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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-K/A þ
    
    Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934For the Fiscal Year Ended December 31, 2003o
    
    Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
 Commission file number 1-8226 (GREY WOLF, INC. LOGO) GREY WOLF, INC.  Texas
(State or other jurisdiction of
incorporation or organization)
    
    74-2144774
(I.R.S. Employer
Identification Number)
 10370 Richmond Avenue, Suite 600
Houston, Texas
(Address of principal executive offices)
    
    77042
(Zip Code)
 Registrants telephone number, including area code: 713-435-6100 Securities registered pursuant to Section 12(b) of the Act: Title of each class
    
    Name of each exchange
on which registeredCommon Stock, Par Value $0.10
Rights to Purchase Junior Participating
Preferred Stock, Par Value $1.00
    
    American Stock Exchange
American Stock Exchange
 Securities registered pursuant to Section 12(g) of the Act: None 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 þ No o Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (229.405 under the Securities Exchange Act of 1934) 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.
þ At February 10, 2004, 181,437,431 shares of the Registrants common stock
were outstanding. The aggregate market value of the Registrants voting stock
held by non-affiliates (based upon the closing price on the American Stock
Exchange on February 10, 2004 of $4.25) was approximately $718.6 million. Indicate by a check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act) Yes þ No o. The following documents have been incorporated by reference into the Parts
of this Report indicated: Certain sections of the Registrants definitive
proxy statement for the Registrants 2004 Annual Meeting of shareholders which
is to be filed pursuant to Regulation 14A under the Securities Exchange Act of
1934 within 120 days of the Registrants fiscal year ended December 31, 2003,
are incorporated by reference into Part III hereof.




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PART I ITEM 1. BUSINESS General Grey Wolf, Inc., a Texas corporation formed in 1980, is a leading provider
of contract land drilling services in the United States. Our customers include
independent producers and major oil and gas companies. We conduct all of our
operations through our subsidiaries. Our principal office is located at 10370
Richmond Avenue, Suite 600, Houston, Texas 77042, and our telephone number is
(713) 435-6100. Our website address is www.gwdrilling.com. 
 We make available free of charge through our website our annual reports on
Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all
amendments to those reports as soon as reasonably practicable after such
material is electronically filed with the Securities and Exchange Commission.
Information on our website is not a part of this report. 
 Business Strategy Within the framework of a very cyclical industry, our strategy is to
maximize shareholder value during each phase of an industry cycle. To achieve
that strategy, we seek to enter each phase of our industrys cycles in a
stronger position by:  
    
    delivering quality, value-added service to our customers;
    
    maintaining a leading position in certain markets where we operate;
    
    responding to market conditions by balancing dayrates we
receive on our rigs with the number of rigs we market;
    
    maintaining a high level of utilization for our marketed rigs;
    
    enhancing cash flow through our turnkey and trucking operations and use of our top drives;
    
    controlling costs and exercising capital spending discipline;
    
    maintaining a premium fleet of equipment with a bias toward deep drilling for natural gas;
    
    using term contracts to provide sufficient cash flow to cover
incremental capital expenditures for refurbishments on rigs under
term contracts;
    
    using term contracts to mitigate the cyclical nature of
dayrates;
    
    searching for new market opportunities where we believe our
quality fleet of rigs would be able to generate attractive returns;
and
    
    searching for potential acquisition candidates that we
believe would be accretive. Industry Overview At the peak of the last up cycle in July 2001, there were 1,136 land rigs
working in the United States according to the Baker Hughes rotary rig count.
That number fell to 628 in April of 2002, we believe due to lower commodity
prices. From April 2002 through December 2002, commodity prices generally
improved and we saw a stabilization of the domestic land rig count at an
average of 710 rigs. From the end of 2002 through the end of January 2004, the
average closing price for natural gas, based upon the NYMEX near month contract
was $5.52 per mmbtu, while the average NYMEX near month contract price of West
Texas Intermediate Crude was $31.16 per barrel. During this time period, the
closing prices did not fall below $4.43 per mmbtu and $25.24 per barrel for
natural gas and West Texas Intermediate Crude, respectively. Over this same
period of time, the number of land rigs working domestically increased to 988. Current Conditions and Outlook The last up cycle in our industry, which began in the second half of 1999
and continued through the third quarter of 2001, was marked by rapidly
increasing dayrates, significant backlog and reactivation of rigs from
cold-stacked status and inventory. Dayrates began increasing when the U.S.
land rig count reached approximately 600 rigs on the Baker Hughes rotary rig
count and continued to rise until roughly mid-2001. Backlog, in the form of
signed contracts and non-binding oral commitments from customers, generally
extended beyond six months and through the use of term contracts extended up to
two years. -2-




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Although the domestic land rig count has increased from 628 in April 2002
to 988 at the end of January 2004, we believe that the current cycle of
increasing rig count differs from the last in that, to date, dayrates have
increased only slightly and we believe backlog has yet to build to levels seen
in 2001. We believe there are a number of factors that contribute to the
overall lack of intensity in the current up cycle. First, the expansion of the land rig fleet in the last up cycle means
there are more rigs available to meet the demand in this cycle with little or
no additional capital expenditure. It is estimated that rigs refurbished and
reactivated in the last up cycle added between 120 and 150 rigs to the market
that are capable of working in this cycle. In addition, new-build rig programs
have added between 50 and 60 additional rigs to the market over the last two
years. Second, the customer base that accounts for the largest portion of working
land rigs consists of independent producers of oil and gas. We believe that
this customer group has, in general, changed its management focus from rapid
oil and gas reserve expansion through drilling and acquisition to overall
financial health measured by balance sheet strength and adequate returns on
capital employed. Under the old focus, we believe that during periods when
commodity prices were high, these customers generally applied the greatest
portion of available cash to increase reserves. Today, we believe that
drilling prospects compete with debt reduction, producing property
acquisitions, and stock buybacks for available cash. Third, we believe the nature of the competitive environment is different.
Competition in this up cycle has focused on market share rather than obtaining
higher dayrates, which received much stronger emphasis in the last up cycle. 
 Finally, a general lack of deep drilling has become evident in this up
cycle, leaving high horsepower premium rigs idle or under utilized. The number
of wells drilled by the top 15 operators to depths greater than 10,000 feet has
declined approximately 30% from the peak in 2001 to the present. Also, today
there are approximately 50 fewer rigs drilling wells to target depths of 15,000
feet or deeper than were drilling at the peak of the last up cycle. This
failure of the deep drilling segment of the market to rebound as quickly as in
the past is reflected not only in the number of rigs working but also in lower
average dayrates. Rigs drilling deeper wells typically command higher
dayrates. 
 We believe we are in a solid position to benefit from an increase in
drilling activity which we believe could develop in 2004. We continue to
maintain our premium fleet of equipment and retain our experienced personnel
which are essential to providing quality service to our customers and returning
our rigs to work when market conditions improve. 
 During each quarter in 2003, we averaged between 59 and 62 rigs working
and have averaged 63 rigs working in the first quarter of 2004 through February
10, 2004. We have, however, seen an increase in the amount of future work for
our rigs currently operating as well as an increase in the dayrates we are
currently bidding for our rigs. This future work is in the form of signed
contracts and non-binding oral commitments from our customers. 
 Operations 
 At February 10, 2004, we had a rig fleet of 117 rigs, 80 of which were
marketed, 22 cold-stacked and 15 held for future refurbishment. Cold-stacked
rigs are rigs that are stacked without crews, are not currently being marketed
and do not require substantial investment to be returned to service. At
February 10, 2004, we estimated that our cold-stacked rigs could be returned to
service for an aggregate of approximately $2.5 million to $3.0 million. We
currently conduct our operations in the following domestic drilling markets: 
  
    
    Ark-La-Tex;
    
    Gulf Coast;
    
    Mississippi/Alabama;
    
    South Texas;
    
    Rocky Mountain; and
    
    West Texas. -3-




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We conduct our operations primarily in domestic markets which we believe
have historically had greater utilization rates and dayrates than the combined
total of all other domestic markets. This is in part due to the heavy
concentration of natural gas reserves in these markets. During 2003,
approximately 98% of the wells we drilled for our customers were drilled in
search of natural gas. Larger natural gas reserves are typically found in
deeper geological formations and generally require premium equipment and
quality crews to drill the wells. 
 Ark-La-Tex Division. Our Ark-La-Tex division provides drilling services
primarily in Northeast Texas, Northern Louisiana and Southern Arkansas, and the
Mississippi/Alabama market. At February 10, 2004, we had 19 marketed rigs in
this division which consisted of 11 diesel electric rigs and eight mechanical
rigs. Our Ark-La-Tex division also operates a fleet of trucks which is used
exclusively to move our rigs. The Ark-La-Tex division also manages the
operations of our Rocky Mountain and West Texas districts. 
 
 We had an average of 14 rigs working in our Ark-La-Tex division during
2003. Daywork contracts generated approximately 84% of our revenues, while
turnkey and footage contracts generated the remaining 16% of our revenues. The
average revenue per rig day worked by the division during 2003 was $10,438. 
 
 Gulf
Coast Division. Our Gulf Coast division provides drilling services
in Southern Louisiana and along the upper Texas Gulf Coast. At February 10,
2004, we had 21 marketed rigs in this division which consist of 18 diesel
electric rigs and three mechanical rigs. 
 
 We had an average of 18 rigs working in our Gulf Coast division during
2003. Daywork contracts generated approximately 40% of our revenues, while
turnkey and footage contracts generated the remaining 60% of our revenues. The
average revenue per rig day worked by the division during 2003 was $16,002. 
 
 South
Texas Division. At February 10, 2004, we had 30 marketed rigs in
this division. The marketed rigs consisted of 15 diesel electric rigs, ten
trailer-mounted rigs, one of which was diesel electric, and five mechanical
rigs. The South Texas division also operates a fleet of trucks which is used
exclusively to move our rigs. 
 
 We had an average of 22 rigs working in our South Texas division during
2003. Daywork contracts generated approximately 63% of our revenues and, while
turnkey and footage contracts generated the remaining 37% of our revenues. The
average revenue per rig day worked by the division during 2003 was $12,241. 
 
 Rocky Mountain District. Our Rocky Mountain district provides drilling
services in the market area which consists of Wyoming, Colorado, northwest Utah
and northern New Mexico. We began operations in the Rocky Mountain market in
June 2001 and at February 10, 2004, had four marketed rigs in this district.
Two of these rigs were 3,000 horsepower or larger diesel electric rigs while
the other two rigs were diesel electric 1,500 horsepower rigs. Daywork
contracts generated 100% of the revenue and contract drilling operating
expenses in this market area and the average revenue per rig day worked in the
district during 2003 was $13,206. We had three rigs working in this district
at February 10, 2004. We continue to look for opportunities to expand our
market presence in this area. 
 
 West Texas District. Our West Texas district provides drilling services
in West Texas and Southeast New Mexico. We began operations in West Texas in
October 2001. Since that time, we have increased the number of marketed rigs
in this district to six diesel electric rigs at February 10, 2004. During
2003, we averaged five rigs working under daywork contracts, with an average
revenue per rig day worked of $9,856. 
 Cold Stacked Rigs and Rigs Held for Refurbishment 
 At February 10, 2004, we had the ability to return all 22 then
cold-stacked rigs to work at an estimated aggregate cost of $2.5 million to
$3.0 million, which would have brought our marketed fleet to 102 rigs at that
date. In addition, at February 10, 2004, we had 15 rigs held for future
refurbishment that could be returned to service for an average of approximately
$5.0 million per rig, excluding drill pipe and drill collars. The actual
number of rigs reactivated in 2004, if any, and in the future will depend upon
many factors, including our estimation of existing and anticipated demand and
dayrates, our success in bidding for domestic contracts, including
term contracts, and the timing of the reactivations. The actual cost of reactivating
these rigs would also depend upon the specific customer requirements and to the
extent that we choose to upgrade these rigs. 
 -4-




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Contracts Our contracts for drilling oil and natural gas wells are obtained either
through competitive bidding or as a result of negotiations with customers.
Contract terms offered by us are generally dependent on the complexity and risk
of operations, on-site drilling conditions, type of equipment used and the
anticipated duration of the work to be performed. Generally, drilling
contracts are for a single well. The majority of our drilling contracts are
typically subject to termination by the customer on short notice with little or
no penalty. Our drilling contracts generally provide for compensation on
either a daywork, turnkey or footage basis. Daywork Contracts. Under daywork drilling contracts, we provide a
drilling rig with required personnel to our customer who supervises the
drilling of the well. We are paid based on a fixed rate per day while the rig
is utilized. Daywork drilling contracts specify the equipment to be used, the
size of the hole and the depth of the well. Under a daywork drilling contract,
the customer bears a large portion of out-of-pocket costs of drilling. The
dayrate we receive is not dependent on the usual risks associated with
drilling, such as time delays for various reasons, including stuck drill pipe
or blowouts. 
 We sometimes enter into term contracts to provide drilling services on a
daywork basis. Typically, the length of our term contracts have ranged from
six months to two years. They have usually included a per rig day termination
rate approximately equal to the dayrate under the contract less estimated
contract drilling operating expenses. We seek term contracts with our
customers when we believe that those contracts may mitigate the financial
impact to us of a decline in dayrates during the period in which the term
contract is in effect. During late 2001 and 2002, the use of term contracts
enabled us to maintain dayrates that proved to be higher than was attainable
during 2002 and 2003. We also have used term contracts to contractually assure
that we receive sufficient cash flow to recover the costs of improvements we
make to the rigs under the term contract, particularly when those improvements
are requested by the customer. 
 
 Turnkey Contracts. Under a turnkey contract, we contract to drill a well
to an agreed upon depth under specified conditions for a fixed price,
regardless of the time required or the problems encountered in drilling the
well. We provide technical expertise and engineering services, as well as most
of the materials required for the well, and are compensated when the contract
terms have been satisfied. Turnkey contracts afford an opportunity to earn a
greater financial result than would normally be available on daywork or footage
contracts if the contract can be completed without complications. 
 The risks to us under a turnkey contract are substantially greater than on
a daywork basis because we assume most of the risks associated with drilling
operations generally assumed by the operator in a daywork contract, including
the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns,
abnormal drilling conditions and risks associated with subcontractors
services, supplies, cost escalation and personnel. We employ or contract for
engineering expertise to analyze seismic, geologic and drilling data to
identify and reduce many of the drilling risks assumed by us. We use the
results of this analysis to evaluate the risks of a proposed contract and seek
to account for such risks in our bid preparation. We believe that our
operating experience, qualified drilling personnel, risk management program,
internal engineering expertise and access to proficient third party engineering
contractors have allowed us to reduce the risks inherent in turnkey drilling
operations. We also maintain insurance coverage against some but not all
drilling hazards. Footage Contracts. Under footage contracts, we are paid a fixed amount
for each foot drilled, regardless of the time required or certain problems
encountered in drilling the well. We typically pay more of the out-of-pocket
costs associated with footage contracts than under daywork contracts. Similar
to a turnkey contract, the risks to us on a footage contract are greater than
under a daywork contract because we assume some of the risks associated with
drilling operations generally assumed by the operator in a daywork contract,
including the risk of blowout, loss of hole, stuck drill pipe, machinery
breakdowns, and risks associated with subcontractors services, supplies, cost
escalation and personnel. Generally, the overall risk we assume is not as
great as under turnkey contracts. As with turnkey contracts, we manage
additional risk through the use of engineering expertise and bid the footage
contracts accordingly. We also maintain insurance coverage against certain
drilling hazards. -5-




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Customers and Marketing Our contract drilling customers include independent producers and major
oil and gas companies. In 2003, 35% of our revenue came from major oil and gas
companies and large independent producers, while the remaining 65% came from
other independents. For the year ended December 31, 2003, no individual
customer accounted for more than 10% of our revenues. We primarily market our
drilling rigs on a regional basis through employee sales representatives.
These sales representatives utilize personal contacts and industry periodicals
and publications to determine which operators are planning to drill oil and
natural gas wells in the immediate future. Once we have been placed on the
bid list for an operator, we will typically be given the opportunity to bid
on all future wells for that operator in the area. From time to time we also enter into informal, nonbinding commitments with
our customers to provide drilling rigs for future periods at agreed upon rates
plus fuel and mobilization charges, if applicable, and escalation provisions.
This practice is customary in the land drilling business during times of
increasing rig demand. Although neither we nor the customer are legally
required to honor these commitments, we generally satisfy such commitments in
order to maintain good customer relations. Insurance 
 Our operations are subject to the many hazards inherent in the drilling
business, including, for example, blowouts, cratering, fires, explosions and
adverse weather. These hazards could cause personal injury, death, suspend
drilling operations or seriously damage or destroy the equipment involved and
could cause substantial damage to producing formations and surrounding areas.
Damage to the environment could also result from our operations, particularly
through oil spillage and extensive, uncontrolled fires. As a protection
against operating hazards, we maintain insurance coverage, including
comprehensive general liability, workers compensation insurance, property
casualty insurance on our rigs and drilling equipment, and control of well
insurance. In addition, we have commercial excess liability insurance, to
cover general liability, auto liability and workers compensation claims which
are higher than the maximum coverage provided under those policies. The table
below and the discussion that follows highlights these coverages as of February
10, 2004. 
 Deductible/Limit
    
    Aggregate
    
    Self-Insured RetentionCoverage
    
    per Occurrence
    
    Limit
    
    per OccurrenceWorkers compensation/
Employer liability
    
    Statutory(1)/$1.0 million
    
    None
    
    
    $350,000Automobile liability
    
    $1.0 million
    
    None
    
    
    $350,000Commercial general liability
    
    $1.0 million
    
    $2.0 million
    
    
    $250,000Commercial excess liability
    
    $10.0 million
    
    $10.0 million
    
    Underlying insuranceCommercial excess liability
    
    $65.0 million
    
    $65.0 million
    
    Underlying insurance
   (1)
    
    Workers compensation policy limits vary depending on the laws of the
particular states in which we operate. Our property casualty insurance coverage for damage to our rigs and
drilling equipment is based on our estimate of the cost of comparable used
equipment to replace the insured property. There is a $125,000 maintenance
deductible per occurrence for losses on our rigs. In addition, there is a
deductible of $850,000 in the
aggregate over the policy period, exclusive of the maintenance deductible.
There is a $25,000 deductible per occurrence on other equipment. We do not
have insurance coverage against loss of earnings resulting from damage to our
rigs. 
 We also maintain insurance coverage to protect against certain hazards
inherent in our turnkey and footage contract drilling operations. This
insurance covers control of well (including blowouts above and below the
surface), cratering, seepage and pollution and care, custody and control. Our
insurance provided $3.0 million coverage per occurrence for care, custody and
control, and coverage per occurrence for control of well, cratering, seepage
and pollution associated with drilling operations of either $10.0 million or
$20.0 million, depending upon the area in which the well is drilled and its
target depth. Each form of coverage provides for a deductible that we 
 -6-




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must
meet, as well as a maximum limit of liability. Each casualty is an occurrence,
and there may be more than one such occurrence on a well, each of which would
be subject to a separate deductible. 
 No assurances can be given that we will be able to maintain the
above-mentioned insurance types and/or the amounts of coverage that we believe
to be adequate. Also, there are no assurances that these types of coverages
will be available in the future. Our insurance may not be sufficient to
protect us against liability for all consequences of well disasters, extensive
fire damage, damage to the environment, damage to producing formations or other
hazards. The rising cost and/or availability of certain types of insurance
could have an adverse effect on our financial condition and results of
operations. 
 Environmental Regulations 
 
 Our operations are subject to stringent federal, state and local laws and
regulations governing protection of the environment. These laws and
regulations may require acquisition of permits before drilling commences and
may restrict the types, quantities and concentrations of various substances
that can be released into the environment. Planning and implementation of
protective measures are required to prevent accidental discharges. Spills of
oil, natural gas liquids, drilling fluids, and other substances may subject us
to penalties and cleanup requirements. Handling, storage and disposal of both
hazardous and non-hazardous wastes are subject to regulatory requirements. 
 
 The federal Clean Water Act, as amended by the Oil Pollution Act, the
federal Clean Air Act, the federal Resource Conservation and Recovery Act, and
their state counterparts, are the primary vehicles for imposition of such
requirements and for civil, criminal and administrative penalties and other
sanctions for violation of their requirements. In addition, the federal
Comprehensive Environmental Response Compensation and Liability Act and similar
state statutes impose strict liability, without regard to fault or the legality
of the original conduct, on certain classes of persons who are considered
responsible for the release of hazardous substances into the environment. Such
liability, which may be imposed for the conduct of others and for conditions
others have caused, includes the cost of remedial action as well as damages to
natural resources. 
 
 Environmental laws and regulations are complex and subject to frequent
change that may result in more stringent and costly requirements. Compliance
with applicable requirements has not, to date, had a material affect on the
cost of our operations, earnings or competitive position. However, compliance
with amended, new or more stringent requirements, stricter interpretations of
existing requirements, or the discovery of contamination may cause us to incur
additional costs or subject us to liabilities that may have a material adverse
effect on our results of operations and financial condition. 
 
 Our business depends on the demand for services from the oil and gas
exploration and development industry, and therefore our business can be
affected by political developments and changes in laws and regulations that
control or curtail drilling for oil and gas for economic, environmental or
other policy reasons. 
 Certain Risks 
 Below we describe the risks and uncertainties that we believe were
material to our business as of February 10, 2004. 
 A material or extended decline in expenditures by the oil and gas industry, due
to a decline or volatility in oil and gas prices, a decrease in demand for oil
and gas or other factors, would reduce our revenue and income. As a supplier of land drilling services, our business depends on the level
of drilling activity by oil and gas exploration and production companies
operating in the geographic markets where we operate. The number of wells they
choose to drill is strongly influenced by past trends in oil and natural gas
prices, current prices and their outlook for future prices. Low oil and natural
gas prices, or the perception among oil and gas companies that prices are
likely to decline, can materially and adversely affect us in many ways,
including:  
    
    our revenues, cash flows and earnings;
    
    the fair market value of our rig fleet, which in turn could
trigger a writedown of the carrying value of these assets for
accounting purposes;
    
    our ability to maintain or increase our borrowing capacity;
    
    our ability to obtain additional capital to finance our
business and make acquisitions, and the cost of that capital; and -7-




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
    
    our ability to retain skilled rig personnel who we would need
in the event of an increase in the demand for our services. Depending on the market prices of oil and natural gas, oil and gas
exploration and production companies may cancel or curtail their drilling
programs, thereby reducing demand for our services. Even during periods when
prices for oil and natural gas are high, companies exploring for oil and
natural gas may cancel or curtail their drilling programs for a variety of
other reasons beyond our control. Any reduction in the demand for drilling
services may materially erode dayrates, the prices we receive for our turnkey
drilling services and the utilization rates for our rigs, any of which could
adversely affect our financial results. Oil and natural gas prices have been
volatile historically and, we believe, will continue to be so in the future.
Many factors beyond our control affect oil and natural gas prices, including:  
    
    weather conditions in the United States and elsewhere;
    
    economic conditions in the United States and elsewhere;
    
    actions by OPEC, the Organization of Petroleum Exporting Countries;
    
    political instability in the Middle East, Venezuela and other major producing regions;
    
    governmental regulations, both domestic and foreign;
    
    the pace adopted by foreign governments for exploration of their national reserves; and
    
    the overall supply and demand for oil and natural gas. An economic downturn may adversely affect our business. An economic downturn may cause reduced demand for petroleum-based products
and natural gas. In addition, many oil and natural gas production companies
often reduce or delay expenditures to reduce costs, which in turn may cause a
reduction in the demand for our services during these periods. The number of
active land drilling rigs may be indicative of demand for services that we
provide. If the economic environment worsens, our business, financial condition
and results of operations may be further adversely impacted. The intense price competition and cyclical nature of our industry could have an adverse effect on our revenues and profitability. The contract drilling business is highly competitive with numerous
industry participants. The drilling contracts we compete for are usually
awarded on the basis of competitive bids. We believe pricing and rig
availability are the primary factors considered by our potential customers in
determining which drilling contractor to select. We believe other factors are
also important. Among those factors are:  
    
    the type and condition of drilling rigs;
    
    the quality of service and experience of rig crews;
    
    the safety record of the company and the particular drilling rig;
    
    the offering of ancillary services; and
    
    the ability to provide drilling equipment adaptable to, and
personnel familiar with, new technologies and drilling techniques. While we must generally be competitive in our pricing, our competitive
strategy emphasizes the quality of our equipment, the safety record of our rigs
and the experience of our rig crews to differentiate us from our
competitors. This strategy is less effective during an industry downturn
as lower demand for drilling services intensifies price competition and makes
it more difficult for us to compete on the basis of factors other than price. The contract drilling industry historically has been cyclical and has
experienced periods of low demand, excess rig supply, and low dayrates,
followed by periods of high demand, short rig supply and increasing dayrates.
Periods of excess rig supply intensify the competition in our industry and
often result in rigs being idle. There are numerous competitors in each of the markets in which we compete.
In all of those markets, an oversupply of rigs can cause greater price
competition. Contract drilling companies compete primarily on a regional
basis, and the intensity of competition may vary significantly from region to
region at any particular time. If demand for drilling services improves in a
region where we operate, our competitors might respond by moving in suitable
rigs from other regions. An influx of rigs from other regions could rapidly
intensify competition and make any improvement in demand for drilling rigs
short-lived. -8-




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We face competition from competitors with greater resources. Some of our competitors have greater financial and human resources than do
we. Their greater capabilities in these areas may enable them to:  
    
    better withstand industry downturns;
    
    compete more effectively on the basis of price and technology;
    
    retain skilled rig personnel; and
    
    build new rigs or acquire and refurbish existing rigs to be
able to place rigs into service more quickly than we can. Our drilling operations involve operating hazards which if not adequately
insured or indemnified against could adversely affect our results of operations
and financial condition. Our operations are subject to the usual hazards inherent in the land
drilling business including the risks of:  
    
    blowouts;
    
    reservoir damage;
    
    cratering;
    
    fires, pollution and explosions;
    
    collapse of the borehole;
    
    lost or stuck drill strings; and
    
    damage or loss from natural disasters. If these drilling hazards occur they can produce substantial liabilities to us which include:  
    
    suspension of drilling operations;
    
    damage to the environment;
    
    damage to, or destruction of, our property and equipment and that of others;
    
    personal injury and loss of life; and
    
    damage to producing or potentially productive oil and natural
gas formations through which we drill. We attempt to obtain indemnification from our customers by contract for
certain of these risks under daywork contracts but are not always able to do
so. We also seek to protect ourselves from some but not all operating hazards
through insurance coverage. The indemnification we receive from our customers
and our own insurance coverage may not, however, be sufficient to protect us
against liability for all consequences of disasters, personal injury and
property damage. Additionally, our insurance coverage generally provides that
we bear a portion of the claim through substantial insurance coverage
deductibles. Our insurance or indemnification arrangements may not adequately
protect us against liability from all of the hazards of our business. If we
were to incur a significant liability for which we were not fully insured or
indemnified, it could adversely affect on our financial position and results of
operations. Our cost of insurance increased significantly in 2003 compared to prior
years, which we believe is consistent with the experience of most companies in
our industry. When we renew our current insurance policies, the premiums we pay
may again increase, which will increase our operating costs. Additionally, we
may be unable to obtain or renew insurance coverage of the type and amount we
desire at reasonable rates. Business acquisitions entail numerous risks and may disrupt our business,
dilute shareholder value or distract management attention. As part of our business strategy, we plan to consider acquisitions of, or
significant investments in, businesses and assets that are complementary to
ours. Any acquisition that we complete could have a material adverse affect on
our operating results and/or the price of our securities. Acquisitions involve
numerous risks, including:  
    
    unanticipated costs and liabilities;  
    
    difficulty of integrating the operations and assets of the acquired business; -9-




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##### 




    
    our ability to properly access and maintain an effective
internal control environment over an acquired company, in order to
comply with the recently adopted and pending public reporting
requirements;  
    
    potential loss of key employees and customers of the acquired companies; and  
    
    an increase in our expenses and working capital requirements. We may incur substantial indebtedness to finance future acquisitions and
also may issue equity securities or convertible securities in connection with
any such acquisitions. Debt service requirements could represent a significant
burden on our results of operations and financial condition and the issuance of
additional equity could be dilutive to our existing stockholders. Also,
continued growth could divert the attention of our management and other
employees from our day-to-day operations and the development of new business
opportunities. Our operations are subject to environmental laws that may expose us to
liabilities for noncompliance, which may adversely affect us. Many aspects of our operations are subject to domestic laws and
regulations. For example, our drilling operations are typically subject to
extensive and evolving laws and regulations governing:  
    
    environmental quality;  
    
    pollution control; and
    
    remediation of environmental contamination. Our operations are often conducted in or near ecologically sensitive
areas, such as wetlands, which are subject to special protective measures and
which may expose us to additional operating costs and liabilities for
noncompliance with applicable laws. The handling of waste materials, some of
which are classified as hazardous substances, is a necessary part of our
operations. Consequently, our operations are subject to stringent regulations
relating to protection of the environment and waste handling which may impose
liability on us for our own noncompliance and, in addition, that of other
parties without regard to whether we were negligent or otherwise at fault.
Compliance with applicable laws and regulations may require us to incur
significant expenses and capital expenditures which could have a material and
adverse effect on our operations by increasing our expenses and limiting our
future contract drilling opportunities. We have had only two profitable years since 1991. 
 We have a history of losses with only two profitable years since 1991. In
1997, we had net income of $10.2 million, and in 2001 we had net income of
$68.5 million. Our ability to achieve profitability in the future will depend
on many factors, but primarily on the number of days our rigs work during any
period and the rates we charge our customers for them during that period. In
the years in which we incurred losses, those losses were primarily due to the
fact that the number of days our rigs worked and the rates we were able to
charge customers for the days worked generated insufficient revenue to cover
our expenses in those years. In some years, we have also incurred charges for
impairment of our drilling equipment assets that contributed to our losses in a
year. This was the case in 2002, when we incurred a $3.5 million asset
impairment charge and reported a loss of $21.5 million for the year. 
 Unexpected cost overruns on our turnkey and footage drilling jobs could
adversely affect us. 
 We have historically derived a significant portion of our revenues from
turnkey and footage drilling contracts and we expect that they will continue to
represent a significant component of our revenues. The occurrence of operating
cost overruns on our turnkey and footage jobs could have a material adverse
effect on our financial position and results of operations. Under a typical
turnkey or footage drilling contract, we agree to drill a well for our customer
to a specified depth and under specified conditions for a fixed price. We
typically provide technical expertise and engineering services, as well as most
of the equipment required for the drilling of turnkey and footage wells. We
often subcontract for related services. Under typical turnkey drilling
arrangements, we do not receive progress payments and are entitled to be paid
by our customer only after we have performed the terms of the drilling contract
in full. For these reasons, the risk to us under turnkey and footage drilling
contracts is substantially greater than for wells drilled on a daywork basis
because we must assume most of the risks associated with drilling operations
that are generally assumed by our customer under a daywork contract. 
 -10-




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##### 



We could be adversely affected if shortages of equipment, supplies or personnel
occur. While we are not currently experiencing any shortages, from time to time
there have been shortages of drilling equipment and supplies which we believe
could reoccur. During periods of shortages, the cost and delivery times of
equipment and supplies are substantially greater. In the past, in response to
such shortages, we have entered into agreements with various suppliers and
manufacturers that enabled us to reduce our exposure to price increases and
supply shortages. Although we have formed many informal supply arrangements
with equipment manufacturers and suppliers, we cannot assure you that we will
be able to maintain existing arrangements. Shortages of drilling equipment or
supplies could delay and adversely affect our ability to return to service our
rigs held for future refurbishment and obtain contracts for our marketed rigs,
which could have a material adverse effect on our financial condition and
results of operations. Although we have not encountered material difficulty in hiring and
retaining qualified rig crews, such shortages have occurred in the past in our
industry. We may experience shortages of qualified personnel to operate our
rigs, which could have a material adverse effect on our financial condition and
results of operations. Our indentures and our credit agreement may prohibit us from participation in
certain transactions that we may consider advantageous. The indentures under which we issued our 8 7/8% Senior Notes due 2007 and 8 7/8%
Senior Notes due 2007, Series B (together, the 8 7/8% Notes) contain
restrictions on our ability and the ability of certain of our subsidiaries
to engage in certain types of transactions. These restrictive covenants may
adversely affect our ability to pursue business acquisitions. These include
covenants which may prohibit or limit our ability to:  
    
    incur additional indebtedness;  
    
    pay dividends or make other restricted payments;  
    
    repurchase our equity securities;  
    
    sell material assets;  
    
    grant or permit liens to exist on our assets;  
    
    enter into sale and lease-back transactions;  
    
    make certain investments;  
    
    enter into transactions with related persons; and  
    
    engage in lines of business unrelated to our core land drilling business. Our subsidiary, Grey Wolf Drilling Company L.P., has entered into a credit
facility that also contains covenants restricting our ability to undertake many
of the same types of transactions and contains financial ratio covenants when
certain conditions are met. They may also limit our ability to respond to
changes in market conditions. Our ability to meet the financial ratio covenants
of our credit agreement and indentures can be affected by events and conditions
beyond our control and we may be unable to meet those tests (see Note 4 to the
consolidated financial statements). We may in the future incur additional
indebtedness that may contain additional covenants that may be more restrictive
than our current covenants. Our credit facility contains default terms that effectively cross default
with any of our other debt agreements, including the indentures for our 8 7/8%
Notes and our 3.75% Contingent Convertible Notes due May 2023 (the 3.75%
Notes). Thus, if we breach the covenants in the indentures for our 8 7/8% Notes,
it could cause our default under our 8 7/8% Notes, our credit facility and,
possibly, other then outstanding debt obligations owed by us. If the
indebtedness under our credit facility or other indebtedness owed by us is more
than $10.0 million and is not paid when due, or is accelerated by the holders
of the debt, then an event of default under the indentures covering our 8 7/8%
Notes would occur. If circumstances arise in which we are in default under our
various credit agreements, our cash and other assets may be insufficient to
repay our indebtedness. We have a significant amount of indebtedness and could incur additional
indebtedness, which could materially and adversely affect our financial
condition and results of operations. We have now and will continue to have a significant amount of
indebtedness. On December 31, 2003, our total long-term indebtedness was
approximately $235.0 million in principal amount, (primarily consisting of
$150.0 million in principal amount of our 3.75% Notes and $85.0 million in
principal amount of 8 7/8% Notes). -11-




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##### 



Our substantial indebtedness could:  
    
    increase our vulnerability to general adverse economic and industry conditions;  
    
    require us to dedicate a substantial portion of our cash flow
from operations to payments on our indebtedness thereby reducing the
availability of our cash flow to fund working capital, capital
expenditures and other general corporate purposes;
    
    limit our flexibility in planning for, or reacting to,
changes in our business and the industry in which we operate;  
    
    place us at a competitive disadvantage compared to our competitors that have less debt; and  
    
    limit our ability to borrow additional funds. Neither the indenture governing our 3.75% Notes nor the terms of our 3.75%
Notes limit our ability to incur additional indebtedness, including senior
indebtedness, or to grant liens on our assets. We and our subsidiaries may
incur substantial additional indebtedness and liens on our assets in the
future. Our existing senior indebtedness is, and any senior indebtedness we incur will
be, effectively subordinated to any present or future obligations to secured
creditors and liabilities of our subsidiaries. 
 Substantially all of our assets and the assets of our subsidiaries,
including our drilling equipment and the equity interest in our subsidiaries,
are pledged as collateral under our credit facility. Our credit facility is
also secured by our guarantee and the guarantees of our subsidiaries. The
3.75% Notes and the 8 7/8% Notes are, and any senior indebtedness we incur will
be, effectively subordinated to all of our and our subsidiaries existing and
future secured indebtedness, including any future indebtedness incurred under
our credit facility. As of February 10, 2004, we had the ability to borrow
approximately $58.6 million under our credit facility (after reductions for
undrawn outstanding standby letters of credit of $16.4 million). In addition,
the 3.75% Notes and the 8 7/8% Notes are effectively subordinated to the claims of
all of the creditors, including trade creditors and tort claimants, of our
subsidiaries. 
 To service our indebtedness, we will require a significant amount of cash. Our
ability to generate cash depends on many factors beyond our control. Our operating activities did not provide net cash sufficient to pay our
debt service obligations for the year ended December 31, 2003 and we cannot
assure you that we will be able to generate sufficient cash flow in the future.
Our ability to make payments on and to refinance our indebtedness and to fund
planned capital expenditures will depend on our ability to generate cash in the
future. This, to a large extent, is subject to general economic, financial,
competitive, regulatory and other factors that are beyond our control. Our reported earnings per share may be more volatile because of the conversion
contingency provision of the 3.75% Notes. Holders of the 3.75% Notes may convert such notes prior to the maturity
date into shares of our common stock in the following circumstances:  
    
    during any calendar quarter, if the closing sale price per
share of our common stock for at least 20 trading days in the period
of 30 consecutive trading days ending on the last trading day of the
calendar quarter preceding the quarter in which the conversion
occurs, is more than 110% of the conversion price per share ($7.10
per share) on that 30th trading day;  
    
    if we have called the 3.75% Notes for redemption;  
    
    during any period that the credit ratings assigned to the
3.75% Notes by both Moodys Investors Service (Moodys) and
Standard & Poors Ratings Group (S&P) are reduced below B1 and B+,
respectively;  
    
    if neither Moodys nor S&P is rating the 3.75% Notes;  
    
    during the five trading day period immediately following any
nine consecutive trading day period in which the average trading
price per $1,000 principal amount of the 3.75% Notes for each day of
such period was less than 95% of the product of the closing sale
price per share of our common stock on that day multiplied by the
number of shares of our common stock issuable upon conversion of
$1,000 principal amount of the 3.75% Notes; or  
    
    upon the occurrence of specified corporate transactions,
including a change in control. -12-




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##### 



Until one of these contingencies is met, the shares underlying the 3.75%
Notes are not included in the calculation of basic or diluted earnings per
share. Should one of these contingencies be met, earnings per share could
decrease, depending on the level of net income, as a result of the inclusion of
the underlying shares in the earnings per share calculation. Volatility in our
stock price could cause this condition to be met in one quarter and not in a
subsequent quarter, increasing the volatility of diluted earnings per share. 
 Investors in our common stock should not expect to receive dividend income, and
will be dependent on the appreciation of our common stock to earn a return on
their investment. 
 
 The decision to pay a dividend on our common stock rests with our board of
directors and will depend on our earnings, available cash, capital requirements
and financial condition. We have never declared a cash dividend on our common
stock and do not expect to pay cash dividends on our common stock for the
foreseeable future. We expect that all cash flow generated from our operations
in the foreseeable future will be retained and used to develop or expand our
business, pay debt service and reduce outstanding indebtedness. Furthermore,
the terms of our credit facility prohibit the payment of dividends without the
prior written consent of the lenders. Investors will likely have to depend on
sales of our common stock at appreciated prices, which we cannot assure, in
order to achieve a positive return on their investment in our common stock. 
 Certain provisions of our organizational documents, securities and credit
agreement have anti-takeover effects which may prevent our shareholders from
receiving the maximum value for their shares. Our articles of incorporation, bylaws, securities and credit agreement
contain certain provisions that may delay or prevent entirely a change of
control transaction not supported by our board of directors, or any transaction
which may have that general effect. These provisions include:  
    
    classification of our board of directors into three classes,
with each class serving a staggered three year term;
    
    giving our board of directors the exclusive authority to
adopt, amend or repeal our bylaws and thus prohibiting shareholders
from doing so;
    
    requiring our shareholders to give advance notice of their
intent to submit a proposal at the annual meeting; and
    
    limiting the ability of our shareholders to call a special
meeting and act by written consent. Additionally, the indentures under which our 3.75% Notes and 8 7/8% Notes are
issued require us to offer to repurchase the 3.75% Notes and 8 7/8% Notes then
outstanding at a purchase price equal to 100% and 101%, respectively, of the
principal amount plus accrued and unpaid interest to the date of purchase in
the event that we become subject to a change of control, as defined in the
indentures. This feature of the indentures could also have the effect of
discouraging potentially attractive change of control offers. Furthermore, we have adopted a shareholder rights plan which may have the
effect of impeding a hostile attempt to acquire control of us. Large amounts of our common stock may be resold into the market in the future
which could cause the market price of our common stock to drop significantly,
even if our business is doing well. As of February 10, 2004, 181.4 million shares of our common stock were
issued and outstanding. An additional 10.2 million shares of our common stock
were issuable upon exercise of outstanding stock options (of which 5.4 million
shares are currently exercisable) and 23.3 million shares were issuable upon
conversion of the 3.75% Notes, once a contingency is met (see Note 4 to the
consolidated financial statements). The market price of our common stock could
drop significantly if future sales of substantial amounts of our common stock
occur, or if the perception exists that substantial sales may occur. Employees At February 10, 2004, we had approximately 1,750 employees. None of our
employees are subject to collective bargaining agreements, and we believe our
employee relations are satisfactory. -13-




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##### 



Forward-Looking Statements This annual report on Form 10-K contains forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. All
statements other than statements of historical facts included in this report
are forward-looking statements, including statements regarding the following:  
    
    business strategy;  
    
    demand for our services;  
    
    2004 rig activity and financial results;  
    
    reactivation and cost of reactivation of non-marketed rigs;  
    
    projected dayrates;  
    
    rigs expected to be engaged in turnkey and footage operations;  
    
    projected tax benefit rate;  
    
    wage rates and retention of employees;  
    
    sufficiency of our capital resources and liquidity; and
    
    depreciation and capital expenditures in 2004. 
 Although we believe the forward-looking statements are reasonable, we
cannot assure you that these statements will prove to be correct. We have
based these statements on assumptions and analyses in light of our experience
and perception of historical trends, current conditions, expected future
developments and other factors we believe were appropriate when the statements
were made. 
 Our forward-looking statements speak only as of the date specified in such
statements or, if no date is stated, as of the date of this report. Grey Wolf
expressly disclaims any obligation or undertaking to release
publicly any updates or revisions to any forward-looking statement
contained in this report to reflect any change in our expectations or with
regard to any change in events, conditions or circumstances on which our
forward-looking statements are based. ITEM 2. PROPERTIES Drilling Equipment An operating land drilling rig consists of engines, drawworks, mast,
substructure, pumps to circulate drilling fluid, blowout preventers, drill pipe
and related equipment. Domestically, land rigs generally operate with crews of
four to six people. 
 Our rig fleet consists of several rig types to meet the demands of our
customers in each of the markets we serve. Our rig fleet consists of two basic
types of drilling rigs, mechanical and diesel electric. Mechanical rigs
transmit power generated by a diesel engine directly to an operation (for
example the drawworks or mud pumps on a rig) through a compound consisting of
chains, gears and hydraulic clutches. Diesel electric rigs are further broken
down into two subcategories, direct current rigs and Silicon Controlled
Rectifier (SCR) rigs. Direct current rigs transmit the power generated by a
diesel engine to a direct current generator. This direct current electrical
system then distributes the electricity generated to direct current motors on
the drawworks and mud pumps. An SCR rigs diesel engines drive alternating
current generators and this alternating current can be transmitted to use for
rig lighting and rig quarters or converted to direct current to drive the
direct current motors on the rig. As of February 10, 2004, we owned nine
direct current diesel electric rigs and 52 SCR diesel electric rigs. 
 
 We also owned, at February 10, 2004, 17 mechanical rigs and one diesel
electric rig that are trailer-mounted for greater mobility. We believe that
trailer-mounted rigs and 1,500 to 2,000 horsepower diesel electric rigs are in
highest demand in the South Texas market. Trailer-mounted rigs are more mobile
than conventional rigs, thus decreasing the time and expense to the customer of
moving the rig to and from the drill site. Under ordinary conditions,
trailer-mounted rigs are capable of drilling an average of two 10,000 foot
wells per month. 
 We also utilize top drives in our drilling operations. A top drive allows
drilling with 90-foot lengths of drill pipe rather than 30-foot lengths, thus
reducing the number of required connections in the drill string. A top drive
also permits rotation of the drill string while moving in or out of the hole.
These characteristics increase drilling -14-




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##### 



speed, personnel safety and drilling
efficiency, and reduce the risk of the drill string sticking during operations.
At February 10, 2004, we owned 15 top drives. We generally deploy our rig fleet among our divisions and districts based
on the types of rigs preferred by our customers for drilling in the geographic
markets served by our divisions and districts. The following table summarizes
the rigs we own as of February 10, 2004: Maximum Rated Depth Capacity (1)Under
    
    10,000'
    
    15,000'
    
    20,000'10,000'
    
    to 14,999'
    
    to 19,999'
    
    and Deeper
    
    TotalMarketedArk-La-TexDiesel Electric
    
    
    
    
    
    
    1
    
    
    
    5
    
    
    
    5
    
    
    
    11Trailer-Mounted
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    1Mechanical
    
    
    
    
    
    
    2
    
    
    
    3
    
    
    
    2
    
    
    
    7Gulf CoastDiesel Electric
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    17
    
    
    
    18Mechanical
    
    
    
    
    
    
    1
    
    
    
    2
    
    
    
    
    
    
    
    3South TexasDiesel Electric
    
    
    
    
    
    
    1
    
    
    
    6
    
    
    
    8
    
    
    
    15Trailer-Mounted
    
    
    
    
    
    
    9
    
    
    
    
    
    
    
    1
    
    
    
    10
    (2)Mechanical
    
    
    
    
    
    
    4
    
    
    
    
    
    
    
    1
    
    
    
    5Rocky MountainDiesel Electric
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4
    
    
    
    4West TexasDiesel Electric
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    4
    
    
    
    6Total Marketed
    
    
    
    
    
    
    19
    
    
    
    19
    
    
    
    42
    
    
    
    80Non-marketedDiesel Electric
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7
    
    
    
    7Trailer-Mounted
    
    
    1
    
    
    
    6
    
    
    
    
    
    
    
    
    
    
    
    7Mechanical
    
    
    1
    
    
    
    11
    
    
    
    8
    
    
    
    3
    
    
    
    23Total Non-Marketed
    
    
    2
    
    
    
    17
    
    
    
    8
    
    
    
    10
    
    
    
    37Total Rig Fleet
    
    
    2
    
    
    
    36
    
    
    
    27
    
    
    
    52
    
    
    
    117
  (1)
    
    The actual drilling capacity of a rig may be less than its rated
capacity due to numerous factors, such as the length of the drill string and
casing size. The intended well depth and the drill site conditions determine
the length of the drill string and other equipment needed to drill a well.(2)
    
    Includes one diesel electric rig. Facilities The following table summarizes our significant real estate: Location
    
    Interest
    
    UsesHouston, Texas
    
    Leased
    
    Corporate OfficeAlice, Texas
    
    Owned
    
    Division Office, Rig Yard, Truck YardEunice, Louisiana
    
    Owned
    
    Division Office, Rig YardHaughton, Louisiana
    
    Owned
    
    Rig YardShreveport, Louisiana
    
    Leased
    
    Division OfficeShreveport, Louisiana
    
    Owned
    
    Rig Yard, Truck YardCasper, Wyoming
    
    Leased
    
    District Office, Rig YardMidland, Texas
    
    Leased
    
    District Office
 We lease approximately 22,700 square feet of office space in Houston,
Texas for our principal corporate offices at a cost of approximately $41,500
per month. We believe that all our facilities are in good operating condition
and that they are adequate for their present uses. -15-




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ITEM 3. LEGAL PROCEEDINGS We are involved in litigation incidental to the conduct of our business,
none of which we believe is, individually or in the aggregate, material to our
consolidated financial condition or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED SHAREHOLDER MATTERS Market Data 
 Our common stock is listed and traded on the American Stock Exchange
(AMEX) under the symbol GW. As of February 13, 2004, we had 976
shareholders of record. The following table sets forth the high and low
closing prices of our common stock on the AMEX for the periods indicated: 
 High
    
    LowPeriod from January 1, 2004 to February 10, 2004
    
    $
    4.31
    
    
    $
    3.74Year Ended December 31, 2003Quarter ended March 31, 2003
    
    
    4.50
    
    
    
    3.50Quarter ended June 30, 2003
    
    
    4.96
    
    
    
    3.88Quarter ended September 30, 2003
    
    
    4.19
    
    
    
    3.22Quarter ended December 31, 2003
    
    
    3.89
    
    
    
    3.16Year Ended December 31, 2002Quarter ended March 31, 2002
    
    
    4.07
    
    
    
    2.69Quarter ended June 30, 2002
    
    
    5.01
    
    
    
    3.72Quarter ended September 30, 2002
    
    
    4.08
    
    
    
    2.78Quarter ended December 31, 2002
    
    
    4.42
    
    
    
    3.15
 We have never declared or paid cash dividends on our common stock and do
not expect to pay cash dividends in 2004 or for the foreseeable future. We
anticipate that all cash flow generated from operations in the foreseeable
future will be retained and used to develop or expand our business, pay debt
service and reduce outstanding indebtedness. Any future payment of cash
dividends will depend upon our results of operations, financial condition, cash
requirements and other factors deemed relevant by our board of directors. The terms of our credit facility prohibit the payment of dividends without
the prior written consent of the lender and the terms of the Indentures under
which our 8 7/8% Notes are issued also restrict our ability to pay dividends under
certain conditions. On February 10, 2004, the last reported sales price of our common stock on
the AMEX was $4.25 per share. ITEM 6. SELECTED FINANCIAL DATA Years Ended December 31,2003
    
    2002
    
    2001
    
    2000
    
    1999(Amounts in thousands, except per share amounts)Revenues (1)
    
    $
    285,974
    
    
    $
    250,260
    
    
    $
    433,739
    
    
    $
    276,758
    
    
    $
    148,465Net income (loss)
    
    
    (30,200
    )
    
    
    (21,476
    )
    
    
    68,453
    
    
    
    (8,523
    )
    
    
    (41,262
    )Net income (loss)
per common share-
basic and diluted
    
    
    (0.17
    )
    
    
    (0.12
    )
    
    
    0.38
    
    
    
    (0.05
    )
    
    
    (0.25
    )Total assets (1)
    
    
    529,078
    
    
    
    590,623
    
    
    
    625,471
    
    
    
    512,370
    
    
    
    453,852Senior and
contingent
convertible notes &
other long-term
debt
    
    
    234,898
    
    
    
    249,613
    
    
    
    250,695
    
    
    
    249,851
    
    
    
    249,962   (1)
    
    Presentation revised to give effect to reclassification of certain items to
conform to the presentation in 2002 and 2003 (see Note 1 to consolidated
financial statements).
 -16-




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Item 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS 
 The following discussion should be read in conjunction with our
consolidated financial statements included elsewhere herein. All significant
intercompany transactions have been eliminated. Overview 
 We are a leading provider of contract land drilling services in the United
States with a fleet, at February 10, 2004, of 117 rigs, of which 80 rigs were
marketed. Our customers include independent producers and major oil and gas
companies. We conduct all of our operations through our subsidiaries in the
Ark-La-Tex, Gulf Coast, Mississippi/Alabama, South Texas, West Texas and Rocky
Mountain drilling markets. Our drilling contracts generally provide
compensation on a daywork, turnkey or footage basis (see Item 1. Business). 
 Our business is cyclical and our financial results depend upon several
factors. These factors include the overall demand for land drilling services,
the level of demand for turnkey and footage services, the demand for deep
versus shallow drilling services, the dayrates we receive for our services and
our success drilling turnkey and footage wells. Rig Activity After a modest increase in our number of rigs working in the first quarter
of 2003, our rig count has remained relatively stable. Our premium rig fleet
is biased towards deep gas drilling and we believe that our activity and market
share have been adversely affected by the general lack of deep drilling in this
current industry cycle. The table below shows the average number of land rigs working in the
United States according to the Baker Hughes rotary rig count and the average
number of our rigs working. 2002
    
    2003
    
    2004DomesticLand Rig
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Full
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Full
    
    Q-1 toCount
    
    Q-1
    
    Q-2
    
    Q-3
    
    Q-4
    
    Year
    
    Q-1
    
    Q-2
    
    Q-3
    
    Q-4
    
    Year
    
    2/10Baker Hughes
    
    
    679
    
    
    
    683
    
    
    
    722
    
    
    
    723
    
    
    
    695
    
    
    
    773
    
    
    
    903
    
    
    
    964
    
    
    
    988
    
    
    
    880
    
    
    
    995Grey Wolf
    
    
    56
    
    
    
    54
    
    
    
    55
    
    
    
    54
    
    
    
    55
    
    
    
    59
    
    
    
    60
    
    
    
    62
    
    
    
    62
    
    
    
    61
    
    
    
    63
 Drilling Contract Bid Rates 
 Daywork dayrates are generally driven by the number of rigs working, or
utilization. Our daywork bid rates ranged between $7,000 and $8,500 per rig
day during the fourth quarter of 2002. However, as the land rig count
increased, our bid rates rose to between $8,000 and $9,500 per rig day, as of
February 10, 2004. All bid rates exclude fuel and top drives. We believe that
the drilling contract dayrates have been affected by an increase in the number
of rigs available, as well as by the focus by our competitors on market share
rather than higher dayrates. 
 
 In addition to our fleet of drilling rigs, we owned, at February 10, 2004,
15 top drives for which our bid rates ranged from $1,500 to $2,000 per day, at
that date. Bid rates for our top drives are in addition to the above stated bid
rates for our rigs. 
 Turnkey and Footage Contract Activity 
 Turnkey and footage work continues to be an important part of our business
and operating strategy. Our engineering and operating expertise allow us to
provide this service to our customers and has historically provided higher
revenues and EBITDA (earnings before interest, taxes, depreciation and
amortization) per rig day worked than under daywork contracts. However, we are
typically required to bear additional operating costs (such
as drill bits) that would otherwise be paid by the customer under daywork
contracts. In 2003, our turnkey and footage EBITDA per rig day was
$5,707compared to a daywork EBITDA per rig day of $593, and our turnkey and
footage revenue was $31,087 per rig day compared to $9,562 per rig day for
daywork. For the year ended December 31, 
 -17-




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##### 



2003, turnkey and footage work
represented 16% of total rig days worked compared to 9% of total rig days
worked in 2002. A rig day is defined as a twenty-four hour period in which a
rig is under contract and should be earning revenue. 
 
 The revenue and drilling operating expenses generated on turnkey and
footage contracts vary widely based upon a number of factors, including the
location of the contracted work as well as the depth and level of complexity of
the wells drilled. The demand for drilling services under turnkey and footage
contracts has historically been greater during periods of overall lower demand.
While demand has been somewhat higher as evidenced by the increase in rig
count, the demand for turnkey services has not declined. We believe this is
due in large part to current daywork rates which have increased only slightly
despite the increase in rig count. 
 Fourth Quarter Financial Results 
 The fourth quarter of 2003 exceeded our previous guidance for the quarter.
Our previous guidance for the fourth quarter was a loss per share of $0.03 on
a diluted basis based upon an average of 66 rigs running. Actual average rigs
running in the fourth quarter of 2003 was 61 and our earnings per share on a
diluted basis for the quarter ended December 31, 2003, was $0.00. The fourth
quarter also included $3.1 million from the sale of a claim in bankruptcy,
against a bankrupt customer, for revenues related to the early termination of a
long-term contract. The early termination revenue was not recognized
previously as the company did not believe it was realizable due to the
customers payment status at the time of the early termination and subsequent
bankruptcy filing. 
 
 In addition to the sale of the claim noted above, we exceeded our previous
guidance primarily due to a record quarter from our turnkey business. We averaged 12 rigs working on turnkey contracts
during the fourth quarter, representing 20% of the total rig days and
43% of our revenue compared to 12% of the total rig days and 28% of
our revenue for the same period in the prior year. We believe that
turnkey work will remain strong in the first quarter of 2004, however, we are
not expecting a repeat of the performance in the fourth quarter. 
 First Quarter 2004 Outlook 
 At February 10, 2003, we
expected that for the first quarter we would have an average of 66 rigs
running and net loss per share of approximately $0.02 on a diluted basis,
projecting an annual tax benefit rate of approximately 37%. That projection
was based upon anticipated levels of activity and dayrates. We expect
depreciation expense of approximately $12.9 million and interest expense of
approximately $3.7 million in the first quarter of 2004. Capital expenditures
for 2004 are currently projected to be $27.0 million to $30.0 million subject
to the actual level of rig activity. These projections are forward-looking
statements and while we believe our estimates are reasonable, we can give no
assurance that such expectations or the assumptions that underlie such
assumptions will prove to be correct. We expect to average between eight and
11 rigs working under turnkey and footage contracts during the first quarter of
2004; however, there can be no assurance that we will be able to maintain the
current level of activity or financial results derived from turnkey and
footage contracts. See Item 1. Business-Forward-Looking Statements for
important factors that could cause actual results to be differ materially from
our expectations. 
 Critical Accounting Policies Our consolidated financial statements and accompanying notes have been
prepared in accordance with accounting principles generally accepted in the
United States of America. The preparation of these financial statements require
our management to make subjective estimates, judgments and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses.
However, these estimates, judgments and assumptions concern matters that are
inherently uncertain. Accordingly, actual amounts and results could differ from
these estimates made by management, sometimes materially. Critical accounting
policies and estimates are defined as those that are both most important to the
portrayal of our financial condition and operating results and require
managements most subjective judgments. The accounting policies that we
believe are critical are property and equipment, impairment of long-lived
assets, revenue recognition, insurance accruals, and income taxes. 
 Property and Equipment. Property and equipment, including betterments and
improvements are stated at cost with depreciation calculated using the
straight-line method over the estimated useful lives of the assets. We make
estimates with respect to the useful lives that we believe are reasonable.
However, the cyclical nature of our business or the introduction of new
technology in the industry, could cause us to change our estimates, thus
impacting the future calculation of depreciation. When any asset is tested for
recoverability, we also review the 
 -18-




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##### 



remaining useful life of the asset. Any
changes to the estimated useful life resulting from that review are made
prospectively. We expense our maintenance and repair costs as incurred. We
estimate the useful lives of our assets are between three and fifteen years. 
 
 Impairment of Long-Lived Assets. We assess the impairment of our
long-lived assets under Statement of Financial Accounting Standards Board
(SFAS) No. 144 Accounting for the Impairment or Disposal of Long-Lived
Assets, whenever events or changes in circumstances indicate that the carrying
value may not be recoverable. Such indicators include changes in our business
plans, a change in the physical condition of a long-lived asset or the extent
or manner in which it is being used, or a severe or sustained downturn in the
oil and gas industry. If we determine that a triggering event, such as those
described previously, has occurred we perform a review of our rig and rig
equipment. Our review is performed by comparing the carrying value of each rig
plus the estimated cost to refurbish or reactivate to the estimated
undiscounted future net cash flows for that rig. If the carrying value plus
estimated refurbishment and reactivation cost of any rig is more than the
estimated undiscounted future net cash flows expected to result from the use of
the rig, a write-down of the rig to estimated fair market value must be made.
The estimated fair market value is the amount at which an asset could be bought
or sold in a current transaction between willing parties. Quoted market prices
in active markets are the best estimate of fair market value, however, quoted
market prices are generally not available. As a result, fair value must be
determined based upon other valuation techniques. This could include appraisals
or present value calculations. The calculation of undiscounted future net cash
flows and fair market value is based on our estimates and projections. 
 
 The demand for land drilling services is cyclical and has historically
resulted in fluctuations in rig utilization. The severity and duration of the
downturn during 1998 triggered an asset impairment charge of $93.2 million. We
believe the contract drilling industry will continue to be cyclical and rig
utilization will fluctuate. The likelihood of an asset impairment increases
during extended periods of rig inactivity. Each year we evaluate our cold
stacked and inventory rigs and determine our intentions for their future use.
This evaluation takes into consideration, among other things, the physical
condition and marketability of the rig, and projected reactivation or
refurbishment cost. To the extent that our estimates of refurbishment and
reactivation cost, undiscounted future net cash flows or fair market value
change or there is a deterioration in the physical condition of the inventory
or cold stacked rigs, we could be required under SFAS No. 144 to record an
impairment charge. During the fourth quarter of 2002, we recorded a pre-tax,
non-cash asset impairment charge of $3.5 million after performing such a
review. Due to the deterioration of the physical condition of five of the
inventory rigs and changes in market conditions, it was determined that the
rigs, based upon the economics, could no longer be returned to service at a
reasonable cost that would have provided an acceptable return and that the
usable component parts would be included in spare equipment and depreciated
over five years. In 2003, no impairment of our long-lived assets was recorded
as no change in circumstances indicated that the carrying value of the assets
was not recoverable. Below is summary of our rig fleet and the estimated cost
to refurbish and reactive by category as of February 10, 2004: 
 NumberRig Category
    
    Of Rigs
    
    Estimated Per Rig Refurbishment and Reactivation CostMarketed
    
    
    80
    
    
    N/ACold Stacked
    
    
    22
    
    
    $0.1-0.2 MillionInventory
    
    
    15
    
    
    $4.5-5.5 Million
 
 The net book value of the inventory rigs at December 31, 2003 was $19.6
million. 
 
 Revenue Recognition. Revenues are earned under daywork, turnkey and
footage contracts. Revenue from daywork and footage contracts is recognized
when it is realized or realizable and earned. On daywork contracts revenue is
recognized based on the number of days completed at fixed rates stipulated by
the contract. On footage contracts revenue is recognized based on the number
of feet that have been drilled at fixed rates stipulated by the contract.
Revenue from turnkey drilling contracts is recognized using the
percentage-of-completion method based upon costs incurred to date compared to
our estimate of the total contract costs. Under percentage-of-completion, we
make estimates of the total contract costs to be incurred, and to the extent
these estimates change, the amount of revenue recognized could be affected.
The significance of the accrued turnkey revenue varies from period to period
depending on the overall level of demand for our services and the portion of
that demand that is for turnkey services. 
 -19-




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At December 31, 2003, there were
eight turnkey wells in progress versus four wells at December 31, 2002, with
accrued revenue of $5.0 million and $3.6 million, respectively at such dates.
Anticipated losses, if any, on uncompleted contracts are recorded at the time
our estimated costs exceed the contract revenue. 
 Insurance Accruals. We maintain insurance coverage related to workers
compensation and general liability claims up to $1.0 million per occurrence
with an aggregate of $2.0 million for general liability claims. These policies
include deductibles of $350,000 per occurrence for workers compensation
coverage and $250,000 per occurrence for general liability coverage. If losses
should exceed the workers compensation and general liability policy amounts,
we have excess liability coverage up to a maximum of $75.0 million. At
December 31, 2003 and 2002, we had $9.4 million and $9.7 million, respectively,
accrued for losses incurred within the deductible amounts for workers
compensation and general liability claims. 
 The amount accrued for the provision for losses incurred varies depending
on the number and nature of the claims outstanding at the balance sheet dates.
In addition, the accrual includes managements estimate of the future cost to
settle each claim such as future changes in the severity of the claim and
increases in medical costs. We use third parties to assist us in developing
our estimate of the ultimate costs to settle each claim, which is based upon
historical experience associated with the type of each claim and specific
information related to each claim. The specific circumstances of each claim
may change over time prior to settlement and as a result, our estimates made as
of the balance sheet dates may change. 
 Income Taxes. Our deferred tax assets consist primarily of net operating
loss carryforwards (NOLs). The estimated amount of our NOLs at December
31, 2003 are $133.5 million, which expires from 2010 to 2023. Approximately
$7.2 million of these NOLs expire in 2010 and 2011, while the remaining $126.3
million expire between 2019 and 2023. Deferred tax assets must be assessed
based upon the likelihood of recoverability from future taxable income and to
the extent that recovery is not likely, a valuation allowance is established.
At December 31, 2003, we do not have a valuation allowance as we believe that
it is more likely than not that our future taxable income and reversal of
deferred tax liabilities will be sufficient to recover our deferred tax assets.
Our business, however, is extremely cyclical and is highly sensitive to changes
in oil and natural gas prices and demand for our services and there can be no
assurances that future economic or financial developments will not impact our
ability to recover our deferred tax assets. 
 In addition, we have $26.5 million in permanent differences which relate
to differences between the financial accounting and tax basis of assets that
were purchased in capital stock acquisitions. The permanent difference will be
reduced as the assets are depreciated for financial accounting purposes on a
straight-line basis over the next nine years. As the amortization of these
permanent differences is a fixed amount, our effective tax rate varies widely
based upon the current level of income or loss. See Note 3 to our consolidated
financial statements for a reconciliation of our statutory to effective tax
rate. 
 Financial Condition and Liquidity The following table summarizes our financial position as of December 31,
2003 and December 31, 2002. December 31, 2003
    
    December 31, 2002Amount
    
    %
    
    Amount
    
    %(In thousands)Working capital
    
    $
    68,727
    
    
    
    14
    
    
    $
    114,353
    
    
    
    21Property and equipment, net
    
    
    404,278
    
    
    
    85
    
    
    
    420,791
    
    
    
    78Other noncurrent assets
    
    
    5,141
    
    
    
    1
    
    
    
    4,668
    
    
    
    1Total
    
    $
    478,146
    
    
    
    100
    
    
    $
    539,812
    
    
    
    100Long-term debt
    
    $
    234,898
    
    
    
    49
    
    
    $
    249,613
    
    
    
    46Other long-term liabilities
    
    
    47,611
    
    
    
    10
    
    
    
    64,941
    
    
    
    12Shareholders equity
    
    
    195,637
    
    
    
    41
    
    
    
    225,258
    
    
    
    42Total
    
    $
    478,146
    
    
    
    100
    
    
    $
    539,812
    
    
    
    100
 -20-




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Significant Changes in Financial Condition. The significant changes in our financial position from December 31, 2002
to December 31, 2003 are a decrease in working capital of $45.6 million, a
decrease in other long-term liabilities of $17.3 million and a decrease in
shareholders equity of $29.6 million. The decrease in working capital is a
result of the issuance of the 3.75% Contingent Convertible Senior Notes due
2023 (the 3.75% Notes) and partial redemption of the 8 7/8% Senior Notes due
2007 (the 8 7/8% Notes), the net loss for the period and capital expenditures.
The decrease in shareholders equity liabilities is due almost entirely to the
net loss for the period of $30.2 million. The decrease in other long-term
liabilities is due to the change in our net deferred tax liabilities resulting
from a deferred tax benefit of $16.4 million. On May 7, 2003, we issued $150.0 million aggregate principal amount of
3.75% Notes. The net proceeds of $146.6 million from the sale of the 3.75%
Notes and $30.6 million of our available cash, a total of $177.2 million, were
used to redeem $165.0 million aggregate principal amount of the 8 7/8% Notes, plus
accrued but unpaid interest. The partial redemption of the 8 7/8% Notes was made
on July 1, 2003 at a redemption premium of 102.9580%. This redemption premium
of $4.9 million was included in interest expense in the second quarter of 2003.
Amortization of the previously deferred financing costs associated with the
notes was accelerated and approximately $2.5 million of additional interest
expense was recognized in the quarter ended June 30, 2003. After the partial redemption of the 8 7/8% Notes, we continue to owe $85.0
million in aggregate principal amount of the 8 7/8% Notes and $150.0 million in
aggregate principal amount of the 3.75% Notes, for a total aggregate principal
amount of $235.0 million for both classes of senior notes. Our annual interest
expense will be reduced by approximately $9.5 million as a result of the
refinancing, including approximately $9.0 million of cash savings. The net effect on working capital of this refinancing was a reduction of
$23.8 million consisting of a $15.0 million net reduction in debt outstanding,
$4.9 million in a redemption premium paid on the 8 7/8% Notes and $3.9 million in
financing costs related to the issuance of the 3.75% Notes. Capital
expenditures of $35.1 million during the year also contributed to the decrease
in working capital. Capital expenditures included the cash purchase of two
diesel electric SCR rigs for $9.0 million. 3.75% Notes The 3.75% Notes bear interest at 3.75% per annum and mature on May 7,
2023. The 3.75% Notes are convertible into shares of our common stock, upon
the occurrence of certain events, at a conversion price of $6.45 per share,
which is equal to a conversion rate of approximately 155.0388 shares per $1,000
principal amount of 3.75% Notes, subject to adjustment. We will pay contingent
interest at a rate equal to 0.5% per annum during any
six-month period, with the initial six-month period commencing May 7,
2008, if the average trading price of the 3.75% Notes per $1,000 principal
amount for the five day trading period ending on the third day immediately
preceding the first day of the applicable six-month period equals $1,200 or
more. The 3.75% Notes are our general unsecured senior obligations and are
fully and unconditionally guaranteed, on a joint and several basis, by all of
our domestic wholly-owned subsidiaries. Non-guarantor subsidiaries are
immaterial. The 3.75% Notes and the guarantees rank equally with our 8 7/8%
Notes. Fees and expenses of approximately $3.9 million incurred at the time of
issuance are being amortized through May 2013, the first date the holders may
require us to repurchase the 3.75% Notes. We may redeem some or all of the
3.75% Notes at any time on or after May 14, 2008, payable in cash, plus accrued
but unpaid interest, including contingent interest, if any, to the date of
redemption at various redemption prices shown in Note 4 to our consolidated
financial statements. Holders may require us to repurchase all or a portion of their 3.75% Notes
on May 7, 2013 or May 7, 2018, and upon a change of control, as defined in the
indenture governing the 3.75% Notes, at 100% of the principal amount of the
3.75% Notes, plus accrued but unpaid interest, including contingent interest,
if any, to the date of repurchase, payable in cash. -21-




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The 3.75% Notes are convertible, at the holders option, prior to the
maturity date into shares of our common stock in the following circumstances:  
    
    during any calendar quarter, if the closing sale price per
share of our common stock for at least 20 trading days in the period
of 30 consecutive trading days ending on the last trading day of the
calendar quarter preceding the quarter in which the conversion
occurs, is more than 110% of the conversion price per share ($7.10
per share) on that 30th trading day;
    
    if we have called the 3.75% Notes for redemption;
    
    during any period that the credit ratings assigned to the
3.75% Notes by both Moodys Investors Service (Moodys) and
Standard & Poors (S&P) Ratings Group are reduced below B1 and B+,
respectively, or if neither rating agency is rating the 3.75% Notes;
    
    during the five trading day period immediately following any
nine consecutive trading day period in which the average trading
price per $1,000 principal amount of the 3.75% Notes for each day of
such period was less than 95% of the product of the closing sale
price per share of our common stock on that day multiplied by the
number of shares of common stock issuable upon conversion of $1,000
principal amount of the 3.75% Notes; or
    
    upon the occurrence of specified corporate transactions,
including a change of control. 
 The 3.75% Notes did not meet the criteria for conversion into common stock
at any time during the year ended December 31, 2003 or through February 10,
2004. At February 10, 2004, the credit ratings assigned to the 3.75% Notes by
Moodys and S&P were B1 and BB-, respectively. 
 The indenture governing the 3.75% Notes does not contain any restriction
on the payment of dividends, the incurrence of indebtedness or the repurchase
of our securities, and does not contain any financial covenants. 8 7/8% Notes At December 31, 2003, we had $85.0 million in aggregate principal amount
of 8 7/8% Notes outstanding. The 8 7/8% Notes, issued in June 1997 and May 1998,
bear interest at 8 7/8% per annum with original maturities on July 1, 2007. The
8 7/8% Notes are our general unsecured senior obligations and are fully and
unconditionally guaranteed, on a joint and several basis, by all of our
domestic wholly-owned subsidiaries. Non-guarantor subsidiaries are immaterial.
The unamortized fees and expenses incurred at the time of issuance related to
the principal amount outstanding are being amortized and discounts are being
accreted over the life of the 8 7/8% Notes. We have the option to redeem the 8 7/8% Notes in whole or in part during the
twelve months beginning July 1, 2003 at 102.9580%, beginning July 1, 2004 at
101.4792% and beginning July 1, 2005 and thereafter at 100.0000% together with
any accrued but unpaid interest to the redemption date. Upon a change of
control as defined in the indentures governing the 8 7/8% Notes, each holder of
the 8 7/8% Notes will have the right to require us to repurchase all or any part
of such holders 8 7/8% Notes at a purchase price equal to 101% of the aggregate
principal amount thereof, plus accrued but unpaid interest to the date of
purchase. We may also, from time-to-time,
seek to retire the 8 7/8% Notes through redemptions, open market purchases
and privately-negotiated transactions. Upon any such transaction, any
difference between the redemption price and the face value of the 8 7/8% Notes
will be recorded as interest expense. The indentures for the 8 7/8% Notes permit us and our subsidiaries to incur
additional indebtedness, including senior indebtedness of up to $100.0 million
aggregate principal amount which may be secured by liens on all of our assets
and the assets of our subsidiaries, subject to certain limitations. The
indentures contain other covenants limiting our ability and our subsidiaries
ability to, among other things, pay dividends or make certain other restricted
payments, make certain investments, incur additional indebtedness, permit
liens, incur dividend and other payment restrictions affecting subsidiaries,
enter into consolidation, merger, conveyance, lease or transfer transactions,
make asset sales, enter into transactions with affiliates or engage in
unrelated lines of business. These covenants are subject to certain exceptions
and qualifications. The indentures consider non-compliance with the
limitations events of default. In addition to non-payment of interest and
principal amounts on the 8 7/8% Notes, the indentures also consider default with
respect to other indebtedness in excess of $10.0 million an event of default.
In the event of a default, the principal and interest could be accelerated upon
written notice by 25% or more of the holders of our 8 7/8% Notes. We are in
compliance with these covenants. -22-




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##### 



CIT Facility Our subsidiary Grey Wolf Drilling Company L.P. has entered into a $75.0
million credit facility with the CIT Group/Business Credit, Inc. (the CIT
Facility) which expires during January 2006. The CIT Facility provides us
with the ability to borrow up to the lesser of $75.0 million or 50% of the
orderly liquidation value (as defined in the agreement) of certain drilling rig
equipment located in the 48 contiguous states of the United States of America.
The CIT Facility is a revolving facility with automatic renewals after
expiration unless terminated by the lender on any subsequent anniversary date
and then only upon 60 days prior notice. Periodic interest payments are due at
a floating rate based upon our debt service coverage ratio within a range of
either LIBOR plus 1.75% to 3.50% or prime plus 0.25% to 1.50%. The CIT
Facility provides up to $20.0 million available for letters of credit. We are
required to pay a commitment fee of 0.375% per annum on the unused portion of
the CIT Facility and letters of credit accrue a fee of 1.25% per annum. The CIT Facility contains affirmative and negative covenants and we are in
compliance with these covenants. Substantially all of our assets, including
our drilling equipment, are pledged as collateral under the CIT Facility which
is also secured by a guarantee of Grey Wolf, Inc. and certain of our
wholly-owned subsidiaries guarantees. However, we retain the option, subject
to a minimum appraisal value, under the CIT Facility to extract $75.0 million
of the equipment out of the collateral pool in connection with the sale or
exchange of such collateral or relocation of equipment outside the contiguous
48 states of the United States of America. We currently have no outstanding
balance under the CIT Facility but had $16.4 million of undrawn letters of
credit at February 10, 2004. These standby letters of credit are for the
benefit of various insurance companies as collateral for premiums and retained
losses which may become payable under the terms of the underlying insurance
contracts and for other purposes. Outstanding letters of credit reduce the
amount available for borrowing under the CIT facility. Among the various covenants that we must satisfy under the CIT Facility
are the following two covenants which apply whenever our liquidity, defined as
the sum of cash, cash equivalents and availability under the CIT Facility,
falls below $25.0 million:  
    
    1 to 1 EBITDA coverage of debt service, tested monthly on a
trailing 12 month basis; and
    
    minimum tangible net worth (as defined in the CIT Facility)
at the end of each quarter will be at least the prior year tangible
net worth less $30.0 million adjusted for quarterly tests. Additionally, if the total amount outstanding under the CIT Facility
(including outstanding letters of credit) exceeds 50% of the orderly
liquidation value of our domestic rigs, we are required to make a prepayment in
the amount of the excess. Also, if the average rig utilization rate falls
below 45% for two consecutive months, the lender will have the option to
request one additional appraisal per year to aid in determining the current
orderly liquidation value of the drilling equipment. Average rig utilization
is defined as the total number of rigs owned which are operating under drilling
contracts in the 48 contiguous states of the United States of America divided
by the total number of rigs owned, excluding rigs not capable of working
without substantial capital investment. Events of default under the CIT
Facility include, in addition to non-payment of amounts due, misrepresentations
and breach of loan covenants and certain other events including:  
    
    default with respect to other indebtedness in excess of $350,000;
    
    judgments in excess of $350,000; or
    
    a change in control which means that we cease to own 100% of
our two principal subsidiaries, some person or group has either
acquired beneficial ownership of 30% or more of the outstanding
common stock of Grey Wolf, Inc. or obtained the power to elect a
majority of our board of directors, or our board of directors ceases
to consist of a majority of continuing directors (as defined by
the CIT Facility). -23-




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##### 



Certain Contractual Commitments The following table summarizes certain of our contractual cash obligations
and related payments due by period at December 31, 2003 (amounts in thousands): Payments Due by
Period(1)Less than
    
    1-3
    
    4-5
    
    After 5Contractual Obligation
    
    Total
    
    1 year
    
    years
    
    years
    
    years3.75%
Notes(2)Principal
    
    $
    150,000
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    150,000Interest
    
    
    109,688
    
    
    
    5,625
    
    
    
    11,250
    
    
    
    11,250
    
    
    
    81,5638 7/8%
Notes(2)Principal
    
    
    85,000
    
    
    
    
    
    
    
    
    
    
    
    85,000
    
    
    
    Interest
    
    
    30,176
    
    
    
    7,544
    
    
    
    15,088
    
    
    
    7,544
    
    
    
    Operating leases
    
    
    944
    
    
    
    674
    
    
    
    257
    
    
    
    13
    
    
    
    Total contractual
cash obligations
    
    $
    375,808
    
    
    $
    13,843
    
    
    $
    26,595
    
    
    $
    103,807
    
    
    $
    231,563
   (1)
    
    This assumes no conversion under, or acceleration of maturity dates due
to redemption, breach of, or default under, the terms of the applicable
contractual obligation.(2)
    
    See 8 7/8% Notes and 3.75% Notes, above, for information relating to
covenants, the breach of which could cause a default under, and
acceleration of, the maturity date. Also see 3.75% Notes for
information related to the holders conversion rights. Our CIT Facility provides up to $20.0 million for the issuance of letters
of credit. If letters of credit which we cause to be issued are drawn upon by
the holders of those letters of credit, then we will become obligated to repay
those amounts along with any accrued interest and fees. Letters of credit
issued reduce the amount available for borrowing under the CIT Facility and, as
a result, we had borrowing capacity of $58.6 million at December 31, 2003. The
following table illustrates the undrawn outstanding standby letters of credit
at December 31, 2003 and the potential maturities if drawn upon by the holders
(amounts in thousands): Payments Due by
Period(1)Total
    
    Less than
    
    1-3
    
    4-5
    
    Over 5Potential Contractual Obligation
    
    Committed
    
    1 year
    
    years
    
    years
    
    yearsStandby letters of credit
    
    $
    16,445
    
    
    $
    
    
    
    $
    16,445
    
    
    $
    
    
    
    $
    Total
    
    $
    16,445
    
    
    $
    
    
    
    
    16,445
    
    
    $
    
    
    
    $
    
   (1)
    
    Assumes no acceleration of maturity date due to breach of, or default
under, the potential contractual obligation. Cash Flow The net cash provided by or used in our operating, investing and financing
activities is summarized below (amounts in thousands): Years Ended December 31,2003
    
    2002
    
    2001Net cash provided by (used in):Operating activities
    
    $
    (7,040
    )
    
    $
    36,403
    
    
    $
    148,312Investing activities
    
    
    (33,927
    )
    
    
    (21,947
    )
    
    
    (101,209
    )Financing activities
    
    
    (18,582
    )
    
    
    (1,224
    )
    
    
    491Net increase (decrease) in cash:
    
    $
    (59,549
    )
    
    $
    13,232
    
    
    $
    47,594
 -24-




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##### 



Our cash flows from operating activities are affected by a number of
factors including the number of rigs working under contract, whether the
contracts are daywork, footage or turnkey, and the rate received for these
services. Our cash flow used in operating activities during the year ended
December 31, 2003 was $7.0 million compared to cash generated from operating
activities during the year ended December 31, 2002 of $36.4 million. While the
number of operating days increased by 10% from 2002 to 2003, our EBITDA per rig
day declined by approximately $645. This decline was due in large part to the
replacement of expiring term contracts with spot market contracts at lower
rates. The lower rig days and EBITDA per rig day contributed to the reduction
in cash flow from operating activities as did the $4.9 million in redemption
premium paid upon partial redemption of the 8 7/8% Notes. Our cash flows from
operating activities were also impacted by changes in current assets and
current liabilities which used $11.1 million and provided $13.0 million in cash
flow for the years ended December 31, 2003 and 2002, respectively. 
 
 Generally, during times of increasing demand, our changes in current
assets and current liabilities will result in the use of cash due primarily to
the build-up of accounts receivable. While there was a small increase in
overall demand in 2003 as compared to 2002, the $13.1 million increase in
accounts receivable year over year was primarily due to the increase in demand
for turnkey services. At the end of 2003, there were eight turnkey wells in
progress while at the end of 2002 there where only four turnkey wells in
progress. This is significant to our cash flow from operations in that we are
generally responsible for significantly more costs while drilling under turnkey
contracts (as opposed to daywork contracts) but we are not compensated
until the contract terms have been completely satisfied. Under daywork
contracts, we bill and are paid as work is performed. 
 
 Another significant change in current assets and current liabilities was
the decrease in accrued interest of $6.5 million. This reduction in accrued
interest is due to the partial redemption of the 8 7/8% Notes and the sale of the
3.75% Notes which lowered our overall interest expense and changed the timing
of our interest payments. 
 
 Our cash flow generated from operating activities during the year ended
December 31, 2002 was $36.4 million compared to cash generated in operating
activities during the year ended December 31, 2001 of $148.3 million. This
change is principally due to a 35% decrease in operating days and a 64%
decrease in our EBITDA per rig day between the two periods. Our cash flows
from operating activities were also impacted by changes in current assets and
current liabilities which provided $13.0 million and used $2.3 million in
cash flow for the years ended December 31, 2002 and 2001, respectively. The change
in current assets and current liabilities during 2002 was primarily due to a
decline in accounts receivable as a direct result of the decline in operating
days and revenues. 
 
 Cash flow used in investing activities for the years ended December 31,
2003, 2002, and 2001 primarily consisted of $35.1 million, 22.3 million, and
$103.0 million of capital expenditures, respectively. These capital
expenditures included betterments and improvements to our rigs, the acquisition
of drill pipe and drill collars, the purchase of top drives, and other capital
items. Also included in capital expenditures in 2003 was the cash purchase of
two diesel electric SCR rigs for $9.0 million. In 2001, capital expenditures
included approximately $55.5 million for the reactivation of cold-stacked and
inventory rigs. 
 Cash flow used in financing activities for the year ended December 31,
2003 consisted of the partial redemption of the 8 7/8% Notes and the sale of the
3.75% Notes, the net effect of which was a reduction in debt outstanding of
$15.0 million. Projected Cash Sources We expect to use cash generated from operations to cover cash
requirements, including debt service on the 3.75% Notes and 8 7/8% Notes and
capital expenditures in 2004. Capital expenditures for 2004 are projected to
be between $27.0 million and $30.0 million, subject to the actual level of rig
activity. We make semi-annual interest payments of $3.8 million on the 8 7/8%
Notes on January 1 and July 1 of each year and semi-annual interest payments of
$2.8 million on the 3.75% Notes on May 7 and November 7 of each year through
the dates of maturity. To the extent that we are unable to generate sufficient
cash from operations we would be required to use cash on hand or draw on our
CIT Facility. At February 10, 2004, our cash and cash equivalent balance was
approximately $57.0 million. From time to time we also review possible acquisition opportunities.
While we currently have no agreements to acquire additional businesses or
equipment, we may enter into such agreements in the future. Our ability to
consummate any such transaction will be dependent in large part on our ability
to fund, primarily through -25-




---



##### 



the capital markets, such a transaction. We cannot
give assurance that adequate funding will be available on satisfactory terms. Results of Operations In accordance with Emerging Issues Task Force Issue No. 01-14 Income
Statement Characterization of Reimbursements Received for Out-of-Pocket
Expenses Incurred, we have revised the presentation of reimbursements received
for certain expenses in the periods presented. These reimbursements are now
included in contract drilling revenues on our consolidated statement of
operations rather than being recorded net of the incurred expenses in drilling
operations expenses. This reclassification had no effect on net income or cash
flows. 
 In the following discussion of the results of our operations and elsewhere
in our filings, we use EBITDA and EBITDA per rig day. EBITDA is a non-GAAP
financial measure under Regulation G of the rules and regulations of the
Securities and Exchange Commission. In accordance with Regulation G, we have
included below a reconciliation of EBITDA to net income (loss), which is the
nearest comparable financial measure. 
 
 We believe that our disclosure of EBITDA per rig day as a measure of rig
operating performance allows investors to make a direct comparison between us
and our competitors, without regard to differences in capital structure or to
differences in the cost basis of our rigs and those of our competitors.
Investors should be aware, however, that there are limitations inherent in
using this performance measure as a measure of overall company profitability
because it excludes significant expense items such as depreciation expense and
interest expense. An improving trend in EBITDA per rig day may not be
indicative of an improvement in our overall profitability. To compensate for
the limitations in utilizing EBITDA per rig day as an operating measure, our
management also uses GAAP measures of performance including operating income
(loss) and net income (loss) to evaluate performance but only with respect to
the company as a whole and not on a per rig basis. 
 2003
    
    2002
    
    2001Earnings before interest, taxes, depreciation
and amortization
    
    $
    30,770
    
    
    $
    40,836
    
    
    $
    176,822Depreciation
    
    
    50,521
    
    
    
    46,601
    
    
    
    41,425Interest expense
    
    
    27,832
    
    
    
    23,928
    
    
    
    24,091Total income tax expense (benefit)
    
    
    (17,383
    )
    
    
    (8,217
    )
    
    
    42,853Net income (loss) applicable to common shares
    
    $
    (30,200
    )
    
    $
    (21,476
    )
    
    $
    68,453
 -26-




---



##### 



The following tables highlight rig days worked, contract drilling revenues
and drilling operating expenses and EBITDA for our daywork and turnkey
operations for the years ended December 31, 2003, 2002 and 2001. 
 For the Year Ended December 31, 2003Daywork
    
    TurnkeyOperations
    
    Operations(1)
    
    
    Total(Dollars in thousands, except averages per rig day worked)Rig days worked
    
    
    18,700
    
    
    
    3,447
    
    
    
    22,147Contract drilling revenue
    
    $
    178,818
    
    
    $
    107,156
    
    
    $
    285,974Drilling operating expenses
    
    
    158,141
    
    
    
    86,146
    
    
    
    244,287General and administrative
expenses(2)
    
    
    10,472
    
    
    
    1,494
    
    
    
    11,966Interest income(2)
    
    
    (812
    )
    
    
    (142
    )
    
    
    (954
    )Gain on sale of assets(2)
    
    
    (69
    )
    
    
    (12
    )
    
    
    (81
    )Provision for asset impairment(2)
    
    
    
    
    
    
    
    
    
    
    Other, net(2)
    
    
    (12
    )
    
    
    (2
    )
    
    
    (14
    )EBITDA
    
    $
    11,098
    
    
    $
    19,672
    
    
    $
    30,770Averages per rig day worked:Contract drilling revenue
    
    $
    9,562
    
    
    $
    31,087
    
    
    $
    12,913EBITDA
    
    $
    593
    
    
    $
    5,707
    
    
    $
    1,389
 For the Year Ended December 31, 2002Daywork
    
    TurnkeyOperations
    
    Operations(1)
    
    
    Total(Dollars in thousands, except averages per rig day worked)Rig days worked
    
    
    18,248
    
    
    
    1,832
    
    
    
    20,080Contract drilling revenue
    
    $
    197,594
    
    
    $
    52,666
    
    
    $
    250,260Drilling operating expenses
    
    
    154,458
    
    
    
    42,112
    
    
    
    196,570General and administrative
expenses(2)
    
    
    10,493
    
    
    
    807
    
    
    
    11,300Interest income(2)
    
    
    (1,575
    )
    
    
    (157
    )
    
    
    (1,732
    )Gain on sale of assets(2)
    
    
    (117
    )
    
    
    (9
    )
    
    
    (126
    )Provision for asset impairment(2)
    
    
    3,121
    
    
    
    419
    
    
    
    3,540Other, net(2)
    
    
    (118
    )
    
    
    (10
    )
    
    
    (128
    )EBITDA
    
    $
    31,332
    
    
    $
    9,504
    
    
    $
    40,836Averages per rig day worked:Contract drilling revenue
    
    $
    10,828
    
    
    $
    28,748
    
    
    $
    12,463EBITDA
    
    $
    1,717
    
    
    $
    5,188
    
    
    $
    2,034
 -27-




---



##### 



For the Year Ended December 31, 2001Daywork
    
    TurnkeyOperations
    
    Operations(1)
    
    
    Total(Dollars in thousands, except averages per rig day worked)Rig days worked
    
    
    28,766
    
    
    
    2,158
    
    
    
    30,924Contract drilling revenue
    
    $
    376,222
    
    
    $
    57,517
    
    
    $
    433,739Drilling operating expenses
    
    
    208,966
    
    
    
    40,362
    
    
    
    249,328General and administrative
expenses(2)
    
    
    9,292
    
    
    
    640
    
    
    
    9,932Interest income(2)
    
    
    (2,272
    )
    
    
    (169
    )
    
    
    (2,441
    )Gain on sale of assets(2)
    
    
    (323
    )
    
    
    (25
    )
    
    
    (348
    )Provision for asset impairment(2)
    
    
    
    
    
    
    
    
    
    
    -Other, net(2)
    
    $
    416
    
    
    $
    30
    
    
    $
    446EBITDA
    
    $
    160,143
    
    
    $
    16,679
    
    
    $
    176,822Averages per rig day worked:Contract drilling revenue
    
    $
    13,079
    
    
    $
    26,657
    
    
    $
    14,026EBITDA
    
    $
    5,567
    
    
    $
    7,728
    
    
    $
    5,718
   (1)
    
    Turnkey operations include the results from turnkey and footage
contracts.(2)
    
    These income and expense items are not contract related and are
allocated between daywork and turnkey based upon operating rig days. Comparison of Fiscal Years ended December 31, 2003 and 2002 
 Our revenue increased by $35.7 million, or 14%, to $286.0 million for the
year ended December 31, 2003, from $250.3 million for the year ended December
31, 2002. At the same time, drilling operating expenses increased by $47.7
million, or 24%, to $244.3 million for the year ended December 31, 2003, from
$196.6 million for the year ended December 31, 2002. While revenues increased
by 14% due to an increase in the number of rig days worked of 10% and an
increase of $450, or 4% in the average revenue per rig day, drilling operating
expenses increased disproportionately by 24%. The disproportionate increase in
drilling operating expenses is due to a change in the mix of rig days worked
under daywork versus turnkey contracts. This is significant to our total
drilling operating costs as we are generally responsible for far greater
operating costs while drilling under turnkey contracts as opposed to daywork
contracts. The disproportionately higher drilling operating expenses
contributed to the $10.1 million, or 25%, decrease in our EBITDA for the year
as did an increase in general and administrative expenses of $666,000 and a
reduction in interest income of $778,000. Our EBITDA was $30.8 million for the
year ended December 31, 2003 compared to $40.8 million for the year ended
December 31, 2002. 
 
 The number of rig days worked under all contracts increased by 2,067, or
10%, to 22,147 for the year ended December 31, 2003 from 20,080 for the year
ended December 31, 2002. Total EBITDA per rig day decreased by $645, or 32%,
to $1,389 for the year ended December 31, 2003, from $ 2,034 for the year ended
December 31, 2002. 
 Daywork Operations 
 Days worked under daywork contracts increased by 452, or 2%, while EBITDA
per rig day declined by $1,124, or 65%, to $593 for the year ended December 31,
2003, from $1,717 for the year ended December 31, 2002. The decrease in EBITDA
per rig day was due primarily to the expiration at the end of 2002 and in 2003
of term contracts that were replaced with spot market contracts at lower rates. 
 Turnkey Operations 
 Days worked under turnkey contracts increased by 1,615, or 88%, while
EBITDA per rig day increased by $519, or 10%, to $5,707 for the year ended
December 31, 2003, from $5,188 for the year ended December 31, 2002. The
increase in EBITDA per rig day was due to differences in the success and
complexity of the wells drilled in 2003 compared to 2002. 
 -28-




---



##### 



Other Depreciation expense increased by $3.9 million, or 8%, to $50.5 million
for the year ended December 31, 2003 compared to $46.6 million for the year
ended December 31, 2002. During the fourth quarter of 2002, we made the
decision not to return five rigs to service and reclassified the component
parts of these rigs to spare equipment, shortening the depreciable lives of
this equipment. In addition, depreciation expense is higher due to capital
expenditures during 2003. General and administrative expenses increased by $666,000, or 6%, to $12.0
million for the year ended December 31, 2003 compared to $11.3 million for the
year ended December 31, 2002. Items affecting general and administrative
expenses include compensation expense in 2003 related to the hiring of our
Executive Vice President and Chief Operating Officer as well as higher
professional fees related to compliance with the Sarbanes-Oxley Act of 2002 and
increases in insurance costs. These items increased expenses by approximately
$1.2 million in 2003. In 2002, severance costs of $330,000 and non-cash
compensation expense of $515,000 related to stock options were recorded as a
result of the termination of employment of an executive officer. Interest expense increased by $3.9 million, or 16%, to $27.8 million for
2003 from $23.9 million for 2002. Interest expense in 2003 includes
approximately $8.5 million of costs associated with the partial redemption of
our 8 7/8% Notes on July 1, 2003 and interest on the $150.0 million aggregate
principal amount of 3.75% Notes issued on May 7, 2003. These costs include a
$4.9 million redemption premium for the 8 7/8% Notes, $2.5 million in accelerated
amortization of a pro-rata portion of the previously deferred financing costs
on the 8 7/8% Notes, and interest on the 3.75% Notes from May 7, 2003 to June 30,
2003. This additional interest expense was partially offset by $4.5 million
lower interest for the last six months of 2003 due to the lower interest rate
on the 3.75% Notes and $15.0 million reduction in principal amount of total
debt outstanding. 
 Our income tax benefit increased by $9.2 million to $17.4 million in 2003
from $8.2 million in 2002. The increase is due to the level of losses and a
change in our estimate of available state tax net operating losses in the
fourth quarter of 2003. This change in estimate increased our income tax
benefit by $938,000. Our income tax benefit is also affected by the annual
amortization of $2.8 million in permanent differences related to differences
between the financial accounting and tax basis of assets purchased in capital
stock acquisitions. The permanent differences are amortized as these assets
are depreciated for financial accounting purposes on a straight-line basis over
their remaining useful lives of approximately nine years at December 31,
2003. As the annual amortization of these permanent differences is a fixed amount,
our book effective tax rate can vary widely based upon the current level of
income or loss. 
 Comparison of Fiscal Years ended December 31, 2002 and 2001 
 Our revenue decreased by $183.5 million, or 42%, to $250.3 million for the
year ended December 31, 2002, from $433.7 million for the year ended December
31, 2001. Drilling operating expenses also decreased by $52.8 million, or 21%,
to $196.6 million for the year ended December 31, 2002, from $249.3 million for
the year ended December 31, 2001. Revenues decreased by 42% due to the
decrease in the number of rig days worked and a decrease in the average revenue
per day. Drilling operating expenses decreased by only 21%. This
disproportionate decrease in drilling operating expenses is due more to the
rapid decline in bid rates in a soft market than issues of cost but was
compounded by the cost of a wage increase of 12% effective June 1, 2001, the
retention of experienced toolpushers and drillers during the downturn, and the
cost of cold stacking rigs. Lower dayrates and higher drilling operating costs
were the primary reasons for the decline in EBITDA of $136.0 million, or 77%,
to EBITDA of $40.8 million for the year ended December 31, 2002, from EBITDA of
$176.8 million for the year ended December 31, 2001. Increases in general and
administrative expenses, a decline in interest income, and a provision for
asset impairment also contributed to the decline in EBITDA. 
 
 Rig days worked under all contracts declined by 10,844, or 35%, to 20,080
for the year ended December 31, 2002 from 30,924 for the year ended December
31, 2001. EBITDA per rig day worked declined by $3,684, or 64%, to $2,034 for
the year ended December 31, 2002, from $5,718 for the year ended December 31,
2001. 
 Daywork Operations 
 Days worked under daywork contracts decreased by 10,518, or 37%, while
EBITDA per rig day declined by $3,850, or 69%, to $1,717 for the year ended
December 31, 2002, from $5,567 for the year ended December 31, 2001. The
decrease in EBITDA per rig day is due to numerous factors affecting contract
drilling revenue and 
 -29-




---



##### 






expenses. Revenue and revenue per rig day decreased due to
the expiration of term contracts that were replaced with spot market contracts
at lower rates. Expenses per rig day increased due to a wage increase of 12%
effective June 1, 2001, the retention of our experienced toolpushers and
drillers during the downturn, the cost of cold-stacking rigs, and overhead and
other fixed costs being spread over less rig days. 
 Turnkey Operations 
 Days worked under turnkey contracts decreased by 326, or 15%,
while EBITDA per rig day decreased by $2,540, or 33%, to $5,188 for the year
ended December 31, 2002, from $7,728 for the year ended December 31, 2001. The
decrease in the EBITDA per rig day was due to differences in the success and
complexity of the wells drilled in 2002 compared to 2001. EBITDA per rig day
worked was also affected by generally lower daywork dayrates in 2002 than in
2001. Lower daywork dayrates can affect the overall turnkey price charged to
customers. 
 Other Depreciation expense increased by $5.2 million, or 12%, to $46.6 million
for the year ended December 31, 2002 compared to $41.4 million for the year
ended December 31, 2001. The increase is primarily due to additional
depreciation attributable to equipment purchased and placed into service during
2001 and 2002. General and administrative expenses increased by $1.4 million, or 14%, to
$11.3 million for the year ended December 31, 2002 compared to $9.9 million for
the year ended December 31, 2001. This increase is due primarily to $330,000
for severance costs and $515,000 of non-cash compensation expense related to
stock options as a result of the termination of employment of an officer in the
first quarter of 2002. Also contributing to the increase are higher insurance
costs and higher professional fees. The difference in interest expense for the years ended December 31, 2002
and 2001 is negligible as the average outstanding debt balance was virtually
the same and the largest component of our debt structure was our 8 7/8% Notes that
carry interest at a fixed rate. Interest income decreased by $709,000, or 29%, to $1.7 million for the
year ended December 31, 2002, from $2.4 million for the year ended December 31,
2001 due to lower interest rates in 2002 partially offset by higher cash
balances. Cash balances were higher in 2002 as a result of an overall build in
cash due to higher drilling activity and dayrates throughout 2001. 
 Net other income (expense) increased by $574,000 to income of $128,000 for
the year ended December 31, 2002, from expense of $446,000 for the same period
of 2001. The expense in 2001 related to the realization of $454,000 in
previously unrealized of foreign currency translation loses as a result of
substantially completing the liquidation of an investment in a foreign
subsidiary. 
 
 We recorded an income tax benefit of $8.2 million in 2002 compared to
income tax expense of $42.9 million in 2001. The change was due to losses
incurred in 2002 and is also affected by the annual amortization of $2.8
million in permanent differences related to differences between the financial
accounting and tax basis of assets acquired in capital stock acquisitions.
The permanent difference are amortized as these assets are depreciated for
financial accounting purposes on a straight-line basis over their remaining
useful lives of approximately 10 years at December 31, 2002. As the annual
amortization of these permanent differences is a fixed amount, our book
effective tax rate varies widely based upon the current levels of income or
loss. 
 Inflation and Changing Prices Contract drilling revenues do not necessarily track the changes in general
inflation as they tend to respond to the level of activity of the oil and gas
industry in combination with the supply of equipment and the number of
competing companies. Capital and operating costs are influenced to a larger
extent by specific price changes in the oil and gas industry and to a lesser
extent by changes in general inflation. -30-




---



##### 



Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Interest Rate Risk. We are subject to market risk exposure related to
changes in interest rates on our CIT Facility. Interest on borrowings under
the CIT facility accrues at a variable rate, using (at our election) either the
prime rate plus 0.25% to 1.50% or LIBOR plus 1.75% to 3.5%, depending upon our
debt service coverage ratio for the trailing 12 month period. We currently
have no outstanding balance under the CIT facility and as such have no exposure
at this time to a change in interest rates. -31-




---



##### 



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to
Consolidated Financial Statements
and Financial Statement Schedule 
 Report of Independent Registered Public Accounting Firm
    
    
    33Consolidated Balance Sheets as of December 31, 2003 and 2002
    
    
    34Consolidated Statements of Operations for the Years
Ended December 31, 2003, 2002, and 2001
    
    
    35Consolidated Statements of Shareholders Equity and Comprehensive Income
for the Years Ended December 31, 2003, 2002, and 2001
    
    
    36Consolidated Statements of Cash Flows for the Years
Ended December 31, 2003, 2002, and 2001
    
    
    37Notes to Consolidated Financial Statements
    
    
    38Financial Statement Schedule:Schedule II  Valuation and Qualifying Accounts
    
    
    51
 
 Schedules other than those listed above are omitted because they are either not
applicable or not required or the information required is included in the
consolidated financial statements or notes thereto. -32-




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##### 



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
 To the Shareholders and Board of Directors
of Grey Wolf, Inc.: We have audited the accompanying consolidated balance sheets of Grey Wolf,
Inc. and Subsidiaries as of December 31, 2003 and 2002, and the related
consolidated statements of operations, shareholders equity and comprehensive
income, and cash flows for each of the years in the three-year period ended
December 31, 2003. In connection with our audits of the consolidated financial
statements, we have also audited the financial statement schedule for the years
ended December 31, 2003, 2002 and 2001. These consolidated financial
statements and financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an opinion on these
consolidated financial statements and financial statement schedule based on our
audits. 
 We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. 
 In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Grey Wolf,
Inc. and Subsidiaries as of December 31, 2003 and 2002, and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 2003, in conformity with accounting principles
generally accepted in the United States of America. Also in our opinion, the
related financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects the information set forth therein. KPMG LLP Houston, Texas
January 30, 2004 -33-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data) December 31,2003
    
    2002ASSETSCurrent assets:Cash and cash equivalents
    
    $
    54,350
    
    
    $
    113,899Restricted cash  insurance deposits
    
    
    749
    
    
    
    784Accounts receivable, net of allowance
of $2,443 and $2,500, respectively
    
    
    60,181
    
    
    
    47,034Prepaids and other current assets
    
    
    4,379
    
    
    
    3,447Total current assets
    
    
    119,659
    
    
    
    165,164Property and equipment:Land, buildings and improvements
    
    
    5,043
    
    
    
    5,424Drilling equipment
    
    
    738,097
    
    
    
    704,734Furniture and fixtures
    
    
    3,332
    
    
    
    3,185Total property and equipment
    
    
    746,472
    
    
    
    713,343Less: accumulated depreciation
    
    
    (342,194
    )
    
    
    (292,552
    )Net property and equipment
    
    
    404,278
    
    
    
    420,791Other noncurrent assets
    
    
    5,141
    
    
    
    4,668$
    529,078
    
    
    $
    590,623LIABILITIES AND SHAREHOLDERS EQUITYCurrent liabilities:Accounts payable  trade
    
    $
    27,893
    
    
    $
    19,460Accrued workers compensation
    
    
    5,295
    
    
    
    4,947Payroll and related employee costs
    
    
    6,660
    
    
    
    6,685Accrued interest payable
    
    
    4,664
    
    
    
    11,160Other accrued liabilities
    
    
    6,420
    
    
    
    8,559Total current liabilities
    
    
    50,932
    
    
    
    50,811Senior notes
    
    
    84,898
    
    
    
    249,613Contingent convertible notes
    
    
    150,000
    
    
    
    Other long-term liabilities
    
    
    4,115
    
    
    
    4,789Deferred income taxes
    
    
    43,496
    
    
    
    60,152Commitments and contingent liabilities
    
    
    
    
    
    
    Shareholders equity:Series B Junior Participating Preferred stock,
$1 par value; 250,000 shares authorized,
none outstanding
    
    
    
    
    
    
    Common stock, $.10 par value; 300,000,000 shares
authorized; 181,283,431 and 181,037,811
issued and
outstanding, respectively
    
    
    18,129
    
    
    
    18,104Additional paid-in capital
    
    
    330,266
    
    
    
    329,712Accumulated deficit
    
    
    (152,758
    )
    
    
    (122,558
    )Total shareholders equity
    
    
    195,637
    
    
    
    225,258$
    529,078
    
    
    $
    590,623
 See accompanying notes to consolidated financial statements -34-




---



##### 



GREY WOLF, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands, except per share data) 
 Years Ended December 31,2003
    
    2002
    
    2001Revenues:Contract drilling
    
    $
    285,974
    
    
    $
    250,260
    
    
    $
    433,739Costs and expenses:Drilling operations
    
    
    244,287
    
    
    
    196,570
    
    
    
    249,328Depreciation
    
    
    50,521
    
    
    
    46,601
    
    
    
    41,425Provision for asset impairment
    
    
    
    
    
    
    3,540
    
    
    
    General and administrative
    
    
    11,966
    
    
    
    11,300
    
    
    
    9,932Gain on sale of assets
    
    
    (81
    )
    
    
    (126
    )
    
    
    (348
    )Total costs and expenses
    
    
    306,693
    
    
    
    257,885
    
    
    
    300,337Operating income (loss)
    
    
    (20,719
    )
    
    
    (7,625
    )
    
    
    133,402
 
 
 Other income (expense):Interest expense
    
    
    (27,832
    )
    
    
    (23,928
    )
    
    
    (24,091
    )Interest income
    
    
    954
    
    
    
    1,732
    
    
    
    2,441Other, net
    
    
    14
    
    
    
    128
    
    
    
    (446
    )Other expense, net
    
    
    (26,864
    )
    
    
    (22,068
    )
    
    
    (22,096
    )Income (loss) before income taxes
    
    
    (47,583
    )
    
    
    (29,693
    )
    
    
    111,306Income tax expense (benefit)Current
    
    
    (938
    )
    
    
    (1,871
    )
    
    
    2,977Deferred
    
    
    (16,445
    )
    
    
    (6,346
    )
    
    
    39,876Total income tax expense (benefit)
    
    
    (17,383
    )
    
    
    (8,217
    )
    
    
    42,853Net income (loss)
    
    $
    (30,200
    )
    
    $
    (21,476
    )
    
    $
    68,453Basic and diluted net income (loss) per
common share
    
    $
    (0.17
    )
    
    $
    (0.12
    )
    
    $
    0.38Basic weighted average common shares
outstanding
    
    
    181,210
    
    
    
    180,936
    
    
    
    180,502Diluted weighted average common shares
outstanding
    
    
    181,210
    
    
    
    180,936
    
    
    
    182,447
 
 See accompanying notes to consolidated financial statements


-35-



---



##### 



GREY WOLF, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY AND COMPREHENSIVE INCOME
(AMOUNTS IN THOUSANDS) Series BJuniorParticipatingPreferred
    
    
    
    
    
    Common
    
    
    
    
    
    
    
    
    
    CumulativeStock
    
    
    
    
    
    Stock
    
    Additional
    
    
    
    
    
    Comprehensive$1 par
    
    Common
    
    $.10 par
    
    Paid-in
    
    
    
    
    
    IncomeValue
    
    Shares
    
    Value
    
    Capital
    
    Deficit
    
    Adjustments
    
    TotalBalance, December 31, 2000
    
    
    
    
    
    
    179,881
    
    
    $
    17,988
    
    
    $
    325,417
    
    
    $
    (169,535
    )
    
    $
    (454
    )
    
    $
    173,416Exercise of stock options
    
    
    
    
    
    
    845
    
    
    
    85
    
    
    
    1,597
    
    
    
    
    
    
    
    
    
    
    
    1,682Tax benefit of stock
option exercises
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,292
    
    
    
    
    
    
    
    
    
    
    
    1,292Cumulative foreign
translation losses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    454
    
    
    
    454Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    68,453
    
    
    
    
    
    
    
    68,453Comprehensive net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    68,453
    
    
    
    454
    
    
    
    68,907Balance, December 31, 2001
    
    
    
    
    
    
    180,726
    
    
    
    18,073
    
    
    
    328,306
    
    
    
    (101,082
    )
    
    
    
    
    
    
    245,297Exercise of stock options
    
    
    
    
    
    
    312
    
    
    
    31
    
    
    
    655
    
    
    
    
    
    
    
    
    
    
    
    686Non-cash compensation
expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    542
    
    
    
    
    
    
    
    
    
    
    
    542Tax benefit of stock
option exercises
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    209
    
    
    
    
    
    
    
    
    
    
    
    209Comprehensive net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (21,476
    )
    
    
    
    
    
    
    (21,476
    )Balance, December 31, 2002
    
    
    
    
    
    
    181,038
    
    
    
    18,104
    
    
    
    329,712
    
    
    
    (122,558
    )
    
    
    
    
    
    
    225,258Exercise of stock options
    
    
    
    
    
    
    245
    
    
    
    25
    
    
    
    343
    
    
    
    
    
    
    
    
    
    
    
    368Tax benefit of stock
option exercises
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    211
    
    
    
    
    
    
    
    
    
    
    
    211Comprehensive net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (30,200
    )
    
    
    
    
    
    
    (30,200
    )Balance, December 31, 2003
    
    
    
    
    
    
    181,283
    
    
    $
    18,129
    
    
    $
    330,266
    
    
    $
    (152,758
    )
    
    $
    
    
    
    $
    195,637
 See accompanying notes to consolidated financial statements


-36-



---



##### 



GREY WOLF, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands) Years Ended December 31,2003
    
    2002
    
    2001Net income (loss)
    
    $
    (30,200
    )
    
    $
    (21,476
    )
    
    $
    68,453Adjustments to reconcile net income (loss) to
net cash provided by (used in) operating activities:Depreciation
    
    
    50,521
    
    
    
    46,601
    
    
    
    41,425Provision for asset impairment
    
    
    
    
    
    
    3,540
    
    
    
    Non-cash compensation expense
    
    
    
    
    
    
    542
    
    
    
    Provision for doubtful accounts
    
    
    
    
    
    
    700
    
    
    
    695Gain on sale of assets
    
    
    (81
    )
    
    
    (126
    )
    
    
    (348
    )Foreign exchange (gain) loss
    
    
    (14
    )
    
    
    (128
    )
    
    
    446Deferred income taxes
    
    
    (16,656
    )
    
    
    (6,555
    )
    
    
    38,584Accretion of debt discount
    
    
    285
    
    
    
    86
    
    
    
    86Tax benefit of stock options exercises
    
    
    211
    
    
    
    209
    
    
    
    1,292(Increase) decrease in restricted cash
    
    
    35
    
    
    
    100
    
    
    
    (25
    )(Increase) decrease in accounts receivable
    
    
    (13,147
    )
    
    
    19,840
    
    
    
    (6,540
    )(Increase) decrease in other current assets
    
    
    (961
    )
    
    
    (1,691
    )
    
    
    1,248Increase (decrease) in accounts payable trade
    
    
    8,476
    
    
    
    (1,590
    )
    
    
    (4,586
    )Increase (decrease) in accrued workers compensation
    
    
    348
    
    
    
    352
    
    
    
    (210
    )Increase (decrease) in other current liabilities
    
    
    (8,660
    )
    
    
    (4,997
    )
    
    
    3,888Increase in other
    
    
    2,803
    
    
    
    996
    
    
    
    3,904Cash provided by (used in) operating activities
    
    
    (7,040
    )
    
    
    36,403
    
    
    
    148,312Cash flows from investing activities:Property and equipment additions
    
    
    (35,102
    )
    
    
    (22,335
    )
    
    
    (103,036
    )Proceeds from sales of equipment
    
    
    1,175
    
    
    
    388
    
    
    
    1,827Cash used in investing activities
    
    
    (33,927
    )
    
    
    (21,947
    )
    
    
    (101,209
    )Cash flows from financing activities:Proceeds from long-term debt
    
    
    146,625
    
    
    
    
    
    
    
    Repayments of long-term debt
    
    
    (165,000
    )
    
    
    (1,910
    )
    
    
    (911
    )Financing costs
    
    
    (575
    )
    
    
    
    
    
    
    (280
    )Proceeds from exercise of stock options
    
    
    368
    
    
    
    686
    
    
    
    1,682Cash provided by (used in) financing activities
    
    
    (18,582
    )
    
    
    (1,224
    )
    
    
    491Net increase (decrease) in cash and cash equivalents
    
    
    (59,549
    )
    
    
    13,232
    
    
    
    47,594Cash and cash equivalents, beginning of year
    
    
    113,899
    
    
    
    100,667
    
    
    
    53,073Cash and cash equivalents, end of year
    
    $
    54,350
    
    
    $
    113,899
    
    
    $
    100,667Supplemental Cash Flow DisclosureCash paid for interest:
    
    $
    30,510
    
    
    $
    22,817
    
    
    $
    22,750Cash paid for (refund of) taxes:
    
    $
    (879
    )
    
    $
    (1,822
    )
    
    $
    3,019
 See accompanying notes to consolidated financial statements


-37-



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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Summary of Significant Accounting Policies Nature of Operations. Grey Wolf, Inc. is a Texas corporation formed in
1980. Grey Wolf, Inc. is a holding company with no independent assets or
operations but through its subsidiaries is engaged in the business of providing
onshore contract drilling services to the oil and gas industry. Grey Wolf,
Inc., through its subsidiaries, currently conducts operations in Alabama,
Arkansas, Louisiana, Mississippi, New Mexico, Texas and Wyoming. The
consolidated financial statements include the accounts of Grey Wolf, Inc. and
its majority-owned subsidiaries (the Company or Grey Wolf). All
significant intercompany accounts and transactions are eliminated in
consolidation. Property and Equipment. Property and equipment are stated at cost.
Depreciation is calculated using the straight-line method over the estimated
useful lives of the assets, between three and fifteen years. Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of.
The Company reviews its long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Impairment of assets to be held and used is determined by a
comparison of the carrying amount of an asset to undiscounted future net cash
flows expected to be generated by an asset. If such assets are considered to
be impaired, the impairment to be recognized is measured by an amount by which
the carrying amount of the assets exceeds the fair value of the assets. Assets
to be disposed of are reported at the lower of the carrying amount or fair
value less costs to sell. During the fourth quarter of 2002, we recorded a
pretax non-cash asset impairment charge of $3.5 million (see Note 12). 
 Revenue Recognition. Contract drilling revenues are earned under daywork,
turnkey and footage contracts. Revenue from daywork and footage contracts is
recognized when it is realized or realizable and earned. On daywork contracts
revenue is recognized based on the number of days completed at fixed rates
stipulated by the contract. On footage contracts revenue is recognized based
on the number of feet that have been drilled at fixed rates stipulated by the
contract. Revenue from turnkey drilling contracts is recognized using the
percentage-of-completion method based upon costs incurred to date and estimated
total contract costs. Provision is made currently for anticipated losses, if
any, on uncompleted contracts 
 Earnings per Share. Basic earnings per share is based on the weighted
average shares outstanding, during the applicable period, without any dilutive
effects considered. Diluted earnings per share reflects dilution from all
outstanding options and shares issuable upon the conversion of the 3.75%
Contingent Convertible Senior Notes once a contingency has been met. The
following is a reconciliation of basic and diluted weighted average common
shares outstanding (in thousands): 2003
    
    2002
    
    2001Weighted average common shares
outstanding  basic
    
    
    181,210
    
    
    
    180,936
    
    
    
    180,502Effect of dilutive securities:Options  Treasury Stock Method
    
    
    
    
    
    
    
    
    
    
    1,945Weighted average common shares
outstanding  diluted
    
    
    181,210
    
    
    
    180,936
    
    
    
    182,447
 In 2003, the Company has excluded approximately 23.3 million shares
issuable upon conversion of the 3.75% Contingent Convertible Senior Notes as
none of the contingencies have been met (see Note 4). The Company incurred net
losses for the years ended December 31, 2003 and 2002 and has, therefore,
excluded certain securities from the computation of diluted earnings per share
as the effect would be anti-dilutive. Securities excluded from the computation
of diluted earnings per share for the years ended December 31, 2003 and 2002
were options to purchase 10.2 million shares and 8.7 million shares,
respectively. Options to purchase 4.1 million shares for the three months
ended December 31, 2001 and September 30, 2001 and 998,500 shares for the three
months


-38-



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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ended June 30, 2001 and March 31, 2001 were not included in the
computation of diluted EPS because the options exercise price was greater than
the average market price of the common shares.

Income Taxes. The Company records deferred tax liabilities utilizing an
asset and liability approach. This method gives consideration to the future
tax consequences associated with differences between the financial accounting
and tax basis of assets and liabilities. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period that
includes the enactment date. The Company and its domestic subsidiaries file a
consolidated federal income tax return.

Stock-Based Compensation. In December 2002, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting Standard
(SFAS) No. 148, Accounting for Stock-Based Compensation-Transition and
Disclosure, which amends SFAS No. 123, Accounting for Stock-Based
Compensation, by providing alternative methods of transition for a voluntary
change to the fair value method of accounting for stock-based employee
compensation. In addition, SFAS No. 148 amends the provisions of SFAS No. 123
to require more prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results of operations. The
Company has adopted the more prominent disclosures required by SFAS No. 148 as
of March 31, 2003; however, as permitted under SFAS No. 123, the Company
continues to apply Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees, and related interpretations in
accounting for its stock option plans. These plans are more fully described in
Note 5.

Accordingly, no compensation expense has been recognized for stock option
grants as all options granted had an exercise price equal to the market value
of the underlying common stock on the date of grant. Had compensation expense
for the stock option grants been determined on the fair value at the grant
dates consistent with the method of SFAS No. 123, the Companys net loss and
loss per share would have been adjusted to the pro forma amounts indicated
below (amounts in thousands, except per share amounts):

2003
    
    2002
    
    2001Net income (loss), as reported
    
    $
    (30,200
    )
    
    $
    (21,476
    )
    
    $
    68,453Add: Stock-based employee compensation
expense included in reporting net
loss, net of related tax effects
    
    
    
    
    
    
    407
    
    
    
    Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards, net of related tax effects
    
    
    (2,523
    )
    
    
    (2,249
    )
    
    
    (1,562
    )Pro forma net income (loss)
    
    $
    (32,723
    )
    
    $
    (23,318
    )
    
    $
    66,891Income (loss) per share  basic and dilutedAs reported
    
    $
    (0.17
    )
    
    $
    (0.12
    )
    
    $
    0.38Pro forma
    
    $
    (0.18
    )
    
    $
    (0.13
    )
    
    $
    0.37


For purposes of determining compensation costs using the provisions of
SFAS No. 123, the fair value of option grants was determined using the
Black-Scholes option-valuation model. The weighted average fair value per
share of stock options granted was $2.36 in 2003, $1.80 in 2002 and $3.90 in
2001. The key input variables used in valuing the options granted in 2003,
2002 and 2001 were: risk-free interest rate based on five-year Treasury strips
of 2.89% to 3.35% in 2003, 2.62% in 2002, and 4.60% in 2001; dividend yield of
zero in each year; stock price volatility of 66% to 71% for 2003 and 75% for
both 2002 and 2001; and expected option lives of five years for each year
presented.

-39-



---



##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Fair Value of Financial Instruments. The carrying amount of the Companys
cash and short-term investments approximates fair value because of the short
maturity of those instruments. The carrying amount of the Companys credit
facility approximates fair value as the interest is indexed to the prime rate
or LIBOR. The fair value of the 8 7/8% Senior Notes at December 31, 2003 and 2002
was $87.6 million and $252.5 million, respectively, compared to the face value
of $85.0 million and $250.0 million, respectively. The fair value of the 3.75%
Contingent Convertible Senior Notes was $141.2 million at December 31, 2003
versus a face value of $150.0 million. Fair value was estimated based on
quoted market prices. Cash Flow Information. Cash flow statements are prepared using the
indirect method. The Company considers all unrestricted highly liquid
investments with a maturity of three months or less at the time of purchase to
be cash equivalents. Restricted Cash. Restricted cash consists of investments in interest
bearing certificates of deposit which are used as collateral for letters of
credit securing insurance deposits and other purposes. The carrying value of
the investments approximates the current market value. Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
requires the use of certain estimates and assumptions relating to the reporting
of assets and liabilities and the disclosure of contingent assets and
liabilities. Actual results could differ from those estimates. Concentrations of Credit Risk. Substantially all of the Companys
contract drilling activities are conducted with major and independent oil and
gas companies in the United States. Historically, the Company has not required
collateral or other security for the related receivables from such customers.
However, the Company has required certain customers to deposit funds in escrow
prior to the commencement of drilling. Actions typically taken by the Company
in the event of nonpayment include filing a lien on the customers producing
properties and filing suit against the customer. Comprehensive Income. Comprehensive income includes all changes in a
companys equity during the period that result from transactions and other
economic events, other than transactions with its shareholders. Recent Accounting Pronouncements. In June 2001, the FASB issued SFAS No.
143, Accounting for Asset Retirement Obligations, which addressed financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. This
statement applies to all entities that have legal obligations associated with
the retirement of long-lived assets that result from the acquisition,
construction, development or normal use of the asset. SFAS 143 is effective
for fiscal years beginning after June 15, 2002. The Company adopted SFAS No.
143 on January 1, 2003. The adoption of SFAS No. 143 did not have an effect on
the Companys financial condition or results of operations for the year ended
December 31, 2003. In April, 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44 and 64, Amendment to FASB Statement No. 13, and Technical
Corrections. Under the provisions of this statement, gains and losses from
extinguishment of debt generally will no longer be classified as extraordinary
items. In addition, this statement eliminates an inconsistency between the
required accounting for sale-leaseback transactions and the required accounting
for certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. This statement also makes various technical
corrections, clarifies meanings, or describes their applicability under changed
conditions. The Company adopted SFAS No. 145 on January 1, 2003. The adoption
of SFAS No. 145 did not have a material effect on the Companys financial
position or results of operations for the year ended December 31, 2003. In July 2002, the FASB issued SFAS No. 146, Accounting for Cost
Associated with Exit or Disposal Activities. SFAS No. 146 is effective for
exit or disposal activities that are initiated after
December 31, 2002. The
Statement addresses financial accounting and reporting for costs associated
with exit or disposal activities and requires companies to recognize costs
associated with exit or disposal activities when they are incurred rather than
at -40-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS the date of a commitment to an exit or disposal plan. SFAS No. 146
nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring). The adoption of SFAS
No. 146 did not have an effect on the Companys financial position or results
of operations for the year ended December 31, 2003. The FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities, in April 2003. SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities. SFAS No. 149 is effective for existing contracts and
new contracts entered into after June 30, 2003. The provisions of SFAS No. 149
did not have a material impact on the Companys consolidated financial
statements for the year ended December 31, 2003. The FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity, in May 2003.
SFAS No. 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. SFAS No. 150 is effective for financial instruments entered into or
modified after May 31, 2003 and is otherwise effective at the beginning of the
first interim period beginning after June 15, 2003. The provisions of SFAS No.
150 did not have a material impact on the Companys consolidated financial
statements for the year ended December 31, 2003. The FASB issued Interpretation (FIN) No. 45, Guarantors Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others, in November 2002. FIN No. 45 is applicable on a
prospective basis for initial recognition and measurement provisions to
guarantees issued after December 2002. FIN No. 45 requires a guarantor to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligations undertaken in issuing the guarantee and expands the required
disclosures to be made by the guarantor about its obligation under certain
guarantees that it has issued. The adoption of FIN No. 45 did not have a
material impact on the Companys financial position or results of operations
for the year ended December 31, 2003. 
 In January 2003, the FASB issued FIN 46, Consolidation of Variable
Interest Entities. In December 2003, the FASB issued a revised version of FIN
46. FIN 46 clarifies existing accounting literature regarding the
consolidation of entities in which a company holds a controlling financial
interest. A majority voting interest in an entity has generally been
considered indicative of a controlling financial interest. FIN 46 specifies
other factors (variable interests) which must be considered when determining
whether a company holds a controlling financial interest in, and therefore must
consolidate, an entity (variable interest entities). The provisions of FIN
46, as revised, are effective for the first reporting period ending after March
15, 2004. The Company will adopt the provisions of FIN 46 for the quarter
ending March 31, 2004, and does not expect that such adoption will have an
effect on its consolidated financial statements. 
 Reclassification. In accordance with Emerging Issues Task Force Issue No.
01-14 Income Statement Characterization of Reimbursements Received for
Out-of-Pocket Expenses Incurred, the Company has revised the presentation of
reimbursements received for certain expenses in the periods presented. These
reimbursements are now included in contract drilling revenues on the income
statement versus previously being recorded net of the incurred expenses in
drilling operations expenses. This reclassification had no effect on net
income or cash flows. In addition, certain other amounts in 2001 and 2002 have
been reclassified to conform to the presentation in 2003. (2) Significant Property Transactions On June 4, 2003, the Company purchased two working rigs for an aggregate
of $9.0 million in cash. One of the rigs purchased is a 1,200 horsepower
diesel electric SCR rig capable of drilling to 17,000 feet and the other is a
1,000 horsepower diesel electric SCR rig capable of drilling to 15,000 feet. During the second quarter of 2001, the Company moved its five Venezuela
rigs to the United States and in the third quarter of 2001 sold three of the
five rigs for an aggregate of $1.3 million. This sale resulted in a gain of -41-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS approximately $602,000. As a result of moving its Venezuela rigs to the
United States, the Company realized $454,000 of previously unrealized foreign
currency translation losses during the second quarter of 2001. (3) Income Taxes The Company and its U.S. subsidiaries file consolidated federal income tax
returns. The components of the provision for income taxes consisted of the
following (amounts in thousands): For the Years Ended December 31,2003
    
    2002
    
    2001CurrentFederal
    
    $
    
    
    
    $
    (1,871
    )
    
    $
    1,870State
    
    
    (938
    )
    
    
    
    
    
    
    1,107$
    (938
    )
    
    $
    (1,871
    )
    
    $
    2,977DeferredFederal
    
    $
    (14,958
    )
    
    $
    (7,080
    )
    
    $
    38,557State
    
    
    (1,487
    )
    
    
    734
    
    
    
    1,319$
    (16,445
    )
    
    $
    (6,346
    )
    
    $
    39,876
 Deferred income taxes are determined based upon the difference between the
carrying amount of assets and liabilities for financial reporting purposes and
amounts used for income tax purposes, and net operating loss and tax credit
carryforwards. The tax effects of the Companys temporary differences and
carryforwards are as follows (amounts in thousands): Years Ended December 31,2003
    
    2002Deferred tax assetsNet operating loss carryforwards
    
    $
    47,964
    
    
    $
    27,008Tax credit carryforwards
    
    
    14
    
    
    
    14Workers compensation accruals
    
    
    3,501
    
    
    
    3,622Other
    
    
    1,411
    
    
    
    1,22952,890
    
    
    
    31,873Deferred tax liabilitiesDepreciation
    
    
    96,386
    
    
    
    92,025Net deferred tax liability
    
    $
    43,496
    
    
    $
    60,152
 At December 31, 2003 and 2002, the Company had U.S. net operating loss
(NOL) carryforwards of $154.5 million and $98.2 million, respectively, which
expire at various times from 2010 through 2023. The NOL carryforwards are
subject to annual limitations as a result of the changes in ownership of the
Company in 1989, 1994 and 1996. Management believes it is more likely than not
that future earnings and reversal of deferred tax liabilities will be
sufficient to permit the Company to realize its deferred tax assets. For financial reporting purposes, approximately $21.0 million of the NOL
carryforwards was utilized to offset the book versus tax basis differential in
the recording of the assets acquired in transactions prior to 1999. -42-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following summarizes the differences between the federal statutory tax
rate of 35% (amounts in thousands): 
 For the Years Ended December 31,2003
    
    2002
    
    2001Income tax expense (benefit) at statutory rate
    
    $
    (16,654
    )
    
    $
    (10,393
    )
    
    $
    38,957Increase (decrease) in taxes resulting from:Permanent differences, primarily due to
basis differences in assets that
were purchased in capital stock
acquisitions
    
    
    1,208
    
    
    
    1,707
    
    
    
    1,320Foreign (income) loss
    
    
    17
    
    
    
    (12
    )
    
    
    95State taxes, net
    
    
    (1,576
    )
    
    
    477
    
    
    
    1,576Other
    
    
    (378
    )
    
    
    4
    
    
    
    905Income tax expense (benefit)
    
    $
    (17,383
    )
    
    $
    (8,217
    )
    
    $
    42,853
 
 (4) Long-Term Debt Long-term debt consists of the following (amounts in thousands): December 31,2003
    
    2002Senior notes due July 2007, general unsecured senior
obligations guaranteed by the Companys domestic
subsidiaries, bearing interest at 8 7/8% per annum
payable semi-annually
    
    $
    84,898
    
    
    $
    249,613Contingent convertible senior notes due May 2023,
general unsecured senior obligations guaranteed by
the Companys domestic subsidiaries, bearing interest
at 3.75% per annum payable semi-annually
    
    
    150,000
    
    
    
    234,898
    
    
    
    249,613Less current maturities
    
    
    
    
    
    
    Long-term debt
    
    $
    234,898
    
    
    $
    249,613
 3.75% Contingent Convertible Senior Notes due May 2023. On May 7, 2003, the Company issued $150.0 million aggregate principal
amount of 3.75% Contingent Convertible Senior Notes due 2023 (the 3.75%
Notes) in a private offering that yielded net proceeds of $146.6 million. The
3.75% Notes bear interest at 3.75% per annum and mature on May 7, 2023. The
3.75% Notes are convertible, upon the occurrence of certain events, at a
conversion price of $6.45 per share, which is equal to a conversion rate of
approximately 155.0388 shares per $1,000 principal amount of the 3.75% Notes,
subject to adjustment. The Company will pay contingent interest at a rate
equal to 0.50% per annum during any six-month period, with the initial
six-month period commencing May 7, 2008, if the average trading price of the
3.75% Notes per $1,000 principal amount for the five day trading period ending
on the third day immediately preceding the first day of the applicable
six-month period equals $1,200 or more. The 3.75% Notes are general unsecured
senior obligations of the Company and are fully and unconditionally guaranteed,
on a joint and several basis, by all domestic wholly-owned subsidiaries of the
Company. Non-guarantor subsidiaries are immaterial. The 3.75% Notes and the
guarantees rank equally with the Companys 8 7/8% Notes due July 2007 (the 8 7/8%
Notes). Fees and -43-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS expenses of $3.9 million incurred at the time of issuance are being
amortized through May 2013, the first date the holders may require the Company
to repurchase the 3.75% Notes. The Company may redeem some or all of the 3.75% Notes at any time on or
after May 14, 2008, at a redemption price shown below, payable in cash, plus
accrued but unpaid interest, including contingent interest, if any, to the date
of redemption: RedemptionPeriod
    
    PriceMay 14, 2008 through May 6, 2009
    
    
    101.88
    %May 7, 2009 through May 6, 2010.
    
    
    101.50
    %May 7, 2010 through May 6, 2011.
    
    
    101.13
    %May 7, 2011 through May 6, 2012.
    
    
    100.75
    %May 7, 2012 through May 6, 2013.
    
    
    100.38
    %May 7, 2013 and thereafter
    
    
    100.00
    %
 Holders may require the Company to repurchase all or a portion of the
3.75% Notes on May 7, 2013 or May 7, 2018, and upon a change of control, as
defined in the indenture governing the 3.75% Notes, at 100% of the principal
amount of the 3.75% Notes, plus accrued but unpaid interest, including
contingent interest, if any, to the date of repurchase, payable in cash. The 3.75% Notes are convertible, at the holders option, prior to the
maturity date into shares of our common stock under the following
circumstances:  
    
    during any calendar quarter, if the closing sale price per
share of our common stock for at least 20 trading days in the period
of 30 consecutive trading days ending on the last trading day of the
calendar quarter preceding the quarter in which the conversion
occurs, is more than 110% of the conversion price per share ($7.10
per share) on that 30th trading day;
    
    if the Company has called the 3.75% Notes for redemption;
    
    during any period that the credit ratings assigned to the
3.75% Notes by both Moodys Investors Service and Standard & Poors
Ratings Group are reduced below B1 and B+, respectively, or if
neither rating agency is rating the 3.75% Notes;
    
    during the five trading day period immediately following any
nine consecutive trading day period in which the average trading
price per $1,000 principal amount of the 3.75% Notes for each day of
such period was less than 95% of the product of the closing sale
price per share of the Companys common stock on that day multiplied
by the number of shares of common stock issuable upon conversion of
$1,000 principal amount of the 3.75% Notes; or upon the occurrence
of specified corporate transactions, including a change of control. The 3.75% Notes did not meet the criteria for conversion into common stock
at any time during the year ended December 31, 2003. At February 10, 2004, the
credit ratings assigned to the 3.75% Notes by Moodys Investor Service and
Standard & Poors Ratings Group were B1 and BB-, respectively. 8 7/8% Notes due July 2007. At December 31, 2003, the Company had $85.0 million in principal amount of
8 7/8% Notes outstanding. The 8 7/8% Notes bear interest at 8 7/8% per annum and mature
on July 1, 2007. The 8 7/8% Notes are general unsecured senior obligations of the
Company and are fully and unconditionally guaranteed, on a joint and several
basis, by all domestic wholly-owned subsidiaries of the Company. Non-guarantor
subsidiaries are immaterial. On July 1, 2003, the $146.6 million of net proceeds from the issuance of
the 3.75% Notes plus $30.6 million of available cash were used to redeem $165.0
million aggregate principal amount of 8 7/8% Notes previously -44-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS outstanding at 102.9580%, plus accrued interest. The redemption premium
of $4.9 million was included in interest expense in the second quarter of 2003.
Amortization of the previously deferred financing costs associated with the
partial redemption of the 8 7/8% Notes on July 1, 2003 was accelerated and
approximately $2.5 million in additional
interest expense was recognized in the
quarter ended June 30, 2003. All other fees and expenses incurred at the time
of issuance are being amortized and discounts are being accreted over the life
of the 8 7/8% Notes. The Company has the option to redeem the 8 7/8% Notes in whole or in part
during the twelve month periods beginning July 1, 2003 at 102.9580%, beginning
July 1, 2004 at 101.4792% and beginning July 1, 2005 and thereafter at
100.0000%, together with any interest accrued and unpaid to the redemption
date. Upon a change of control as defined in the indentures, each holder of
the 8 7/8% Notes will have the right to require the Company to repurchase all or
any part of such holders 8 7/8% Notes at a purchase price equal to 101% of the
aggregate principal amount thereof, plus accrued and unpaid interest to the
date of purchase. We may also, from time to time, seek to retire the 8 7/8% Notes
through redemption, open market purchases and privately negotiated
transactions. Any difference between the redemption price and the face value of
the 8 7/8% Notes will be recorded as interest expense. The indentures for the 8 7/8% Notes permit us and our subsidiaries to incur
additional indebtedness, including senior indebtedness of up to $100.0 million
aggregate principal amount which may be secured by liens on all of our assets
and the assets of our subsidiaries, subject to certain limitations. The
indentures contain other covenants limiting our ability and our subsidiaries
ability to, among other things, pay dividends or make certain other restricted
payments, make certain investments, incur additional indebtedness, permit
liens, incur dividend and other payment restrictions affecting subsidiaries,
enter into consolidation, merger, conveyance, lease or transfer transactions,
make asset sales, enter into transactions with affiliates or engage in
unrelated lines of business. These covenants are subject to certain exceptions
and qualifications. The indentures consider non-compliance with the
limitations events of default. In addition to non-payment of interest and
principal amounts on the 8 7/8% Notes, the indentures also consider default with
respect to other indebtedness in excess of $10.0 million an event of default.
In the event of a default, the principal and interest could be accelerated upon
written notice by 25% or more of the holders of our 8 7/8% Notes. As of December
31, 2003 we are in compliance with these covenants. CIT Facility. The Companys subsidiary Grey Wolf Drilling Company L.P.
has a $75.0 million credit facility with the CIT Group/Business Credit, Inc.
(the CIT Facility) which expires during January 2006. The CIT Facility
provides the Company with the ability to borrow up to the lesser of $75.0
million or 50% of the orderly liquidation value (as defined in the agreement)
of certain drilling rig equipment located in the 48 contiguous states of the
United States of America. The CIT Facility is a revolving facility with
automatic renewals after expiration unless terminated by the lender on any
subsequent anniversary date and then only upon 60 days prior notice. Periodic
interest payments are due at a floating rate based upon the Companys debt
service coverage ratio within a range of either LIBOR plus 1.75% to 3.50% or
prime plus 0.25% to 1.50%. The CIT Facility provides up to $20.0 million
available for letters of credit. The Company is required to pay a commitment
fee of 0.375% per annum on the unused portion of the CIT Facility and letters
of credit accrue a fee of 1.25% per annum. The CIT Facility contains affirmative and negative covenants and the
Company is in compliance with these covenants. Substantially all of the
Companys assets, including its drilling equipment, are pledged as collateral
under the CIT Facility which is also secured by a guarantee of Grey Wolf, Inc.
and certain of the Companys wholly-owned subsidiaries guarantees. The
Company, however, retains the option, subject to a minimum appraisal value,
under the CIT Facility to extract $75.0 million of the equipment out of the
collateral pool in connection with the sale or exchange of such collateral or
relocation of equipment outside the contiguous 48 states of the United States
of America. -45-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Among the various covenants that we must satisfy under the CIT Facility
are the following two covenants which apply whenever our liquidity, defined as
the sum of cash, cash equivalents and availability under the CIT Facility,
falls below $25.0 million.  
    
    1 to 1 EBITDA coverage of debt service, tested monthly on a
trailing 12 month basis; and
    
    minimum tangible net worth (all as defined in the CIT
Facility) at the end of each quarter will be at least the prior year
tangible net worth less $30.0 million adjusted for quarterly tests. Additionally, if the total amount outstanding under the CIT Facility
(including outstanding letters of credit) exceeds 50% of the orderly
liquidation value of our domestic rigs, we are required to make a prepayment in
the amount of the excess. Also, if the average rig utilization rate falls
below 45% for two consecutive months, the lender will have the option to
request one additional appraisal per year to aid in determining the current
orderly liquidation value of the drilling equipment. Average rig utilization
is defined as the total number of rigs owned which are operating under drilling
contracts in the 48 contiguous states of the United States of America divided
by the total number of rigs owned, excluding rigs not capable of working
without substantial capital investment. Events of default under the CIT
Facility include, in addition to non-payment of amounts due, misrepresentations
and breach of loan covenants and certain other events including:  
    
    default with respect to other indebtedness in excess of $350,000;
    
    judgments in excess of $350,000; or
    
    a change in control which means that we cease to own 100% of
our two principal subsidiaries, some person or group has either
acquired beneficial ownership of 30% or more of the Company or
obtained the power to elect a majority of our board of directors, or
our board of directors ceases to consist of a majority of
continuing directors (as defined by the CIT Facility). The Company currently has no outstanding balance under the CIT Facility
and had $16.4 million of undrawn standby letters of credit at December 31,
2003. These standby letters of credit are for the benefit of various insurance
companies as collateral for premiums and retained losses which may become
payable under the terms of the underlying insurance contracts and for other
purposes. Outstanding letters of credit reduce the amount available for
borrowing under the CIT facility. The Company had non-cash activities for the years ended December 31, 2002
and 2001 related to vehicle additions under capital leases. The non-cash
amounts excluded from cash used in investing activities and cash provided by
financing activities were $199,000 and $1.7 million for the years ended
December 31, 2002 and 2001, respectively. (5) Capital Stock and Stock Option Plans On September 21, 1998, the Company adopted a Shareholder Rights Plan (the
Plan) in which rights to purchase shares of Junior Preferred stock will be
distributed as a dividend at the rate of one Right for each share of common
stock. Each Right will entitle holders of the Companys common stock to buy
one-one thousandth of a share of Grey Wolfs Series B Junior Participating
Preferred stock at an exercise price of $11. The Rights will be exercisable
only if a person or group acquires beneficial ownership of 15% or more of Grey
Wolfs common stock or announces a tender or exchange offer upon consummation
of which such person or group would beneficially own 15% or more of Grey Wolfs
common stock. Furthermore, if any person becomes the beneficial owner of 15%
or more of Grey Wolfs common stock, each Right not owned by such person or
related parties will enable its holder to purchase, at the Rights then-current
exercise price, shares of common stock of the Company having a value of twice
the Rights exercise price. The Company will generally be entitled to redeem
the Rights at $.001 per Right at any time until the 10th day following public
announcement that a 15% position has been acquired. -46-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The 2003 Incentive Plan (the 2003 Plan) was approved by shareholders in
May 2003. The 2003 Plan authorizes the grant of the following equity-based
awards:  
    
    incentive stock options;
    
    non-statutory stock options;
    
    restricted shares; and
    
    other stock-based and cash awards. The 2003 Plan replaced the Companys 1996 Employee Stock Option Plan (the
1996 Plan); provided, however that outstanding options previously granted
shall continue to be exercisable subject to the terms and conditions of such
grants. The 1996 Plan allowed for grants of non-statutory options to purchase
common stock, but no further grants of common stock will be made under the 1996
Plan. The 2003 Plan reserves a maximum of 17.0 million shares of the Companys
common stock underlying all equity-based awards, but is reduced by the shares
of common stock subject to previous grants under the 1996 Plan. At December
31, 2003, there were 6.5 million shares of common stock available for grant
under the 2003 Plan until March 2013. Prior to 2003, the Company also granted
options under stock option agreements with its chief executive officer and
directors that are outside of the 2003 Plan. At December 31, 2003, these
individuals had options outstanding to purchase an aggregate of 2.0 million
shares of common stock. The exercise price of stock options approximates the fair market value of
the stock at the time the option is granted. A portion of the outstanding
options became exercisable upon issuance and the remaining become exercisable
in varying increments over three to five-year periods. The options expire on
the tenth anniversary of the date of grant. On November 13, 2001, the Company amended all outstanding stock option
agreements issued under the 1996 Employee Stock Option Plan and certain
outstanding stock option agreements issued to executive officers and directors.
Based upon the occurrence of certain events (triggering events), the
amendments provide for accelerated vesting of options and the extension of the
period in which a current employee option holder has to exercise his options.
The provisions of the amendments provide for accelerated vesting of options
after termination of employment of a current option holder within one year of a
change of control of the Company (as defined in the amendment). Triggering
events that cause an extension of the exercise period, but not longer than the
remaining original exercise period, include termination of employment as a
result of any reason not defined as termination for cause, voluntary
resignation, or retirement in the amendment. In accordance with Accounting Principles Board Opinion 25 (APB 25), the
amendments to the stock option agreements created a new measurement date of
November 13, 2001. APB 25 requires the Company to determine the intrinsic
value of the options at the measurement date and recognize non-cash
compensation expense upon the occurrence of a triggering event. The amount of
compensation expense that would be recognized upon the occurrence of a
triggering event is the difference between the fair market value of the
Companys stock on the measurement date and the original exercise prices of the
options. In March 2002, a triggering event occurred when an officers employment
terminated. As a result, the Company recognized approximately $515,000 of
non-cash compensation expense along with approximately $330,000 of severance
cost. In addition, the Company recognized approximately $27,000 of non-cash
compensation expense during the remainder of 2002. These amounts have been
included in general and administrative expenses on the consolidated statement
of operations. -47-




---



##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Stock option activity for all stock options issued as of December 31,
2003, 2002 and 2001 was as follows (number of shares in thousands): 2003
    
    2002
    
    2001Weighted
    
    
    
    
    
    Weighted
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    Average
    
    
    
    
    
    AverageNo. of
    
    Exercise
    
    No. of
    
    Exercise
    
    No. of
    
    ExerciseShares
    
    Price
    
    Shares
    
    Price
    
    Shares
    
    PriceOutstanding  beginning
of the year
    
    
    8,721
    
    
    $
    2.85
    
    
    
    7,512
    
    
    $
    2.85
    
    
    
    7,318
    
    
    $
    2.25Granted
    
    
    2,161
    
    
    
    3.91
    
    
    
    2,302
    
    
    
    2.88
    
    
    
    1,149
    
    
    
    6.08Exercised
    
    
    (246
    )
    
    
    1.50
    
    
    
    (312
    )
    
    
    2.20
    
    
    
    (846
    )
    
    
    1.99Cancelled
    
    
    (427
    )
    
    
    3.43
    
    
    
    (781
    )
    
    
    3.16
    
    
    
    (109
    )
    
    
    3.16Outstanding  end of year
    
    
    10,209
    
    
    $
    3.09
    
    
    
    8,721
    
    
    $
    2.85
    
    
    
    7,512
    
    
    $
    2.85
 The Company had stock options exercisable at December 31, 2003 of 5.4
million with a range of exercise prices from $.69 to $6.37. At December 31,
2002 and 2001, there were 4.0 million stock options exercisable, with a range
of exercise prices from $0.69 to $6.37, and 3.2 million stock options
exercisable from $0.69 to $4.50, respectively. The following table summarizes information about stock options outstanding
at December 31, 2003: WeightedAverage
    
    WeightedRemaining
    
    AverageNumber
    
    Contractual
    
    ExerciseRange of Exercise Prices
    
    Outstanding
    
    Life(1)
    
    Price$0.69 to $1.63
    
    
    2,674
    
    
    
    3.78
    
    
    $
    1.28$1.75 to $4.38
    
    
    6,516
    
    
    
    7.42
    
    
    
    3.35$4.44 to $6.37
    
    
    1,019
    
    
    
    7.11
    
    
    
    6.1210,209
    
    
    
    6.44
    
    
    $
    3.09
   (1)
    
    Represents weighted average remaining contractual life in
years. (6)     Segment Information and Accumulated Comprehensive Income The Company manages its business as one reportable segment. Although the
Company provides contract drilling services in several markets domestically,
these operations have been aggregated into one reportable segment based on the
similarity of economic characteristics among all markets including the nature
of the services provided and the type of customers of such services. Prior to the third quarter of 2001, the Company managed its business as
two reportable segments; domestic operations and foreign operations. Late in
the first quarter of 1999, the Company suspended all operations in Venezuela
but retained the option to begin operations at any time. However, during the
second quarter of 2001, the Company moved its five Venezuela rigs to the United
States and in the third quarter of 2001 sold three of the five rigs for $1.3
million. This sale resulted in a gain of approximately $602,000. As a result
of moving the Venezuela rigs to the United States, the Company realized
$454,000 of previously unrealized foreign currency translation losses during
the second quarter of 2001. -48-




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##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (7)     Related-Party Transactions The Company performed contract drilling services for affiliates of one of
the Companys directors. Total revenues recognized from these affiliates
during 2003, 2002 and 2001 were $4.1 million, $3.4 million and $6.0 million,
respectively. During 2001, the Company also purchased equipment for $119,000
from an affiliate of the Chairman, President and Chief Executive Officer of the
Company. (8)     Lease Commitments Aggregate minimum lease payments required under noncancellable operating
leases having terms greater than one year are as follows as of December 31,
2003: 2004  $674,000; 2005  $201,000; 2006  $56,000; 2007  $7,000; 2008 -
$7,000; and $0 thereafter. Lease expense under operating leases for 2003, 2002 and 2001 were
approximately $718,000, $680,000 and $618,000, respectively. (9)     Contingencies The Company is involved in litigation incidental to the conduct of its
business, none of which management believes is, individually or in the
aggregate, material to the Companys consolidated financial condition or
results of operations. (10)     Employee Benefit Plan The Company has a defined contribution employee benefit plan covering
substantially all of its employees. The Company matches 100% of the first 3%
of individual employee contributions and 50% of the next 3% of individual
employee contributions. Employer matching contributions under the plan totaled
$873,000, $1.3 million, and $1.3 million for the years ended December 31, 2003,
2002 and 2001, respectively. Participants vest in employer matching
contributions over a five year period based upon service with the Company. (11)     Concentrations Substantially all of the Companys contract drilling activities are
conducted with independent and major oil and gas companies in the United
States. Historically, the Company has not required collateral or other
security to support the related receivables from such customers. However, the
Company has required certain customers to deposit funds in escrow prior to the
commencement of drilling. Actions typically taken by the Company in the event
of nonpayment include filing a lien on the customers producing property and
filing suit against the customer. For the three months ended December 31, 2003, the Company had one customer
which represented approximately 11% of total revenue. For the year ended
December 31, 2002, the Company also had one customer which represented
approximately 11% of total revenue. There were no customers with revenue
greater than 10% for the years ended December 31, 2003 and 2001. (12)     Provision for Asset Impairment 
 During the fourth quarter of 2002, the Company recorded a pre-tax non-cash
asset impairment charge of $3.5 million in accordance with SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. Due to the
deterioration of the physical condition of five of our inventory rigs and
changes in market conditions, it was determined that the rigs based on the
economics, could no longer be returned to service at a reasonable cost that
would have provided an acceptable return, and that the usable component parts
would be included in spare equipment and depreciated over five years. As such,
an asset impairment charge was recorded to write the rigs down to the fair
market value of the useable component parts and the Company revised the number
of drilling rigs in its fleet. The fair market value was based on an appraisal
obtained from a third party appraiser. 
 -49-




---



##### 



GREY WOLF, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (13)     Quarterly Financial Data (unaudited) Summarized quarterly financial data for years ended December 31, 2003,
2002 and 2001 are set forth below (amounts in thousands, except per share
amounts). Quarter EndedMarch
    
    June
    
    September
    
    December2003
    
    2003
    
    2003
    
    2003Revenues
    
    $
    62,387
    
    
    $
    66,949
    
    
    $
    72,383
    
    
    $
    84,255Operating income (loss)
    
    
    (8,414
    )
    
    
    (7,820
    )
    
    
    (7,681
    )
    
    
    3,196Loss before income taxes
    
    
    (14,148
    )
    
    
    (21,921
    )
    
    
    (11,183
    )
    
    
    (331
    )Net income (loss)
    
    
    (9,621
    )
    
    
    (14,185
    )
    
    
    (6,950
    )
    
    
    556Net income (loss) per
common share basic and diluted
    
    
    (0.05
    )
    
    
    (0.08
    )
    
    
    (0.04
    )
    
    
    0.00
 Quarter EndedMarch
    
    June
    
    September
    
    December2002
    
    2002
    
    2002
    
    2002Revenues
    
    $
    64,912
    
    
    $
    62,854
    
    
    $
    61,118
    
    
    $
    61,376Operating income (loss)
    
    
    2,714
    
    
    
    (101
    )
    
    
    (3,025
    )
    
    
    (7,213
    )Loss before income taxes
    
    
    (2,756
    )
    
    
    (5,544
    )
    
    
    (8,626
    )
    
    
    (12,767
    )Net loss
    
    
    (2,177
    )
    
    
    (4,048
    )
    
    
    (6,131
    )
    
    
    (9,120
    )Net loss per common share basic and diluted
    
    
    (0.01
    )
    
    
    (0.02
    )
    
    
    (0.03
    )
    
    
    (0.05
    )
 Quarter EndedMarch
    
    June
    
    September
    
    December2001
    
    2001
    
    2001
    
    2001Revenues
    
    $
    101,136
    
    
    $
    114,967
    
    
    $
    128,030
    
    
    $
    89,606Operating income
    
    
    27,591
    
    
    
    40,479
    
    
    
    45,684
    
    
    
    19,648Income before income taxes
    
    
    22,270
    
    
    
    34,553
    
    
    
    40,268
    
    
    
    14,215Net income
    
    
    13,362
    
    
    
    20,732
    
    
    
    25,378
    
    
    
    8,981Net income per common share basic and diluted
    
    
    0.07
    
    
    
    0.11
    
    
    
    0.14
    
    
    
    0.05
 -50-




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##### 



Schedule II GREY WOLF, INC. AND SUBSIDIARIES Valuation and Qualifying Accounts
(In thousands) Balance at
    
    Additions
    
    Collections
    
    Balance atBeginning
    
    Charged
    
    and
    
    Endof Period
    
    Allowance
    
    Write-Offs
    
    Of PeriodYear Ended December 31, 2001Allowance for doubtful accounts receivable
    
    $
    1,800
    
    
    $
    695
    
    
    $
    (695
    )
    
    $
    1,800Year Ended December 31, 2002Allowance for doubtful accounts receivable
    
    $
    1,800
    
    
    $
    700
    
    
    $
    
    
    
    $
    2,500Year Ended December 31, 2003Allowance for doubtful accounts receivable
    
    $
    2,500
    
    
    $
    
    
    
    $
    (57
    )
    
    $
    2,443
 -51-




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##### 



ITEM
9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM
9A.   CONTROLS AND PROCEDURES As of December 31, 2003, we carried out an evaluation, under the
supervision and with the participation of management, including our Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures pursuant to
Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures are effective. Disclosure controls and procedures are controls and
procedures that are designed to ensure that information required to be
disclosed in our reports filed or submitted under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commissions rules and forms. There have been no significant changes in our internal control over
financial reporting that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting. PART III ITEM 10.     DIRECTORS AND EXECUTIVES OFFICERS OF THE REGISTRANT The information required by this item as to our directors and executive
officers is hereby incorporated by reference to such information appearing
under the captions Directors and Executive Officers in our definitive proxy
statement for our 2004 Annual Meeting of Shareholders and is to be filed with
the Securities and Exchange Commission (the Commission) pursuant to the
Securities Exchange Act of 1934 within 120 days of the end of our fiscal year
on December 31, 2003. ITEM 11.     EXECUTIVE COMPENSATION The information required by this item as to the compensation of our
management is hereby incorporated by reference to such information appearing
under the caption Executive Compensation in our definitive proxy statement
for our 2004 Annual Meeting of Shareholders and is to be filed with the
Commission pursuant to the Securities Exchange Act of 1934 within 120 days of
the end of our fiscal year on December 31, 2003. ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDERS MATTERS The information required by this item as to the ownership by our
management and others of our securities is hereby incorporated by reference to
such information appearing under the caption Nominees for Director,
Ownership by Management and Certain Shareholders and Executive Compensation
Plans in our definitive proxy statement for our 2004 Annual Meeting of
Shareholders and is to be filed with the Commission pursuant to the Securities
Exchange Act of 1934 within 120 days of the end of our fiscal year on December
31, 2003. ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item as to certain business relationships and transactions with our managements and other parties
related to us is hereby incorporated by reference to such information appearing under the caption Certain Transactions in our
definitive proxy statement for our 2004 Annual Meeting
of Shareholders and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days
of the end of our fiscal year on December 31, 2003. -52-




---



##### 



ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this item as to accounting fees and services
is hereby incorporated by reference to such information appearing under the
caption Independent Auditors in our definitive proxy statement for our 2004
Annual Meeting of Shareholders and is to be filed with the Commission pursuant
to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal
year on December 31, 2003. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K  (a)
    
    The following documents are filed as part of this report:  1.
    
    and 2. Financial Statements and Schedule The consolidated financial statements and supplemental schedule of Grey
Wolf, Inc. and Subsidiaries are included in Part II, Item 8 and are
listed in the Index to Consolidated Financial Statements and Financial
Statement Schedule therein.  3.
    
    Exhibits Exhibit No.
    
    
    
    Documents3.1
    
    
    
    
    Articles of Incorporation of Grey Wolf, Inc., as amended
(incorporated herein by reference to Exhibit 3.1 to Form 10-Q dated
May 12, 1999).3.2
    
    
    
    
    By-Laws of Grey Wolf, Inc., as amended (incorporated herein by
reference to Exhibit 99.1 to Form 8-K dated March 23, 1999).4.1
    
    
    
    

Form
of Trust Indenture, dated June 27, 1997, relating to the 8 7/8%
Senior Notes due 2007 by the Company and Texas Commerce Bank
National Association, as Trustee (incorporated herein by reference
to Exhibit 4.2 to the Companys Registration Statement on Form S-3
No. 333-26519 filed June 24, 1997).4.2
    
    
    
    
    Supplemental Indenture (to the Trust Indenture dated June 27,
1997), dated as of March 31, 1998, among the Company, the New
Guarantor, the Existing Guarantors, and Chase Bank of Texas
National Association, as Trustee. (incorporated herein by
reference to Exhibit 4.5 to Form 8-K filed May 21, 1998).4.3
    
    
    
    
    Second Supplemental Indenture (to the Trust Indenture dated June
27, 1997), dated as of May 8, 1998, by and among the Company, the
Guarantors, and Chase Bank of Texas, National Association, as
Trustee (incorporated herein by reference to Exhibit 4.5 to Form
8-K filed May 21, 1998).4.4
    
    
    
    
    Third Supplemental Indenture (to the Trust Indenture dated June 27,
1997), dated as of January 4, 1999, among the Company, the New
Guarantors, the Existing Guarantors, and Chase Bank of Texas,
National Association, as Trustee (incorporated herein by reference
to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).4.5
    
    
    
    

Form
of Trust Indenture, dated May 8, 1998, relating to the 8 7/8%
Senior Notes due 2007 by and among the Company, the Guarantors, and
Chase Bank of Texas, National Association, as Trustee (incorporated
herein by reference to Exhibit 4.3 to Form 8-K filed May 21, 1998).
 -53-
      Exhibit No.
    
    
    
    Documents4.6
    
    
    
    
    Supplemental Indenture (to the Trust Indenture dated May 8, 1998),
dated as of January 4, 1999, among the Company, the New Guarantors,
the Existing Guarantors and Chase Bank of Texas, National
Association, as Trustee (incorporated herein by reference to Grey
Wolf, Inc. Annual Report on From 10-K for the year ended December
31, 2001).4.7
    
    
    
    
    Rights Agreement dated as of September 21, 1998 by and between the
Company and American Stock Transfer and Trust Company as Rights
Agent (incorporated herein by reference to Exhibit 4.1 to Form 8-K
filed September 22, 1998).4.8
    
    
    
    
    Indenture, dated as of May 7, 2003, relating to the 3.75%
Contingent Convertible Senior Notes due 2023 between the Company,
the Guarantors, and JPMorgan Chase Bank, a New York Banking
Corporation, as Trustee (incorporated herein by reference to
Exhibit 4.2 to the Companys Registration Statement on Form S-3 No.
333-106997 filed July 14, 2003).4.9
    
    
    
    
    Supplemental Indenture, dated as of May 22, 2003, relating to the
3.75% Contingent Convertible Senior Notes due 2023 between the
Company, the Guarantors, and JPMorgan Chase Bank, a New York
Banking Corporation, as Trustee (incorporated herein by reference
to Exhibit 4.3 to the Companys Registration Statement on Form S-3
No. 333-106997 filed July 14, 2003).10.1
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated September 3,
1996, by and between the Company and Thomas P. Richards
(incorporated herein by reference to Exhibit 10.2 to Registration
Statement No. 333-14783).10.2
    
    
    
    
    Form of Incentive Stock Option Agreement dated September 3, 1996,
by and between the Company and Ronnie E. McBride (incorporated
herein by reference to Exhibit 10.14 to Post Effective Amendment
No. 1 to Registration Statement No. 333-14783).10.3
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated September 3,
1996, by and between the Company and Ronnie E. McBride.
(incorporated herein by reference to Exhibit 10.15 to Post
Effective Amendment No. 1 to Registration Statement No. 333-14783).10.4
    
    
    
    
    Grey Wolf, Inc. 1996 Employee Stock Option Plan (incorporated
herein by reference to Grey Wolf, Inc. 1996 Annual Meeting of
Shareholders definitive proxy materials).10.5
    
    
    
    
    Grey Wolf Inc. Amendment to 1996 Employee Stock Option Plan
(incorporated herein by reference to Grey Wolf, Inc. 1999 Annual
Meeting of Shareholders definitive proxy materials filed April 9,
1999).10.6
    
    
    
    
    Grey Wolf, Inc. Second Amendment to 1996 Employee Stock Option Plan
dated May 14, 2002 (incorporated herein by reference to Exhibit 4.6
to Grey Wolf, Inc. Registration Statement on Form S-8 No. 333-90888
filed June 21, 2002).10.7
    
    
    
    
    Drillers Inc. 1982 Stock Option and Long-Term Incentive Plan for
Key Employees (incorporated by reference to Drillers Inc. 1982
Annual Meeting definitive proxy solicitation materials).10.8
    
    
    
    
    Form of Incentive Stock Option Agreement dated March 17, 1997, by
and between the Company and Gary D. Lee (incorporated by reference
to DI Industries, inc. Annual Report of Form 10-K for the year
ended December 31, 1996).10.9
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated February 10,
1998, by and between the Company and David W. Wehlmann
(incorporated herein by reference to Grey Wolf, Inc. Annual Report
on Form 10-K for the year ended December 31, 1997).10.10
    
    
    
    
    Revolving Credit Agreement dated as of January 14, 1999 among Grey
Wolf Drilling Company LP (as borrower), Grey Wolf, Inc. (as
guarantor), The CIT Group/Business Credit, Inc. (as agent) and
various financial institutions (as lenders). (incorporated herein
by reference to Exhibit 10.1 to Form 8-K dated January 26, 1999).
 -54-
      Exhibit No.
    
    
    
    Documents10.11
    
    
    
    
    First Amendment to Loan Agreement dated as of December 20, 2001, by
and among Grey Wolf Drilling Company, LP (as borrower) and Grey
Wolf, Inc. (as guarantor) and the CIT Group/Business Credit, Inc.
(as agent) and various financial institutions (as lenders)
(incorporated herein by reference to Grey Wolf, Inc. Annual Report
on Form 10-K for the year ended December 31, 2001).10.12
    
    
    
    
    Second Amendment to Loan Agreement dated as of February 7, 2003 by
and among Grey Wolf Drilling Company L.P. (as borrower), Grey Wolf,
Inc. and various subsidiaries (as guarantors) and the CIT
Group/Business Credit, Inc. and various financial institutions (as
lenders) (incorporated herein by reference to Grey Wolf, Inc.
Annual Report on Form 10-K for the year ended December 31, 2002).10.13
    
    
    
    
    Non-Qualified Stock Option Agreement dated January 16, 1999, by and
between the Company and Edward S. Jacob, III. (incorporated herein
by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the
year ended December 31, 1999).10.14
    
    
    
    
    Form of Amendment to Non-Qualified Stock Option Agreements dated
November 13, 2001, by and between the Company and Thomas P.
Richards (incorporated herein by reference to Grey Wolf, Inc.
Annual Report on Form 10-K for the year ended December 31, 2001).10.15
    
    
    
    
    Form of Amendment to Non-Qualified Stock Option Agreement dated
November 13, 2001, by and among the Company (f.k.a. DI Industries,
Inc.), Thomas P. Richards and Richards Brothers Interests, L.P. (incorporated herein by reference to Grey Wolf, Inc. Annual Report
on Form 10-K for the year ended December 31, 2001).10.16
    
    
    
    
    Form of Amendment to Non-Qualified Stock Option Agreements dated
November 13, 2001, by and between the Company and each of David W.
Wehlmann, Edward S. Jacob III, Gary D. Lee, Ronnie E. McBride,
Merrie S. Costley, and Donald J. Guedry, Jr. (incorporated herein
by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the
year ended December 31, 2001).10.17
    
    
    
    
    Grey Wolf, Inc. Executive Severance Plan effective November 15,
2001 (incorporated herein by reference to Grey Wolf, Inc. Annual
Report on Form 10-K for the year ended December 31, 2001).10.18
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and Thomas P. Richards (incorporated
herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K
for the year ended December 31, 2001).10.19
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and David W. Wehlmann (incorporated
herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K
for the year ended December 31, 2001).10.20
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and Edward S. Jacob III (incorporated
herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K
for the year ended December 31, 2001).10.21
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and Gary D. Lee (incorporated herein by
reference to Grey Wolf, Inc. Annual Report on Form 10-K for the
year ended December 31, 2001).10.22
    
    
    
    
    Employment Agreement effective March 31, 2003 by and between the
Company and William E. Chiles (incorporated herein by reference to
Grey Wolf, Inc. Quarterly Report on Form 10-Q for the quarter ended
March 31, 2003).
 -55-
      Exhibit No.
    
    
    
    Documents10.23
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated as of February
13, 2002, by and between the Company and each of Frank M. Brown,
William T. Donovan, James K.B. Nelson, Robert E. Rose, Steven A.
Webster, and William R. Ziegler (incorporated herein by reference
to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).10.24
    
    
    
    
    Grey Wolf, Inc. 2003 Incentive Plan (incorporated herein by
reference to Grey Wolf, Inc. 2003 Annual Meeting of Shareholders
definitive proxy materials).21.1
    
    
    
    

List
of Subsidiaries of Grey Wolf, Inc (incorporated herein by reference
to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2003).*23.1
    
    
    
    
    Consent of Independent Registered Public Accounting Firm, KPMG LLP*31.1
    
    
    
    
    Certification of Chief Executive Officer pursuant to Rule 13a-14(a).*31.2
    
    
    
    
    Certification of Chief Financial Officer pursuant to Rule 13a-14(a).*32.1
    
    
    
    
    Certification pursuant to 18 U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Thomas
P. Richards, Chairman, President and Chief Executive Officer and
David W. Wehlmann, Executive Vice President and Chief Financial
Officer.
   *
    
    Filed herewith  (b)
    
    Reports on Form 8-K1.
    
    We furnished a Report on Form 8-K under Item 12 with the
Securities and Exchange Commission on October 23, 2003 with regard
to our press release announcing operating results for the quarter
ended September 30, 2003.  2.
    
    We furnished a Report on Form 8-K under Item 12 with the
Securities and Exchange Commission on February 2, 2004 with regard
to our press release announcing operating results for the quarter
and year ended December 31, 2003. -56-
      SIGNATURES 
 Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized, this 9th day of
August, 2004. 
 Grey Wolf, Inc.By:
    /s/ David W. WehlmannDavid W. Wehlmann, Executive Vice President andChief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated. Signatures and Capacities
    
    DateBy:
    
/s/ Thomas P. Richards
    
    
    August 9, 2004Thomas P. Richards, Chairman, President and Chief Executive Officer
(Principal Executive Officer)By:
    
    /s/ David W. Wehlmann
    
    
    August 9, 2004David W. Wehlmann, Executive Vice President and Chief Financial OfficerBy:
    
    /s/ Merrie S. Costley
    
    
    August 9, 2004Merrie S. Costley, Vice President and ControllerBy:
    
    /s/ William R. Ziegler
    
    
    August 9, 2004William R. Ziegler, DirectorBy:
    
    /s/ Frank M. Brown
    
    
    August 9, 2004Frank M. Brown, DirectorBy:
    
    /s/ William T. Donovan
    
    
    August 9, 2004William T. Donovan, DirectorBy:
    
    /s/ James K. B. Nelson
    
    
    August 9, 2004James K. B. Nelson, DirectorBy:
    
    /s/ Robert E. Rose
    
    
    August 9, 2004Robert E. Rose, DirectorBy:
    
    /s/ Steven A. Webster
    
    
    August 9, 2004Steven A. Webster, Director
 -57-
      Index to Exhibit Exhibit No.
    
    
    
    Documents3.1
    
    
    
    
    Articles of Incorporation of Grey Wolf, Inc., as amended
(incorporated herein by reference to Exhibit 3.1 to Form 10-Q dated
May 12, 1999).3.2
    
    
    
    
    By-Laws of Grey Wolf, Inc., as amended (incorporated herein by
reference to Exhibit 99.1 to Form 8-K dated March 23, 1999).4.1
    
    
    
    

Form
of Trust Indenture, dated June 27, 1997, relating to the 8 7/8%
Senior Notes due 2007 by the Company and Texas Commerce Bank
National Association, as Trustee (incorporated herein by reference
to Exhibit 4.2 to the Companys Registration Statement on Form S-3
No. 333-26519 filed June 24, 1997).4.2
    
    
    
    
    Supplemental Indenture (to the Trust Indenture dated June 27,
1997), dated as of March 31, 1998, among the Company, the New
Guarantor, the Existing Guarantors, and Chase Bank of Texas
National Association, as Trustee. (incorporated herein by
reference to Exhibit 4.5 to Form 8-K filed May 21, 1998).4.3
    
    
    
    
    Second Supplemental Indenture (to the Trust Indenture dated June
27, 1997), dated as of May 8, 1998, by and among the Company, the
Guarantors, and Chase Bank of Texas, National Association, as
Trustee (incorporated herein by reference to Exhibit 4.5 to Form
8-K filed May 21, 1998).4.4
    
    
    
    
    Third Supplemental Indenture (to the Trust Indenture dated June 27,
1997), dated as of January 4, 1999, among the Company, the New
Guarantors, the Existing Guarantors, and Chase Bank of Texas,
National Association, as Trustee (incorporated herein by reference
to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).4.5
    
    
    
    

Form
of Trust Indenture, dated May 8, 1998, relating to the 8 7/8%
Senior Notes due 2007 by and among the Company, the Guarantors, and
Chase Bank of Texas, National Association, as Trustee (incorporated
herein by reference to Exhibit 4.3 to Form 8-K filed May 21, 1998).4.6
    
    
    
    
    Supplemental Indenture (to the Trust Indenture dated May 8, 1998),
dated as of January 4, 1999, among the Company, the New Guarantors,
the Existing Guarantors and Chase Bank of Texas, National
Association, as Trustee (incorporated herein by reference to Grey
Wolf, Inc. Annual Report on From 10-K for the year ended December
31, 2001).4.7
    
    
    
    
    Rights Agreement dated as of September 21, 1998 by and between the
Company and American Stock Transfer and Trust Company as Rights
Agent (incorporated herein by reference to Exhibit 4.1 to Form 8-K
filed September 22, 1998).4.8
    
    
    
    
    Indenture, dated as of May 7, 2003, relating to the 3.75%
Contingent Convertible Senior Notes due 2023 between the Company,
the Guarantors, and JPMorgan Chase Bank, a New York Banking
Corporation, as Trustee (incorporated herein by reference to
Exhibit 4.2 to the Companys Registration Statement on Form S-3 No.
333-106997 filed July 14, 2003).4.9
    
    
    
    
    Supplemental Indenture, dated as of May 22, 2003, relating to the
3.75% Contingent Convertible Senior Notes due 2023 between the
Company, the Guarantors, and JPMorgan Chase Bank, a New York
Banking Corporation, as Trustee (incorporated herein by reference
to Exhibit 4.3 to the Companys Registration Statement on Form S-3
No. 333-106997 filed July 14, 2003).10.1
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated September 3,
1996, by and between the Company and Thomas P. Richards
(incorporated herein by reference to Exhibit 10.2 to Registration
Statement No. 333-14783).10.2
    
    
    
    
    Form of Incentive Stock Option Agreement dated September 3, 1996,
by
      Exhibit No.
    
    
    
    Documentsand between the Company and Ronnie E. McBride (incorporated
herein by reference to Exhibit 10.14 to Post Effective Amendment
No. 1 to Registration Statement No. 333-14783).10.3
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated September 3,
1996, by and between the Company and Ronnie E. McBride.
(incorporated herein by reference to Exhibit 10.15 to Post
Effective Amendment No. 1 to Registration Statement No. 333-14783).10.4
    
    
    
    
    Grey Wolf, Inc. 1996 Employee Stock Option Plan (incorporated
herein by reference to Grey Wolf, Inc. 1996 Annual Meeting of
Shareholders definitive proxy materials).10.5
    
    
    
    
    Grey Wolf Inc. Amendment to 1996 Employee Stock Option Plan
(incorporated herein by reference to Grey Wolf, Inc. 1999 Annual
Meeting of Shareholders definitive proxy materials filed April 9,
1999).10.6
    
    
    
    
    Grey Wolf, Inc. Second Amendment to 1996 Employee Stock Option Plan
dated May 14, 2002 (incorporated herein by reference to Exhibit 4.6
to Grey Wolf, Inc. Registration Statement on Form S-8 No. 333-90888
filed June 21, 2002).10.7
    
    
    
    
    Drillers Inc. 1982 Stock Option and Long-Term Incentive Plan for
Key Employees (incorporated by reference to Drillers Inc. 1982
Annual Meeting definitive proxy solicitation materials).10.8
    
    
    
    
    Form of Incentive Stock Option Agreement dated March 17, 1997, by
and between the Company and Gary D. Lee (incorporated by reference
to DI Industries, inc. Annual Report of Form 10-K for the year
ended December 31, 1996).10.9
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated February 10,
1998, by and between the Company and David W. Wehlmann
(incorporated herein by reference to Grey Wolf, Inc. Annual Report
on Form 10-K for the year ended December 31, 1997).10.10
    
    
    
    
    Revolving Credit Agreement dated as of January 14, 1999 among Grey
Wolf Drilling Company LP (as borrower), Grey Wolf, Inc. (as
guarantor), The CIT Group/Business Credit, Inc. (as agent) and
various financial institutions (as lenders). (incorporated herein
by reference to Exhibit 10.1 to Form 8-K dated January 26, 1999).10.11
    
    
    
    
    First Amendment to Loan Agreement dated as of December 20, 2001, by
and among Grey Wolf Drilling Company, LP (as borrower) and Grey
Wolf, Inc. (as guarantor) and the CIT Group/Business Credit, Inc.
(as agent) and various financial institutions (as lenders)
(incorporated herein by reference to Grey Wolf, Inc. Annual Report
on Form 10-K for the year ended December 31, 2001).10.12
    
    
    
    
    Second Amendment to Loan Agreement dated as of February 7, 2003 by
and among Grey Wolf Drilling Company L.P. (as borrower), Grey Wolf,
Inc. and various subsidiaries (as guarantors) and the CIT
Group/Business Credit, Inc. and various financial institutions (as
lenders) (incorporated herein by reference to Grey Wolf, Inc.
Annual Report on Form 10-K for the year ended December 31, 2002).10.13
    
    
    
    
    Non-Qualified Stock Option Agreement dated January 16, 1999, by and
between the Company and Edward S. Jacob, III. (incorporated herein
by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the
year ended December 31, 1999).10.14
    
    
    
    
    Form of Amendment to Non-Qualified Stock Option Agreements dated
November 13, 2001, by and between the Company and Thomas P.
Richards (incorporated herein by reference to Grey Wolf, Inc.
Annual Report on Form 10-K for the year ended December 31, 2001).10.15
    
    
    
    
    Form of Amendment to Non-Qualified Stock Option Agreement dated
November 13, 2001, by and among the Company (f.k.a. DI Industries,
Inc.), Thomas P. Richards and Richards Brothers Interests, L.P
      Exhibit No.
    
    
    
    Documents(incorporated herein by reference to Grey Wolf, Inc. Annual Report
on Form 10-K for the year ended December 31, 2001).10.16
    
    
    
    
    Form of Amendment to Non-Qualified Stock Option Agreements dated
November 13, 2001, by and between the Company and each of David W.
Wehlmann, Edward S. Jacob III, Gary D. Lee, Ronnie E. McBride,
Merrie S. Costley, and Donald J. Guedry, Jr. (incorporated herein
by reference to Grey Wolf, Inc. Annual Report on Form 10-K for the
year ended December 31, 2001).10.17
    
    
    
    
    Grey Wolf, Inc. Executive Severance Plan effective November 15,
2001 (incorporated herein by reference to Grey Wolf, Inc. Annual
Report on Form 10-K for the year ended December 31, 2001).10.18
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and Thomas P. Richards (incorporated
herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K
for the year ended December 31, 2001).10.19
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and David W. Wehlmann (incorporated
herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K
for the year ended December 31, 2001).10.20
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and Edward S. Jacob III (incorporated
herein by reference to Grey Wolf, Inc. Annual Report on Form 10-K
for the year ended December 31, 2001).10.21
    
    
    
    
    Amended and Restated Employment Agreement dated November 13, 2001,
by and between the Company and Gary D. Lee (incorporated herein by
reference to Grey Wolf, Inc. Annual Report on Form 10-K for the
year ended December 31, 2001).10.22
    
    
    
    
    Employment Agreement effective March 31, 2003 by and between the
Company and William E. Chiles (incorporated herein by reference to
Grey Wolf, Inc. Quarterly Report on Form 10-Q for the quarter ended
March 31, 2003).10.23
    
    
    
    
    Form of Non-Qualified Stock Option Agreement dated as of February
13, 2002, by and between the Company and each of Frank M. Brown,
William T. Donovan, James K.B. Nelson, Robert E. Rose, Steven A.
Webster, and William R. Ziegler (incorporated herein by reference
to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended
December 31, 2001).10.24
    
    
    
    
    Grey Wolf, Inc. 2003 Incentive Plan (incorporated herein by
reference to Grey Wolf, Inc. 2003 Annual Meeting of Shareholders
definitive proxy materials).21.1
    
    
    
    
    List of Subsidiaries of Grey Wolf, Inc.
(incorporated herein by
reference to Grey Wolf, Inc. Annual Report on Form 10-K for the
year ended December 31, 2003).*23.1
    
    
    
    
    Consent of Independent Registered Public Accounting Firm, KPMG LLP*31.1
    
    
    
    
    Certification of Chief Executive Officer pursuant to Rule 13a-14(a).*31.2
    
    
    
    
    Certification of Chief Financial Officer pursuant to Rule 13a-14(a).*32.1
    
    
    
    
    Certification pursuant to 18 U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Thomas
P. Richards, Chairman, President and Chief Executive Officer and
David W. Wehlmann, Executive Vice President and Chief Financial
Officer.
 
  
 * Filed herewith