TMBR SHARP DRILLING INC - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

FORM 10-K

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

For the fiscal year ended March 31, 2003
or

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

Commission File Number 0-12757

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

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

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

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

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

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

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

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

Yes [X] No [ ]

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

Indicate by check mark whether the Registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2).

Yes [ ] No [X]

The aggregate market value of voting and non-voting common equity held
by nonaffiliates of the Registrant at September 30, 2002 (the last business day
of the Registrant's most recently completed second fiscal quarter) was
approximately $67,604,989 based on the last sale price of the Registrant's
common stock on that date.

At June 10, 2003, 5,496,636 shares of the Registrant's common stock
were outstanding.

TMBR/SHARP DRILLING, INC.

FORM 10-K

TABLE OF CONTENTS

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PART I

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

o fluctuations in prices of oil and gas;

o future capital requirements and availability of
financing;

o risks associated with the drilling of wells;

o competition;

o general economic conditions;

o timing and amount of future production of oil and
natural gas;

o operating costs and other expenses;

o cash flow, anticipated liquidity and prospects for
growth;

o estimates of proved reserves and exploitation and
exploration opportunities; and

o marketing of oil and natural gas.

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

Before investing in our common stock, you should be aware that there
are various risks associated with an investment. Some of these are described
under the Risk Factors section in Part I of this report and in other sections of
this report.

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ITEM 1. BUSINESS

Throughout this report, we refer to some terms that are commonly used
and understood in the oil and gas industry. These terms are: Mcf, Bcf, Bbls and
EBO. Mcf refers to the quantity of one thousand cubic feet of natural gas. Bcf
means one billion cubic feet of natural gas. Bbls means barrels of oil or crude
oil condensate. An EBO is an equivalent barrel of oil, or 6 Mcf of natural gas
for one barrel of oil. MEBO is one thousand equivalent barrels of oil.

ABOUT TMBR/SHARP

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

We provide domestic onshore contract drilling services to major and
independent oil and gas companies. Our operations are focused in the Permian
Basin of west Texas and eastern New Mexico. In addition to our drilling rigs, we
provide the crews and most of the ancillary equipment used in the operation of
our drilling rigs. Rig utilization for the fiscal year ended March 31, 2003 was
approximately 52% compared to 67% for the year ended March 31, 2002.

We own 18 drilling rigs. At June 2, 2003, 11 rigs were operating for
non-affiliated oil producers, and 7 were "stacked" (non-operating). All of our
rigs are operational and actively marketed in the Permian Basin of west Texas
and eastern New Mexico. We market our contract drilling services to both major
oil companies and independent oil producers. The depth capabilities of our rigs
range from 8,500 feet to 30,000 feet.

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

We believe we have established a reputation for reliability, high
quality equipment and well-trained crews. We continually seek to modify and
upgrade our equipment to maximize the performance and capabilities of our
drilling rig fleet, which we believe provides us with a competitive advantage.
We have the capability to design, repair and modify our drilling rig fleet from
our principal support and storage facilities in Midland, Texas, and an
additional storage yard in Odessa, Texas.

Our oil and gas exploration and production operations complement our
onshore drilling operations. These activities are focused in the mature
producing regions in the Permian Basin of west Texas and eastern New Mexico. Oil
and gas operations comprised approximately 18% of our revenues for the fiscal
year ended March 31, 2003.

At March 31, 2003, our total proved oil and gas reserves were estimated
to be:

o 2,868 MBOE of proved developed reserves; and

o 456 MBOE of proved undeveloped reserves.

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At that same date, our total proved reserves were estimated to have an
after tax present value of future net revenues, discounted at 10%, of $37.8
million.

At March 31, 2003, we owned interests in approximately 28,531 gross
(6,107 net) acres of developed oil and gas properties, and approximately 18,596
gross (4,779 net) acres of undeveloped properties.

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

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

We have no material patents, licenses, franchises, or concessions which
we consider significant to our operations.

The nature of our business is such that we do not maintain or require a
"backlog" of products, customer orders or inventory.

Our operations are not subject to renegotiation of profits or
termination of contracts at the election of the federal government.

We have not been a party to any bankruptcy, receivership,
reorganization or similar proceeding.

Sometimes, seasonal conditions affect our business. As an example,
weather conditions can hinder our drilling activities.

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

Our principal executive offices are located at 4607 West Industrial
Blvd., Midland, Texas, 79703 and our telephone number is (915) 699-5050.

AVAILABLE INFORMATION

You may read and copy any materials we file with the SEC at the SEC's
Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may
obtain information on the operation of the Public Reference Room by calling the
SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov)
that contains reports, proxy and information statements, and other information
regarding issuers, including TMBR/Sharp, that file electronically with the SEC.

We have not created a website yet, so electronic copies of our SEC
filings are not available on a website. However, until our website is created,
we will provide electronic or paper copies of our SEC filings free of charge
upon request made to: Patricia R. Elledge, Controller, PRElledge@aol.com,
915-699-5050.

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RECENT DEVELOPMENTS

On May 26, 2003, we entered into an Agreement and Plan of Merger, dated
as of May 26, 2003, with Patterson-UTI Energy, Inc. and Patterson-UTI
Acquisition, LLC, a Texas limited liability company and a wholly owned
subsidiary of Patterson-UTI Energy, Inc. Under terms of the merger agreement,
assuming all of the conditions to the merger are satisfied or waived, we will
merge with and into Patterson-UTI Acquisition, LLC, with Patterson-UTI
Acquisition, LLC being the surviving company.

Subject to the terms and conditions in the merger agreement, each
issued and outstanding share of our common stock not owned directly or
indirectly by Patterson-UTI Energy, Inc. or by us (except shares of common stock
held by persons who object to the merger, and who comply with all of the
provisions of Texas law concerning the right of holders of shares of common
stock to dissent from the merger and require appraisal of their common stock),
will be converted into the right to receive $9.09 in cash and 0.312166 of a
share of common stock, $.01 par value per share, of Patterson-UTI Energy, Inc.
Patterson-UTI Energy, Inc. will pay each holder cash in lieu of any fractional
shares.

Under the terms of the merger agreement, we agreed not to solicit
competing offers, but we may consider and accept an unsolicited offer if our
board of directors determines, after consultation with outside legal counsel,
that the unsolicited offer is superior to the terms of the proposed merger. If
we accept an unsolicited offer, or our board of directors withdraws its
recommendation in light of an unsolicited offer, or our shareholders do not vote
to approve the merger because of an unsolicited offer, we would be required to
pay to Patterson a breakup fee of $3.5 million.

The merger is subject to customary conditions to closing, including
approval by our shareholders, as well as any necessary regulatory filings and
approvals, such as the anti-trust provisions of the Hart-Scott-Rodino Act. There
can be no assurance that the merger will be consummated in accordance with the
terms of the merger agreement, if at all.

As you read this report, it is important to keep in mind that the
information presented, including our financial statements and related
statistical data, does not give effect to the proposed merger.

-6-

DRILLING RIGS

The following table describes the type and depth capabilities of our 18
onshore drilling rigs.

- ---------

*In active operation at June 2, 2003.

Major overhauls, repairs and general maintenance for our drilling rigs
are primarily conducted at our principal support and storage facilities in
Midland, Texas. We emphasize the maintenance and periodic improvement of our
drilling equipment and believe that our rigs are generally in good condition.

DRILLING CONTRACTS

Our drilling contracts are usually obtained through competitive bidding
or as a result of direct negotiations with customers. Drilling contracts
typically obligate us to pay all expenses associated with drilling an oil or gas
well, including wages of drilling personnel, maintenance expenses and incidental
purchases of rig supplies and equipment. The majority of our contracts are
"daywork" contracts with the remainder being "footage" or "turnkey" contracts.
Under a footage contract, we charge an agreed price per foot of hole drilled,
whereas a day-work contract permits us to charge a per diem fixed rate for each
day the rig is in operation. A turnkey contract specifies a total price for
drilling a well plus providing other services, materials or equipment which are
typically the responsibility of the operator under footage or daywork contracts.
Prices for all contracts vary depending on the location, depth, duration,
complexity of the well to be drilled, operating conditions and other factors
peculiar to each proposed well. Under footage and turnkey contracts, we manage
the drilling operation and the type of equipment to be used, subject to certain
customer specifications. We also bear the risk and expense of mechanical
malfunctions,

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equipment shortages, and other delays arising from problems caused in drilling a
well. Daywork contracts permit the operator of the well to manage drilling
operations and to specify the type of equipment to be used. Under daywork
contracts, we generally bear none of the risk due to time delays caused by
unforeseeable circumstances such as stuck or broken drill pipe or blowouts. Of
the 11 rigs working at June 2, 2003, one was subject to a footage contract and
10 were subject to daywork contracts.

Our operations are subject to many hazards, including well blowouts and
fires that could cause personal injury, suspension of drilling operations,
damage to or destruction of equipment and damage to producing formations and
surrounding areas. We believe we are adequately insured for public liability and
damage to the property of others resulting from our operations.

RIG UTILIZATION

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

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(a) Of the total number of rigs owned, one was owned for only a portion of
the fiscal year ended March 31, 2000.

(b) Of the total number of rigs owned, one was owned for only a portion of
the fiscal year ended March 31, 2001. On April 12, 2001, one of our
rigs was destroyed as a result of an explosion, fire and subsequent
blowout.

Additional information about our assets, income and revenues from our
contract drilling and exploration and production business segments can be found
in Note 6 to our financial statements under Item 8 of this report.

-8-

CUSTOMERS

During the fiscal year ended March 31, 2003, we drilled a total of 93
wells for approximately 10 customers. The following table shows certain
information regarding customers for our contract drilling services that
accounted for more than 10% of our total revenues during the last fiscal year.

Depending upon the demand for our drilling rigs and our ability to
attract new customers, the loss of EOG Resources, Inc. or Pure Resources, L.P.
as customers could have a material adverse effect on our financial condition and
results of operation.

COMPETITION

We encounter substantial competition from other drilling contractors in
our contract drilling operations. Our principal market areas in west Texas and
eastern New Mexico are highly fragmented and competitive. Like us, other
companies compete primarily on the basis of contract rates, suitability and
availability of equipment and crews, experience of drilling in certain areas,
and reputation. We believe we compete favorably in these areas. Competition is
primarily on a well-by-well basis and may vary significantly at any particular
time. Drilling rigs can be stacked or moved from one region to another in
response to perceived long-term changes in levels of activity. Based on our
primary areas of activity and the depth of wells we typically drill, we compete
directly with approximately twelve other drilling contractors.

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

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

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EMPLOYEES

At June 2, 2003, we had 53 salaried employees and approximately 287
hourly paid employees. Our employees are not covered by collective bargaining
agreements and we have never experienced a strike or work stoppage. We consider
our employee relations to be satisfactory.

REGULATION

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

Our oil and gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal, state and
local agencies. Failure to comply with these rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases our cost of doing business and affects our profitability. Because
these rules and regulations are frequently amended or reinterpreted, we are
unable to predict the future cost or impact of complying with such laws.

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

Sales of our gas are not regulated and are made at market prices.
However, the Federal Energy Regulatory Commission, or FERC, regulates interstate
and certain intrastate gas transportation rates and service conditions, which
affect our gas marketing efforts, as well as the revenues we receive from sales
of our gas production. Beginning in 1992, the FERC issued Order No. 636 and a
series of related orders that have significantly altered the marketing and
transportation of gas. Order 636 mandated a fundamental restructuring of
interstate pipeline sales and transportation service, including the unbundling
by interstate pipelines of the sales, transportation, storage and other
components of the city-gate sales services such pipelines previously performed.
One of the FERC's purposes in issuing the orders was to increase competition
within all phases of the natural gas industry. Order 636 and subsequent FERC
orders issued in individual pipeline restructuring proceedings have been the
subject of appeals, the results of which have generally upheld Order No. 636.
Generally, Order 636 has eliminated or substantially reduced the interstate
pipelines' traditional role as wholesalers of natural gas, and has substantially
increased competition and volatility in natural gas markets. Although Order No.
636 does not directly regulate our production and marketing activities, it does
affect how buyers and sellers gain access to the necessary transportation
facilities and how we and our competitors sell natural gas in the marketplace.

The sale of oil we produce is not currently regulated and is made at
market prices. Prices we receive from the sale of oil are affected by the cost
of transporting the product to market. Effective as of January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation rates
for interstate common carrier oil pipelines, which, generally, indexed such
rates to inflation. These regulations could increase the cost of transporting
oil by

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interstate pipelines. However, we do not believe that these regulations affect
us any differently than other oil producers, gatherers and marketers.

We are also required to comply with various federal and state
regulations regarding plugging and abandonment of oil and gas wells.

ENVIRONMENTAL

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

The following are examples of some environmental laws that potentially
impact our operations.

Water. The Oil Pollution Act, or OPA, was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act, or FWPCA, and other
statutes as they pertain to prevention of and response to major oil spills. The
OPA subjects owners of facilities to strict, joint and potentially unlimited
liability for removal costs and certain other consequences of an oil spill,
where the spill is into navigable waters, or along shorelines. If an oil spill
into such waters occurs, we could face substantial liabilities. States in which
we operate have also enacted similar laws.

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

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Endangered Species. The Endangerd Species Act, or ESA, seeks to ensure
that activities do not jeopardize endangered or threatened animal, fish and
plant species, nor destroy or modify the critical habitat of such species. Under
the ESA, seismic, exploration and production operations, as well as actions by
federal agencies, may not significantly impair or jeopardize the species of its
habitat. The ESA provides for criminal penalties for willful violations of the
Act. Other statutes provide protection to animal and plant species and may apply
to our operations.

Solid Waste. The federal Resource Conservation and Recovery Act, or
RCRA, and comparable state statutes govern the disposal of "hazardous wastes."
Although the Comprehensive Environmental Response, Compensation, and Liability
Act, also known as the Superfund law, or CERCLA, currently excludes petroleum
from the definition of "hazardous substances," and the RCRA also excludes
certain classes of exploration and production wastes from regulation, such
exemptions by Congress under both CERCLA an RCRA may be deleted, limited or
modified in the future. If such changes are made to CERCLA and/or the RCRA, we
could be required to remove and remediate previously disposed of materials
(including materials disposed of or released by prior owners or operators) from
properties (including ground water contaminated with hydrocarbons) and to
perform removal or remedial actions to prevent future contamination.

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

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

OIL AND GAS OPERATIONS

Our oil and gas operations involve the acquisition, exploration for,
development and production of oil and natural gas. During the fiscal year ended
March 31, 2003, our exploration efforts were conducted in west Texas and eastern
New Mexico.

We actively invest in oil and gas properties for the purpose of
exploration, development and production of oil and gas. We acquire and
participate in exploration activities as a working interest owner along with
other third parties and we usually provide the contract drilling services for
these activities.

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Exploration for oil and natural gas requires substantial expenditures,
especially for exploration in more remote areas. As is customary in the oil and
gas industry, the drilling of oil and gas wells is usually accomplished through
participation with other third parties. One of the parties experienced with
operations in the area is usually designated as the operator of the property and
is responsible for the direct supervision, administration and accounting for
wells drilled and completed under an operating agreement among the parties. We
usually serve as operator of oil and gas properties that we assemble into
drilling prospects and we participate as a non-operating working interest owner
in prospects generated by third parties. As operator, we supervise the drilling
and completion of wells and production from the wells and the further
development of surrounding properties. The operator of a well has significant
control over its location and the timing of its drilling. In addition, the
operator of a well receives fees from other working interest owners as
reimbursement for the general and administrative expenses attendant to the
operation of the wells. The operator will normally receive revenues and pay
expenses equal to more than its ownership interest in the wells, and then must
remit or collect all but its share to or from the other respective participants
in the well. At June 2, 2003 we were serving as operator of 52 wells.

OIL AND GAS RESERVES

Joe C. Neal & Associates, an independent engineering firm, estimated
the total proved reserves attributable to our oil and gas properties to be 1.21
million Bbls of oil and 12.64 Bcf of natural gas as of March 31, 2003. Based on
oil and gas prices at March 31, 2003 and current operating and development
costs, the present value of our pretax future net revenues from our properties,
discounted at 10%, was estimated to be approximately $40.6 million as of March
31, 2003.

In accordance with applicable SEC requirements, estimates of our proved
reserves and future net revenues are made using sales prices and costs,
estimated to be in effect as of the date of such reserve estimates, that are
held constant throughout the life of the properties, except to the extent a
contract specifically provides for escalation. The average realized prices for
our reserves as of March 31, 2003 were $28.93 per Bbl of oil and $4.716 per Mcf
of natural gas.

For additional information concerning our estimated proved oil and gas
reserves, you should read Note (9) to our financial statements. You should refer
to "Item 8 - Financial Statements and Supplementary Data".

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

In general, the volume of production from oil and gas properties
declines as reserves are depleted. Unless we acquire properties containing
proved reserves or conduct successful exploration and development activities, or
both, our proved reserves, and volumes of production will decline as reserves
are produced. Our future oil and gas production is highly dependent upon the
level of success we have in acquiring or finding additional reserves.

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We do not have any oil or gas reserves outside the United States.

No major discovery or other favorable or adverse event has occurred
since March 31, 2003 which is believed to have caused a significant change in
our estimated proved oil and gas reserves.

Our oil and gas reserves and production are not subject to long-term
supply or similar agreements with foreign governments or authorities.

On June 11, 2003, we filed a notice with the Federal Trade Commission
and the Department of Justice pursuant to the Hart-Scott Rodino Antitrust
Improvements Act of 1976, as amended, because of the proposed merger. Exhibits
filed as part of this notice included a summary of a "sale case" model of proved
reserves that we used for internal purposes when we were negotiating the merger
with Patterson. The contents of the filing, including the reserve reports
included in the filing, are confidential and not available to the public. The
estimated proved reserves in the sale case model exceeded the estimated proved
reserves presented in this report by more than five percent, primarily because
of different classifications of certain oil and gas properties and the
application of higher prices per Bbl of oil and Mcf of gas.

PRODUCTIVE WELLS AND ACREAGE

The following tables shows the gross and net productive oil and gas
wells and the gross and not developed and undeveloped acreage in which we owned
a working interest at March 31, 2003. Excluded from the table is acreage in
which our interest is limited to royalty or similar interests.

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

-14-

On September 5, 1995, we entered into a ten-year License Agreement with
the Government of the Republic of Palau and the State of Kayangel which
permitted us to explore for oil and natural gas offshore. The license covered
approximately 1.1 million acres within the waters of Palau. Under the license
agreement, as amended, we were obligated to drill two wells by March, 2002.
However, we never drilled the wells and in 2002 we decided to abandon this
project and impaired approximately $150,000 which represented our costs related
to this leasehold.

DRILLING ACTIVITIES

The following table shows information about the number of gross and net
exploratory and development wells drilled for our account during the periods
indicated.

- ---------

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

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

At June 2, 2003, we were participating in the drilling of 1 gross (.125
net) development well in Lea County, New Mexico.

We own substantially all of the equipment we use in our drilling
operations. Some insignificant items of drilling equipment are leased or rented
as needed because they either cannot be purchased or they are only necessary for
the drilling of certain types of wells located in certain areas.

-15-

PRODUCTION, PRICES AND LIFTING COSTS

The following table shows certain information about our production,
including the volumes of oil and gas we produced, the average sales prices we
received for sales of oil and gas we produced, and the average production
(lifting) cost per EBO.

- ---------

TITLE TO PROPERTIES

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

-16-

MARKETS AND CUSTOMERS

We sell our oil and gas at the wellhead on an "as-produced" basis and
we do not refine petroleum products. Other than normal production facilities, we
do not own an interest in any bulk storage facilities or pipelines. As is
customary in the industry, we sell our production in any one area to relatively
few purchasers, including transmission companies that have pipelines near our
producing wells. Gas purchase contracts are generally on a short-term "spot
market" basis and usually contain provisions by which the prices and delivery
quantities for future deliveries will be determined. For the year ended March
31, 2003, Plains Marketing, L.P. accounted for approximately 25% of our oil and
gas revenues and Navajo Refining Company accounted for approximately 20% of our
oil and gas revenues for such period. The loss of either one of these purchasers
could cease or delay our production and sales if alternative purchasers having
adequate gathering facilities are not found to replace such purchaser's volume
of oil or gas purchased. However, we believe that under present circumstances we
would be able to find other purchasers for our oil and gas production.

RISK FACTORS

In addition to the other information included in this report, the
following risk factors should be considered in evaluating our business and
future prospects. The risk factors described below are not necessarily
exhaustive and you are encouraged to perform your own investigation with respect
to us and our business. We also urge you to read the other information included
in this report, including our financial statements and the related notes.

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

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

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

For the year ended March 31, 2003, we recognized a non-cash impairment
charge of $459,391 related to our oil and gas reserves and unproved properties.
This impairment of oil and gas assets was primarily the result of adjustments of
forecasts and decline curves for certain wells added in prior years and
unsuccessful exploitation efforts to increase production. No assurance can be
given that we will not experience write-downs in the future.

-17-

Part of our business is seasonal in nature.

Weather conditions affect the demand for and prices of natural gas and
can also delay drilling activities, temporarily disrupting our overall business
plans. Demand for natural gas is typically higher during winter months. As a
result, our results of operations may be adversely affected by seasonal
conditions.

We must replace oil and gas reserves that we produce. Failure to
replace reserves may negatively affect our business.

Our future performance depends in part upon our ability to find,
develop and acquire additional oil and gas reserves that are economically
recoverable. Our proved reserves decline as they are depleted and we must locate
and develop or acquire new oil and gas reserves to replace reserves being
depleted by production. No assurance can be given that we will be able to find
and develop or acquire additional reserves on an economical basis. If we cannot
economically replace our reserves, our results of operations may be materially
adversely affected.

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

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

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

o the cost of exploring for, producing and transporting oil and
natural gas;

o the level and price of foreign oil and natural gas imports;

o the discovery rate of new oil and natural gas reserves;

o available pipeline and other oil and natural gas
transportation capacity;

o weather conditions; and

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

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

-18-

We operate in a highly competitive industry, which includes competitors
with greater financial resources.

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

Terrorist activities may adversely affect our business.

Terrorist activities, anti-terrorist efforts and other armed conflict
involving the United States or its interests abroad may adversely affect the
United States and global economies and could prevent us from meeting our
financial and other obligations. The disruption of the financial markets and the
negative impact on the U. S. economy caused by September 11 and other terrorist
events may undermine our efforts and any success we might have in our contract
drilling and exploration and production activities. Although September 11 was
not a direct attack on the domestic oil and gas industry, any similar events in
the future, particularly those directed at the oil and gas industry, could
materially and adversely affect our business, results of operations and
financial condition. If events of this nature occur and persist, the attendant
political instability and societal disruption could reduce overall demand for
oil and natural gas, potentially putting downward pressure on prevailing oil and
natural gas prices and causing a reduction in our revenues. Natural gas and oil
production facilities, transportation systems and storage facilities could be
direct targets of terrorist attacks, and our operations could be adversely
impacted if infrastructure integral to our operations is destroyed or damaged by
such an attack. Costs for insurance and other security may increase as a result
of these threats, and some insurance coverage may become more difficult to
obtain if available at all.

The oil and gas industry is capital intensive and we may not have
sufficient funding for our capital expenditures.

The oil and gas industry is capital intensive. Our cash flow from
operations and the continued availability of credit are subject to a number of
variables, including the number and type of drilling contracts we are able to
obtain, the level of oil and gas we are able to produce from existing wells, the
prices at which oil and gas are sold and our ability to locate and produce new
reserves. We cannot provide any assurance that our cash flow from operations and
present borrowing capacity will be sufficient to fund our anticipated capital
expenditures and working capital requirements. We may from time to time seek
additional financing, either in the form of bank borrowings, sales of securities
or other forms of financing. Except for our loan agreement with our bank lender,
we do not have any agreements for any such financing and there can be no
assurance as to the availability of any such financing. To the extent our
capital resources and earnings are at any time insufficient to fund our
activities or repay any indebtedness when due, we will need to raise additional
funds through public or private financings or additional borrowings. No
assurance can be given as to our ability to obtain any such capital resources.
If we are not at any time able to obtain the necessary capital resources, our
financial condition and results of operations could be materially adversely
affected. If, however, additional funds are raised through the issuance of
equity securities, the percentage ownership of our shareholders at that time
could be diluted and, in addition, such equity securities may have rights,
preferences or privileges senior to those of the common stock.

-19-

There is a shortage of qualified and experienced labor.

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

The reserve data in this report represent estimates only.

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

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

o the timing of production and related expenses

o changes in consumption levels; and

o governmental regulations or taxation.

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

Our contract drilling activities and oil and gas exploration activities are
subject to many inherent risks.

Our oil and gas operations are marked by unprofitable efforts because
of dry holes and wells that do not produce oil or gas in sufficient quantities
to return a profit. The success of our operations depends, in part, upon the
ability of qualified personnel. The cost of drilling, completing and operating
wells is often uncertain. There is no assurance that our oil and gas drilling or

-20-

acquisition activities will be successful, that any production will be obtained,
or that any such production, if obtained, will be profitable.

Our drilling operations and our rig fleet are subject to many hazards
inherent in the onshore drilling industry, such as encountering unusual or
unexpected formations and pressures, blowouts, explosions, cratering, well fires
and spills. These hazards can result in personal injury and loss of life, severe
damage to or destruction of property and equipment, pollution or environmental
damage and suspension of operations. Any one of these potential hazards could
result in accidents, environmental damage, personal injury, property damage and
other harm that could result in substantial liabilities to us. We generally try
to obtain from our customers indemnity agreements requiring them to hold us
harmless if loss of production or reservoir damage occurs. Even when we obtain
contractual indemnification, however, the customer may not maintain adequate
insurance to support such indemnification. If we incur substantial liabilities
from our drilling operations, our results of operations may be materially
adversely affected.

As is customary in the industry, we maintain insurance against some,
but not all, of the hazards and risks we encounter. We maintain general
liability insurance and obtain insurance against blowouts and pollution risks on
a well-by-well basis, but we do not carry insurance against all operating
hazards. No assurance can be given that our insurance or contractual indemnity
protection will be sufficient or effective under all circumstances or against
all hazards to which we may be subject, and our insurance claims will be subject
to retentions and deductibles. The occurrence of a significant event for which
we are not fully insured or indemnified or the failure of a customer to meet its
indemnification obligations could have a material adverse effect on our results
of operations and financial condition. No assurance can be given that we will be
able to maintain insurance in the future at rates that we consider reasonable.

Decreased demand or reduced prices we receive for our contract land
drilling services could materially adversely affect our financial condition.

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

We may incur losses in connection with our footage and turnkey drilling
contracts.

We cannot provide assurance that we will not incur losses on turnkey
and footage drilling contracts. We perform drilling services under our footage
and turnkey drilling contracts which require that we drill a well to a specified
depth for a fixed price. The risks associated with turnkey and footage contracts
are greater than for wells drilled on a daywork basis because turnkey and
footage contracts require us to assume most of the risks associated with
drilling operations that are normally retained by the operator under a daywork
contract, including the risk of blowout, loss of hole, stuck drill string,
machinery breakdowns, abnormal drilling conditions and risks associated with
subcontractors, services, supplies and personnel.

At March 31, 2003, two of our rigs were operating under footage
contracts. None were working under turnkey contracts. Under footage and turnkey
contracts, we do not receive payment unless the well is drilled to the specified
depth, and we must bear the costs of performing drilling services until the well
has been drilled. In addition, profitability of the contract is dependent upon
keeping expenses within the estimates we use in determining the contract price
and completing the contracts on schedule.

-21-

We don't pay dividends on our common stock.

We have never paid dividends on our common stock, and do not intend to
pay cash dividends on the common stock in the foreseeable future. Net income
from our operations, if any, will be used for the development of our business.
Any decision to pay dividends on the common stock in the future will depend upon
our profitability at that time.

We are subject to many restrictions under our bank loan agreement.

As required by our loan agreement with our bank lender, substantially
all of our drilling rigs and related equipment, accounts receivable and
inventory have been pledged as collateral to secure the payment of our loans.
The loan agreement restricts our ability to obtain additional financing, make
investments, lease equipment, sell assets and engage in business combinations.
However, on May 23, 2003, our bank lender consented to the proposed merger with
a subsidiary of Patterson-UTI Energy, Inc. We are also required to comply with
certain financial covenants and maintain certain financial ratios. The loan
agreement also prohibits us from declaring or paying dividends on our common
stock. Although we are currently in compliance with the loan covenants, our
ability to comply in the future with these restrictions and covenants is
uncertain and will be affected by the levels of cash flow from operations and
events or circumstances beyond our control. Failure to comply with any of the
restrictions and covenants under the loan agreement could result in a default
under the loan agreement, resulting in the acceleration of the due dates of any
amounts owed to the bank and the foreclosure by the bank on our pledged assets.

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

Our financial statements for the year ended March 31, 2001 were audited by
Arthur Andersen LLP.

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

ITEM 2. PROPERTIES

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

We also own a 66 acre tract of land in Odessa, Texas, which is
presently being utilized as a secondary storage location. From time to time, we
also store and stack rigs in the field at the rig's last location site.

-22-

We own a warehouse and yard facility situated on approximately 4 acres
in Midland, Texas. This additional storage is used to complement the existing
Midland yard facility. We believe that the support and storage facilities for
our drilling rigs and related equipment are more than adequate for our needs.

ITEM 3. LEGAL PROCEEDINGS

We are a defendant in various lawsuits generally incidental to our
business. We accrue for such items when a liability is both probable and the
amount can be reasonably estimated. We do not believe that the ultimate
resolution of any of our existing lawsuits will have a material effect on our
financial position or results of operations.

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

There were no meetings of our security holders during the fourth
quarter of the fiscal year ended March 31, 2003, and no matters were submitted
to a vote of security holders during such period.

-23-

PART II

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

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

On June 10, 2003, the last reported sale price of our common stock as
reported by NASDAQ was $19.86 per share.

The transfer agent for our common stock is American Stock Transfer &
Trust Company, New York, New York.

On June 10, 2003, the outstanding shares of our common stock were held
of record by approximately 1,900 shareholders.

We have never declared or paid any cash dividends on our common stock
and we have no present intention to pay cash dividends in the future. We
presently intend to retain all earnings to fund our operations and future
growth. Under terms of our loan agreement with our bank lender, we are
prohibited from paying cash dividends on the common stock. See Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources".

At March 31, 2003, a total of 613,500 shares of common stock were
authorized for issuance upon exercise of outstanding stock options. An
additional 276,000 shares remained available for future issuance under our
equity compensation plans. In the table on the following page, certain
information is described about these shares and the equity compensation plans
which provide for their authorization and issuance. To find additional
information about our equity compensation plans, you are urged to read Note 3 to
our financial statements.

-24-

RECENT SALES OF UNREGISTERED SECURITIES

As described in Item 11 of this report under the caption "Compensation
of Directors", TMBR/Sharp has a Directors Fee Stock Plan. Under this plan,
nonemployee directors are entitled to receive 300 shares of TMBR/Sharp common
stock for each Board meeting attended and 100 shares of common stock for
attendance at each meeting of a Board committee. During the fiscal year ended
March 31, 2003, Mr. Fitzgerald received 3,400 shares under this plan; Mr. Cone
received 3,300 shares; Mr. Taylor received 3,000 shares; and Mr. Batchelor
received 2,800 shares. The shares issued were not registered under the
Securities Act of 1933, as amended. Such shares were newly issued and were sold
for services provided by the directors. There were no underwriters involved.
TMBR/Sharp relied upon Section 4(2)of the Securities Act of 1933, as amended,
for exemption of such sale and issuance from the registration requirements of
such Act as transactions not involving a public offering.

EQUITY COMPENSATION PLANS

Equity Compensation Plan Information

(1) During the fiscal year ended March 31, 2003 12,500 shares of our common
stock were issued to nonemployee Directors under TMBR's Directors Fee
Stock Plan, other than upon exercise of options, warrants or rights.
This plan is described in Note (3) of the Financial Statements. The
plan authorizes the issuance of a total of 25,000 shares of common
stock. At March 31, 2003, 6,000 shares of common stock remained
available for future payment of nonemployee Directors' fees.

-25-

ITEM 6. SELECTED FINANCIAL DATA

The following table shows selected financial data for our operations
for each of the five years ended March 31, 2003. This table should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations", and the Financial Statements and related notes
included elsewhere herein.

-26-

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

The following discussion is intended to assist you in understanding our
financial position and results of operations for each year in the three-year
period ended March 31, 2003. you should read the following discussion and
analysis in conjunction with our financial statements and the related notes.

The following discussion contains forward looking statements. For a
description of limitations inherent in forward-looking statements, see
"Cautionary Statement Regarding Forward-Looking Statements" on page 3.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of
operation are based upon financial statements which have been prepared in
accordance with accounting principles generally accepted in the United States of
America, or GAAP. The preparation of these financial statements requires us to
make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses. We have identified below certain of these
policies as being of particular importance to the portrayal of our financial
position and results of operations and which require the application of
significant judgment by our management. We analyze our estimates, including
those related to oil and gas revenues, oil and gas properties, income taxes and
contingencies and litigation, and base our estimates on historical experience
and various other assumptions that we believe to be reasonable under the
circumstances. Actual results may differ from these estimates under different
assumptions or conditions. We believe the following critical accounting policies
affect our more significant judgments and estimates used in the preparation of
our financial statements:

o Revenue Recognition - Contract Drilling Operations. Drilling
revenues from footage and daywork contracts are recognized as
work is performed utilizing the percentage-of-completion
method. Costs under footage and daywork contracts are
recognized in the period they are incurred. Due to the nature
of turnkey contracts and risks therein, we utilize the
completed contract method to recognize drilling revenues and
expenses relating to turnkey contracts. Expected losses on all
in-process contracts are recognized in the period the loss can
reasonably be determined.

o Depreciation - Contract Drilling Operations. Drilling equipment
is depreciated on a units-of-production method based on the
monthly utilization of the equipment. Drilling equipment which
is not utilized during a month is depreciated using a minimum
utilization rate of approximately 25%. Estimated useful lives
range from four to eight years. Other property and equipment is
depreciated using the straight-line method of depreciation
with estimated useful lives of three to seven years.

o Revenue Recognition - Oil and Gas Properties. We follow the
sales method of accounting for oil and natural gas revenues.
Under this method, revenues are recognized based on actual
volumes of oil and natural gas sold to purchasers. No
receivables, payables or unearned revenue are recorded unless
a working interest owner's aggregate sales from the property
exceed its share of the total reserves-in-place.

o Successful Efforts Accounting. We account for our oil and
natural gas operations using the successful efforts method of
accounting. Under this method, all costs

-27-

associated with property acquisition, successful exploratory
wells and all development wells are capitalized. Items charged
to expense generally include geological and geophysical costs,
cost of unsuccessful exploratory wells and oil and natural gas
production costs.

o Proved Reserve Estimates. Estimates of our proved reserves
included in this report are prepared in accordance with GAAP
and SEC guidelines. The accuracy of a reserve estimate is a
function of:

- the quality and quantity of available data;

- the interpretation of that data;

- the accuracy of various mandated economic
assumptions; and

- the judgment of the persons preparing the estimate.

Our proved reserve information included in this report is
based on estimates prepared by Joe C. Neal & Associates.
Estimates prepared by others may be higher or lower than our
estimates.

Because these estimates depend on many assumptions, all of
which may substantially differ from actual results, reserve
estimates may be different from the quantities of oil and
natural gas that are ultimately recovered. In addition,
results of drilling, testing and production after the date of
an estimate may justify material revisions to the estimate.

Our shareholders should not assume that the present value of
future net cash flows is the current market value of our
estimated proved reserves. In accordance with SEC
requirements, we based the estimated discounted future net
cash flows from proved reserves on prices and costs as of the
date of the estimate. Actual future prices and costs may be
materially higher or lower than the prices and costs as of the
date of the estimate.

Our estimates of proved reserves directly impact depletion
expense. If the estimates of proved reserves decline, the rate
of which we record depletion expense increases, reducing net
income. Such a decline may result from property performance or
from lower market prices or increases in costs, which may make
it uneconomic to drill for and produce higher cost fields. In
addition, the decline in proved reserve estimates may impact
the outcome of our assessment of our oil and gas producing
properties for impairment.

o Impairment of Proved Oil and Gas Properties. We review our
proved properties whenever management judges that events or
circumstances indicate that the recorded carrying value of the
properties may not be recoverable. Management assesses whether
or not an impairment provision is necessary based upon
management's outlook of future commodity prices and net cash
flows that may be generated by the properties. Proved oil and
gas properties are reviewed for impairment on a
property-by-property basis, which is the lowest level at which
depletion of proved properties is calculated.

o Impairment of Unproved Oil and Gas Properties. Management
periodically assesses individually significant unproved oil
and gas properties for impairment, on a project-

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by-project basis. Management's assessment of the results of
exploration activities, commodity price outlooks, planned
future sales or expiration of all or a portion of such
projects impact the amount and timing of impairment
provisions.

o Valuation of Deferred Tax Assets. We compute income taxes in
accordance with SFAS No. 109. "Accounting for Income Taxes."
SFAS No. 109 requires an asset and liability approach which
results in the recognition of deferred tax liabilities and
assets for the expected future tax consequences of temporary
differences between the carrying amounts and the tax basis of
those assets and liabilities. SFAS No. 109 also requires the
recording of a valuation allowance if it is more likely then
not that some portion or all of a deferred tax asset will not
be realized.

OVERVIEW

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

The contract drilling industry is currently experiencing a slight
increase in demand and a firming of prices for contract drilling services due to
the recent increase and stability surrounding oil and gas prices. We have been
and will continue to be affected by oil and gas industry conditions but cannot
predict either the future level of demand for our contract drilling services or
future conditions in the contract drilling industry. The contract drilling
industry remains highly competitive. We believe we own a sufficient number of
drilling rigs to remain competitive within our areas of operation. In addition,
we believe we compete favorably with respect to the depth capabilities of our
rigs, the experience level of our personnel, our reputation and our relationship
with existing customers. However, our operating results will continue to be
directly affected by the level of drilling activity in our service areas.

The following table sets forth certain information relating to our
contract drilling operations for the periods indicated:

Oil and Gas Operations. Our oil and gas producing activities are
accounted for using the successful efforts method of accounting. Using this
method, we capitalize all costs incurred to acquire oil and gas properties
(proved and unproved), all development costs, and the costs of successful
exploratory wells. The costs of unsuccessful exploratory wells are expensed.
Geological and geophysical costs, including seismic costs, are charged to
expense when incurred. In cases where we provide contract drilling for oil and
gas properties in which we have an ownership interest, our proportionate share
of costs is capitalized as stated above, net of our working-interest

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share of profits from the related drilling contracts. Capitalized costs of
undeveloped properties, which are not depleted until proved reserves can be
associated with the properties, are periodically reviewed for possible
impairment. Such unevaluated costs totaled approximately $2,196,000 at March 31,
2003 and $1,967,000 at March 31, 2002.

For properties with proved or proved developed oil and gas reserves,
depletion, depreciation and amortization of capitalized costs was calculated for
fiscal 2003, 2002 and 2001 by applying the units-of-production method to the
estimated amount of such reserves.

We recognized non-cash charges of approximately $0.5 million for fiscal
2003; $4.0 million for fiscal 2002; and $1.2 million for fiscal 2001. These
non-cash charges resulted from writedowns of the carrying value of our oil and
gas properties. We assess the need for an impairment of capitalized costs of oil
and gas properties on a property-by-property basis. If an impairment is
indicated based on undiscounted future cash flows, then it is recognized to the
extent that net capitalized costs exceed discounted future cash flows. Many
assumptions are required for the impairment assessment when impairment
indicators are present, including future prices and expenses, production volumes
and drilling results. Changes in these assumptions could have a significant
impact on whether specific oil and gas properties fail the impairment test.
Prices used for the impairment analysis at March 31, 2003 were $28.93 per Bbl
and $4.716 per Mcf. Future impairment expense may be required on current
properties if we change our pricing or cost assumptions in the future or if
estimated future recoverable reserves decline.

The following table shows certain information relating to our oil and
gas operations for the periods indicated:

We have never entered into hedging arrangements and do not have any
delivery commitments. While hedging arrangements reduce exposure to losses
resulting from unfavorable price changes, they also limit the ability to benefit
from favorable market price changes.

RESULTS OF OPERATIONS

COMPARISON OF YEAR ENDED MARCH 31, 2003 TO YEAR ENDED MARCH 31, 2002

Contract drilling revenues for fiscal 2003 decreased by 33% from fiscal
2002. Rig utilization rates in fiscal 2003 were 53%, as compared to 67% in
fiscal 2002. The decrease in contract drilling revenues was due to the decrease
in utilization and an approximate 14% decrease in the average prices received
for contract drilling services. Rig utilization in our operating market is
difficult to project because of wide fluctuations in drilling activity. In
addition, the number of rigs industry wide that are actually available for work
cannot be accurately determined.

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Contract drilling expenses were 69% of contract drilling revenues in
fiscal 2003 while in fiscal 2002 contract drilling expenses were 57% of contract
drilling revenues. The percentage increase in contract drilling expenses was
primarily due to the decrease in drilling revenues.

Oil and gas revenues increased by approximately 25% when comparing
fiscal 2003 to fiscal 2002. Quantities of oil and natural gas produced (on an
equivalent barrel of oil basis) increased by approximately 26%, while average
sales prices of crude oil and natural gas (on an equivalent barrel of oil basis)
increased by approximately 1%. The following table shows certain information
relating to our oil and gas revenues:

Oil and gas production expenses increased approximately 12%, primarily
the result of an increase in production taxes.

We participated as a working-interest owner in the drilling of 21 gross
(5.96 net) wells during fiscal 2003, one of which was a dry hole. In fiscal
2002, we participated as a working-interest owner in the drilling of 13 gross
(4.00 net) wells, three of which were dry holes.

General and administrative expenses increased approximately 56%. This
increase is primarily due to an increase in insurance, ad valorem and franchise
tax expenses.

Depreciation, depletion and amortization expenses increased by
approximately 3%. This increase can be attributed to an increase in the
quantities of oil and gas produced as oil and gas properties are depleted using
the units-of-production method.

We recognized a non-cash charge of $0.5 million in fiscal 2003 and a
non-cash charge of $4.0 million in fiscal 2002 related to the writedown of the
carrying value of our oil and gas properties.

Net working capital was $9.3 million at March 31, 2003, as compared to
$9.1 million at March 31, 2002.

COMPARISON OF YEAR ENDED MARCH 31, 2002 TO YEAR ENDED MARCH 31, 2001

Contract drilling revenues for fiscal 2002 increased by 30% over
contract drilling revenues for fiscal 2001. Our rig utilization rate in fiscal
2002 was 67% and our rig utilization rate for 2001 was 68%. The increase in
contract drilling revenues was due to an increase in the average prices we
received for our contract drilling services.

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

Our oil and gas revenues remained relatively flat when comparing fiscal
2002 to and 2001. Although quantities of oil and gas produced (on an equivalent
barrel of oil basis) increased by approximately 36%, oil and gas revenues for
fiscal 2002 were negatively affected by a decrease in prices we received for oil
and natural gas. The following table shows certain information relating to our
oil and gas revenues:

Oil and gas production expenses increased by 26%, which was the result
of start up expenses for new wells coming on line, coupled with an increase in
the number of producing properties. Also, we experienced a general rise in the
cost of services and supplies which were included in production expenses.

We participated as a working-interest owner in the drilling of 13 gross
(4.00 net) wells during fiscal 2002, three of which were dry holes. In fiscal
2001, we participated as a working-interest owner in the drilling of 21 gross
(6.91 net) wells, nine of which were dry holes.

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

General and administrative expenses increased approximately 56%. The
increase was the result of an increase in payroll and insurance expenses.

We recognized non-cash charges of $4.0 million in fiscal 2002 and $1.2
million in fiscal 2001, in each case related to the writedown of the carrying
value of our oil and gas properties.

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

INCOME TAXES

At March 31, 2003, we had approximately $33.0 million of unused net
operating loss, or NOL, carryforwards for tax purposes. Use of these NOL
carryforwards is dependent upon our ability to generate taxable earnings in
future periods. These carryforwards began to expire in fiscal 2000 and
approximately $10.3 million expired in 2003. Our ability to utilize NOL
carryforwards may be substantially limited in the future under the Internal
Revenue Code of 1986. If we experience an ownership change under applicable
provisions of the Internal Revenue Code, the carryforward would be limited to an
annual amount determined by specified interest rates and other variables. We
estimate that we will be able to utilize approximately $3.9 million of NOL
carryforwards in 2003 to reduce taxable income. As of March 31, 2003, we do not
believe an ownership change has occurred. However, if the merger with Patterson
is completed, we believe that a change of control would occur and utilization of
future NOL carryforwards would be limited.

The effective tax rates for fiscal 2003 and 2002 differ from the
statutory tax rate of 34% primarily due to the utilization of NOLs. The tax
benefit recorded in 2003 results primarily from the reversal of valuation
allowance discussed below.

We utilize an asset and liability approach for financial accounting and
reporting for income taxes. We have a deferred tax asset primarily due to our
NOL carryforwards.

We assess the need for a valuation allowance against our deferred tax
assets based on whether we believe that it is more likely than not that the
deferred tax asset is realizable. As of March 31, 2002, we fully reserved our
deferred tax asset as we determined that realizability of any portion of the
deferred tax asset was not more likely than not. Realization of the deferred tax
asset requires us to generate future taxable income. During 2003, after
considering increases in commodity prices, recent utilization of operating loss
carryforwards to reduce taxable income, and the anticipated expiration of NOL
carryforwards, we determined that it was more likely than not that a portion of
the deferred tax assets was realizable. Accordingly, a benefit of approximately
$6.8 million was recognized during 2003 as the valuation allowance was reduced.
In addition, during 2003 the valuation allowance was reduced through the
utilization of NOL carryforwards to reduce taxable income as well as the
expiration of unused NOL carryforwards.

WORKERS COMPENSATION

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

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Cash flow provided by operations was $12.8 million, $20.9 million and
$11.9 million in fiscal 2003, 2002 and 2001, respectively. The decrease from
fiscal 2002 to 2003 was primarily the result of lower income before taxes in
2003 compared to 2002. Net income in fiscal 2003 included a non-cash deferred
tax benefit of $6.8 million. The increase from fiscal 2001 to 2002 was primarily
working capital changes due to timing of cash collections and payments.

Cash required by investing activities was $12.2 million, $18.3 million
and $11.9 million, in fiscal 2003, 2002 and 2001, respectively. Cash flow
required by investing activities in all years was primarily for additions to
property and equipment.

Cash provided (required) by financing activities was $.5 million, $.2
million and ($.7) million in fiscal 2003, 2002 and 2001, respectively. Uses of
cash included repayment of bank borrowings of $1.1 million and $1.2 million in
fiscal 2002 and 2001, respectively. Sources of cash included proceeds from
exercise of stock options and sale of common stock of $.7 million, $1.4 million
and $.5 million in fiscal 2003, 2002 and 2001, respectively.

In June, 2000, we entered into a second amended and restated loan
agreement with Wells Fargo Bank Texas, N.A. The loan agreement provides for a
$5.0 million revolving line of credit facility, of which $5.0 million was
available at March 31, 2003. The facility is secured by our drilling rigs and
related equipment, accounts receivable and inventory. Borrowings under the
revolving facility bear interest at an annual rate equal to the bank's base
rate, or 4.25% at March 31, 2003. Accrued and unpaid interest on outstanding
principal is payable monthly. The loan facility matures on August 31, 2004, at
which time all outstanding principal and accrued and unpaid interest will be due
and payable in full. At March 31, 2003, no amounts were outstanding under the
loan facility. The principal amount outstanding at any one time may not exceed
the lesser of $5.0 million or one-third of the borrowing base amount. The
borrowing base amount is the sum of the Company's accounts receivable and the
value of its inventory, drilling rigs, drill pipe and related equipment. We
redetermine the borrowing base quarterly, but the bank may, in its discretion,
make its own determination of the borrowing base which will be the controlling
borrowing base amount. At March 31, 2003, the borrowing base amount was
approximately $39.6 million.

In addition to certain customary affirmative covenants, the loan
agreement contains covenants which restrict us from:

o incurring additional debt, incurring or permitting
liens to exist on any of our property, assets or
revenues;

o declaring or paying dividends or other distributions
on our stock (or acquiring any of our stock);

o issuing stock;

o entering into transactions with affiliates;

o disposing of assets; and

o undertaking certain other types of transactions.

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The loan agreement also contains financial covenants which we must be in
compliance with at the end of each fiscal quarter. These requirements include
having a tangible net worth of $9.0 million; a current ratio of .80 to 1.00; an
interest expense coverage ratio of 3.0 to 1.0; and a debt to worth ratio of 1.0
to 1.0.

If the merger with Patterson is not completed, we anticipate that
sufficient funds for our capital expenditures in fiscal 2004 will be available
from a combination of sources, including:

o borrowings under our line of credit;

o funds raised through issuances of equity or debt
securities in public or private transactions; and

o internally generated funds.

The following table shows information regarding capital expenditures we
made during the last three fiscal years.