UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 1-8226

GREY WOLF, INC.

Registrant’s telephone number, including area code: 713-435-6100

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

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 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

     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 aggregate market value of the registrant’s voting stock held by non-affiliates on June 30, 2004 based upon the closing price on the American Stock Exchange on that date was approximately $747.7 million.

     At March 9, 2005, 190,382,741 shares of the Registrant’s common stock were outstanding.

     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 2005 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, 2004, are incorporated by reference into Part III hereof.

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Table of Contents

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 natural 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 incorporating the following:

     Customer and marketing efforts

	•	delivering quality, value-added service to our customers;
	•	maintaining a strong 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;
	•	using term contracts to provide sufficient cash flow to cover a majority of the incremental capital expenditures for refurbishments on rigs under term contracts and to maximize long-term cash flow;

     Equipment and Operations

	•	maintaining a premium fleet of equipment with a bias toward drilling for natural gas;
	•	enhancing cash flow through our turnkey and trucking operations and use of our top drives;
	•	controlling costs and exercising capital spending discipline;

     Growth opportunities

	•	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

     According to the Baker Hughes rotary rig count, there were 1,136 land rigs working in the United States at the peak of the last up cycle in 2001. That number fell to 628 in April 2002, we believe due to lower commodity prices and the land rig count generally stabilized from April 2002 thru December 2002. Beginning in the first quarter of 2003 the land rig count, per Baker Hughes, began to increase from an average of 773 rigs working in the first quarter of 2003 to an average of 1,131 rigs working during the fourth quarter of 2004. As of March 4, 2005, the land rig count climbed to 1,163 rigs working. We believe this increase is due to attractive commodity prices that our customers are receiving for their production. From the end of 2003 through March 9, 2005, the average NYMEX near month contract price of natural gas was $6.19 per Mmbtu, while the average NYMEX near month contract price of West Texas Intermediate Crude was $42.52 per barrel.

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     We believe that the industry is at or near full utilization of all currently marketed rigs readily capable of working. In addition, we believe there is little excess rig capacity in the market that can be quickly mobilized without significant capital expenditures. The bulk of any incremental rigs to be added to the market are held by us and two of our largest competitors.

Current Conditions and Outlook

     We believe the outlook for oil and natural gas prices as well as the outlook for land drilling contractors remains positive as we move through 2005. The land rig count has reached a point that we believe provides support for increasing dayrates and improved contractual terms. The current high oil and natural gas commodity prices are providing our customers with the cash flow to pursue oil and natural gas prospects in the areas where we operate. As of March 9, 2005, commodity prices remain relatively high with the NYMEX twelve-month strip for natural gas at $7.48 per Mmbtu and the NYMEX twelve-month strip for oil at $54.14 per barrel.

     We expect wages and costs to increase in 2005 as a result of this robust demand. We have already incurred wage increases in the Rocky Mountain Division in late 2004 and have experienced some escalations in cost during 2004. We also expect that the delivery times for drill pipe and newly manufactured rig components will lengthen significantly including, for example, delivery times for mud pumps and draw works. The cost increases and extended delivery times continue to support a basis for increases in dayrates for 2005.

     In a tighter market for quality rigs, we are signing an increasing number of term contracts. We currently have 22 rigs working under term contracts with a term of six months to two years. Nine more are scheduled to go to work under term contracts by mid-second quarter. We have approximately 7,600 and 1,200 rig days contracted in 2005 and 2006, respectively, under term contracts. In addition to our 102 marketed rigs, we have 10 cold-stacked rigs which can be deployed quickly, and have 15 inventory rigs available for refurbishment and reactivation as demand dictates.

     In 2004, we completed a refinancing of our 8 7/8% senior notes with two issues of contingent convertible senior notes, which significantly reduced our interest expense to $14.8 million for 2004, down from $27.8 million in 2003. The current interest rate on our $125.0 million floating rate contingent convertible notes is 2.51% per annum and the interest rate on our other contingent convertible notes instrument is 3.75% per annum. This refinancing also extended our debt maturity dates (see Note 4 to the consolidated financial statements). We increased our line of credit facility from $75.0 million to $100.0 million at the end of 2004 and extended the term of this facility to the end of 2008. We will continue to focus on maintaining a strong balance sheet as well as higher liquidity and flexibility essential to growth for the future.

Operations

     At March 9, 2005, we had a rig fleet of 127 rigs, 102 of which were marketed, 10 cold-stacked and 15 held for future refurbishment. Cold-stacked rigs are rigs that are stacked without crews and are not currently being marketed. We have committed to return two of our ten cold-stacked rigs to service in approximately mid-2005, both under term contracts with customers. By returning these two cold-stacked rigs to service with term contracts, we are able to provide sufficient cash flow to cover the incremental capital expenditures for the required refurbishments.

     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.

     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. However, we continually evaluate opportunities to enter foreign markets in which we can enter term contracts to support such a commitment. During 2004, approximately 98% of the wells we drilled for our customers were drilled in search of natural gas. Larger natural gas reserves are

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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 March 9, 2005, we had 20 marketed rigs in this division which consisted of 11 diesel electric rigs and nine mechanical rigs, including one trailer-mounted rig. Our Ark-La-Tex division also operates a fleet of trucks which is used exclusively to move our rigs. The Ark-La-Tex division manages the operations of our West Texas district.

     We had an average of 20 rigs working in our Ark-La-Tex division during 2004. Daywork contracts generated approximately 83% of the division’s revenues, while turnkey and footage contracts generated the remaining 17%. The average revenue per rig day worked by the division during 2004 was $12,153.

     Gulf Coast Division. Our Gulf Coast division provides drilling services in Southern Louisiana and along the upper Texas Gulf Coast. At March 9, 2005, we had 24 marketed rigs in this division which consist of 19 diesel electric rigs and five mechanical rigs.

     We had an average of 20 rigs working in our Gulf Coast division during 2004. Daywork contracts generated approximately 62% of the division’s revenues, while turnkey and footage contracts generated the remaining 38%. The average revenue per rig day worked by the division during 2004 was $14,566.

     South Texas Division. At March 9, 2005, we had 29 marketed rigs in this division. The marketed rigs consisted of 16 diesel electric rigs, and 13 mechanical rigs. Nine of these marketed rigs are trailer-mounted, in response to the market demands of this division. The South Texas division also operates a fleet of trucks which is used exclusively to move our rigs.

     We had an average of 27 rigs working in our South Texas division during 2004. Daywork contracts generated approximately 59% of the division’s revenues, while turnkey and footage contracts generated the remaining 41%. The average revenue per rig day worked by the division during 2004 was $15,182.

     Rocky Mountain Division. Our Rocky Mountain division 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 the Company acquired New Patriot Drilling Corp. (“Patriot”) and its ten rigs in April, 2004. We had 17 marketed rigs in this division at March 9, 2005, which consisted of seven diesel electric rigs and ten mechanical rigs.

     We had an average of ten rigs working in our Rocky Mountain Division during 2004. Daywork contracts generated 100% of the revenue in this division and the average revenue per rig day worked during 2004 was $11,579.

     West Texas District. Our West Texas district provides drilling services in West Texas, Southeast New Mexico and the Mid-Continent region. We began operations in West Texas in October 2001. Since that time, we have increased the number of marketed rigs in this district to 11, including six diesel electric rigs and five mechanical rigs at March 9, 2005. During 2004, we averaged revenue per rig day worked of $10,157, all of which was under daywork contracts.

Cold Stacked Rigs and Rigs Held for Refurbishment

     At March 9, 2005, we had the ability to return each of our ten cold-stacked rigs to work at an estimated cost of $1.0 million to $3.0 million per rig, excluding pipe. In addition, at March 9, 2005, we had 15 rigs held for future refurbishment that could be returned to service for an estimated cost of approximately $5.0 million to $8.0 million per rig, excluding drill pipe and drill collars. The actual number of rigs reactivated in 2005, 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.

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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. Drilling contracts can be for a single well or multiple wells. 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. In addition, our day work contracts generally allow us to pass crew wage increases to our customers in the form of higher dayrates.

     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 cancellation fee approximately equal to the dayrate under the contract less estimated contract drilling operating expenses for the unexpired term of the contract. 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.

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Customers and Marketing

     Our contract drilling customers include independent producers and major oil and natural gas companies. In 2004, 32% of our revenue came from major oil and natural gas companies and large independent producers, while the remaining 68% came from other independents. For the year ended December 31, 2004, 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 long-term 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 March 9, 2005.

     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. 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.

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     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 provides $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, with a $150,000 deductible or $20.0 million, with a $225,000 deductible, depending upon the area in which the well is drilled and its target depth. Each form of coverage provides for a deductible that we 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. In addition, there is a deductible of $850,000 in the aggregate over the policy period, exclusive of the maintenance deductible. Except for care, custody and control and total loss, an aggregate deductible of $850,000 per annum is to apply to our property and casualty and “control of well” insurance combined, exclusive of maintenance deductibles.

     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. Any rising cost, changing deductibles, and/or availability of certain types of insurance could have an adverse effect on our financial condition and results of operations. Increases in deductibles could be caused by changes in our claims experience.

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 natural 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 natural 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 March 9, 2005.

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A material or extended decline in expenditures by the oil and natural gas industry, due to a decline or volatility in oil and natural gas prices, a decrease in demand for oil and natural gas, an increase in rig supply 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 natural 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 natural 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
	•	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 natural 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 reduce the number of rigs under contract, 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. If the economic environment worsens, our business, financial condition and results of operations may be 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.

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     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, by reactivating previously stacked rigs or purchasing new rigs. An influx of rigs into a market area from any source could rapidly intensify competition and make any improvement in demand for drilling rigs short-lived.

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:

	•	build new rigs or acquire and refurbish existing rigs to be able to place rigs into service more quickly than us in periods of high drilling demand;
	•	compete more effectively on the basis of price and technology;
	•	better withstand industry downturns; and
	•	retain skilled rig personnel.

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 events 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 risks 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 risks of our business. If we were to incur a significant liability for which we were not fully insured or indemnified, it could adversely affect our financial position and

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results of operations. 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, including our April 2004 acquisition of Patriot, involve numerous risks, including:

	•	unanticipated costs and liabilities;
	•	difficulty of integrating the operations and assets of the acquired business;
	•	our ability to properly access and maintain an effective internal control environment over an acquired company, in order to comply with the recently adopted 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 shareholders. Acquisitions could also 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 three profitable years since 1996.

     We have a history of losses with only three profitable years since 1996. In 1997, we had net income of $10.2 million, in 2001 we had net income of $68.5 million, and in 2004 we had net income of $8.1 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 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.

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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, our risk 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.

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 because of increasing demand for contract drilling services in general. 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 our cold-stacked rigs and inventory rigs to service 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 during periods of high demand. 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 credit agreement may prohibit us from participation in certain transactions that we may consider advantageous.

     Our subsidiary, Grey Wolf Drilling Company L.P., has entered into a credit facility that contains covenants restricting our ability to undertake many types of transactions and contains financial ratio covenants when certain conditions are met. These restrictions may 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 Contingent Convertible Floating Rate Notes due April 2024 (the “Floating Rate 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 3.75% Notes and Floating Rate Notes, it could cause our default under our 3.75% Notes, our Floating Rate 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 3.75% Notes and our Floating Rate 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.

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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 and prevent us from fulfilling our obligations under the notes and our other outstanding indebtedness.

     We have now and will continue to have a significant amount of indebtedness. On December 31, 2004, our total long-term indebtedness was approximately $275.0 million in principal amount, (primarily consisting of $150.0 million in principal amount of our 3.75% Notes and $125.0 million in principal amount of our Floating Rate Notes).

     Our substantial indebtedness could:

	•	make it more difficult for us to satisfy our obligations with respect to the 3.75% Notes and the Floating Rate Notes;
	•	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 indentures governing our 3.75% Notes and our Floating Rate Notes nor the terms of our 3.75% Notes or our Floating Rate 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.

     The Floating Rate Notes bear interest annually at a rate equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05%. Although the interest rate on the Floating Rate Notes will never be more 6.00%, we are subject to market risk exposure related to changes in interest rates on the Floating Rate Notes up to 6.00%. A significant increase in 3-month LIBOR would increase the interest rate on the Floating Rate Notes and the amount of interest we pay on the Floating Rate Notes, which may have a material adverse affect on our financial condition and liquidity.

     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 Floating Rate 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 March 9, 2005, we had the ability to borrow approximately $78.7 million under our credit facility (after reductions for undrawn outstanding standby letters of credit of $21.3 million). In addition, the 3.75% Notes and the Floating Rate 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.

     Although our operating activities did provide net cash sufficient to pay our debt service obligations for the year ended December 31, 2004, our cash flow from operating activities was insufficient to cover our debt service obligations in 2003. 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.

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Credit ratings affect our ability to obtain financing and the cost of such financing.

     Our credit ratings affect our ability to obtain financing and the cost of such financing. At December 31, 2004, our corporate and unsecured debt ratings were rated B1 by Moody’s Investors Service and BB– by Standard & Poor’s Ratings group. In determining our credit ratings, the rating agencies consider a number of both quantitative and qualitative factors. These factors include earnings, fixed charges such as interest, cash flows, total debt outstanding, off balance sheet obligations and other commitments, total capitalization and various ratios calculated from these factors. The rating agencies also consider predictability of cash flows, business strategy, industry conditions and contingencies. Lower ratings on our senior unsecured debt could impair our ability to obtain additional financing and will increase the cost of the financing that we do obtain.

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 Floating Rate Notes are issued require us to offer to repurchase the 3.75% Notes and Floating Rate Notes then outstanding at a purchase price equal to 100% and 100%, 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 March 9, 2005, 190,382,741 million shares of our common stock were issued and outstanding. An additional 6.6 million shares of our common stock were issuable upon exercise of outstanding stock options (of which 3.7 million shares are currently exercisable) and 42.5 million shares were issuable upon conversion of the 3.75% Notes and the Floating Rate Notes, once a conversion contingency is met. See Note 4 to the consolidated financial statements for information on the conditions under which our 3.75% Notes and our Floating Rate Notes become convertible into our common stock. The market price of our common stock could drop significantly if future sales of substantial amounts of our common stock occur, if the perception exists that substantial sales may occur or if our convertible notes become convertible.

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Employees

     At March 9, 2005, we had approximately 2,900 employees. None of our employees are subject to collective bargaining agreements, and we believe our employee relations are satisfactory.

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;
	•	2005 rig activity and financial results;
	•	projected depreciation expense and interest expense;
	•	reactivation and cost of reactivation of non-marketed rigs;
	•	projected dayrates;
	•	the availability of term contracts;
	•	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 2005.

     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 size rigs 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 March 9, 2005, we owned 12 direct current diesel electric rigs and 53 SCR diesel electric rigs.

     We also owned at March 9, 2005, 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

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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 speed, personnel safety and drilling efficiency, and reduce the risk of the drill string sticking during operations. At March 9, 2005, we owned 17 top drives.

     We generally deploy our rig fleet among our divisions and district based on the types of rigs preferred by our customers for drilling in the geographic markets served by our divisions and district. The following table summarizes the rigs we own as of March 9, 2005:

(2) Includes one diesel electric rig.

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Facilities

     The following table summarizes our significant real estate:

     We lease approximately 22,700 square feet of office space in Houston, Texas for our principal corporate offices at a cost of approximately $33,100 per month. We believe that all our facilities are in good operating condition and that they are adequate for their present uses.

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. See Note 8 – Commitments and Contingencies in Notes to Consolidated Financial Statements.

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 and Issuer Purchases of Equity Securities

Market Data

     Our common stock is listed and traded on the American Stock Exchange (“AMEX”) under the symbol “GW.” As of March 9, 2005, we had 921 shareholders of record. The following table sets forth the high and low prices of our common stock on the AMEX for the periods indicated:

     On March 9, 2005, the last reported sales price of our common stock on the AMEX was $6.31 per share.

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     We have never declared or paid cash dividends on our common stock and do not expect to pay cash dividends in 2005 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.

     On March 31, 2004, we sold $100.0 million of our Floating Rate Notes. On April 27, 2004, we sold an additional $25.0 million of the Floating Rate Notes when the initial purchasers of the Floating Rate Notes securities exercised their entire option to purchase additional Floating Rate Notes which was granted in connection with the first sale of the Floating Rate Notes. The initial purchasers in both sales of the total of $125.0 million of Floating Rate Notes were Deutsche Bank Securities Inc. and Credit Suisse First Boston, LLC. The net proceeds to us from the sales of Floating Rate Notes were $122.2 million, net of the initial purchasers’ discounts of $2.8 million. We used the net proceeds to redeem our 8?% Senior Notes Due 2007 and for general corporate purposes. The Floating Rate Notes were sold in reliance on exemptions from registration under the Securities Act of 1933 under Section 4(2) of the Securities Act and Rule 144A thereunder. For additional information about the Floating Rate Notes, including terms of convertibility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Floating Rate Notes.”

Item 6. Selected Financial Data

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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 March 9, 2005, of 127 rigs, of which 102 rigs were marketed. Our customers include independent producers and major oil and natural gas companies. We conduct substantially 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-Contracts).

     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

     The United States land rig count at March 4, 2005 reached 1,163 rigs, which is higher than the levels reached during the 2001 up cycle. As a result of this increased demand, we have also seen an increase in our average rigs worked throughout 2004. Our average working rig count rose approximately 49% from the first quarter of 2004 to March 9, 2005, including the ten rigs that we added to our fleet in connection with the acquisition of New Patriot Drilling Corp. (“Patriot”). For the week ended March 4, 2005, we had an average of 98 rigs working.

     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.

     We are signing an increasing number of term contracts. We currently have 22 rigs working under term contracts with terms of six months to two years. These rigs are included in the average rigs working in the table above. In addition, nine more rigs are scheduled to go to work under term contracts by mid-second quarter and we have a total of approximately 7,600 and 1,200 days contracted for 2005 and 2006, respectively, under term contracts.

Drilling Contract Bid Rates

     Improvements in the level of land drilling in the United States during 2004 have positively impacted the dayrates we are receiving for our rigs. Our dayrates rose an average of $1,059 per day across rigs and all our market regions in the fourth quarter of 2004 over the third quarter. This compares to an increase of $644 per day between the second and third quarters of 2004. This latest quarter-to-quarter increase is the largest we have experienced since the second quarter of 2001. As of March 9, 2005, our bid rates have risen to between $10,500 to $17,000 per rig day, without fuel or top drives. We expect this upward trend in dayrates to continue during 2005; however, we cannot predict the rate of increase.

     In addition to our fleet of drilling rigs, we owned 17 top drives at March 9, 2005, for which our bid rates are up to $2,500 per day, at that date. Bid rates for our top drives are in addition to the above stated bid rates for our rigs.

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Turnkey and Footage Contract Activity

     Turnkey and footage work is 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 earnings before interest expense, taxes, depreciation and amortization (“EBITDA”) per rig day worked than under daywork contracts. A rig day is defined as a twenty-four hour period in which a rig is under contract and should be earning revenue. However, we are typically required to bear additional operating costs (such as drill bits) and risk (such as loss of hole) that would otherwise be assumed by the customer under daywork contracts. In 2004, our turnkey and footage EBITDA per rig day was $5,990 compared to a daywork EBITDA per rig day of $2,282, and our turnkey and footage revenue was $32,515 per rig day compared to $11,184 per rig day for daywork. For the year ended December 31, 2004, turnkey and footage work represented 11% of total rig days worked compared to 16% of total rig days worked in 2003. This percentage decrease in 2004 is due to the increase in the number of days worked under daywork contracts.

     EBITDA generated on turnkey and footage contracts can 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 lower during periods of overall higher demand. We have not, however, experienced this typical market reaction thus far in this most recent increase in demand. While overall demand has been higher as evidenced by the increase in rig count, the demand for our turnkey services has not significantly declined.

First Quarter 2005 Outlook

     We have prepared an estimate of results for the first quarter of 2005 based upon currently anticipated levels of drilling activity and dayrates. We expect that for the first quarter we will have an average of 98 rigs working per day, EBITDA of approximately $40.6 million and net income per share of approximately $0.07 on a diluted basis, projecting an annual tax rate of approximately 39%. We expect depreciation expense of approximately $14.7 million and interest expense of approximately $2.6 million in the first quarter of 2005. Capital expenditures for the full year 2005 are currently projected to be $70.0 million to $90.0 million subject to the actual level of rig activity and the ultimate number of rig reactivations during the year. 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 seven and nine rigs working under turnkey and footage contracts during the first quarter of 2005; however, there can be no assurance that we will be able to maintain the current level of activity or the financial results we have historically derived from turnkey and footage contracts. See Item 1. Business-Forward-Looking Statements for important factors that could cause actual results to be different materially from our expectations.

Critical Accounting Policies

     Our consolidated financial statements and accompanying notes to consolidated financial statements 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, goodwill and other intangible 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 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.

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     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 natural 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 2004 and 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 reactivate, excluding drill pipe, by category as of March 9, 2005:

The net book value of the inventory rigs at December 31, 2004 was $18.2 million.

     Goodwill and Other Intangible Assets. During the second quarter of 2004, we completed the acquisition of Patriot, which was accounted for as a business combination in accordance with SFAS No. 141, “Business Combinations.” In conjunction with the purchase price allocation of the Patriot acquisition we recorded goodwill of $10.4 million and intangible assets of $3.2 million. The intangible assets represent customer contracts and related relationships acquired and are being amortized over the useful life of three years.

     Goodwill represents the excess of costs over the fair value of assets of the business acquired. None of the goodwill resulting from this acquisition is deductible for tax purposes. We follow the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Pursuant to SFAS No. 142, goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead are tested for impairment at least annually in accordance with the provisions of SFAS No. 142. SFAS No. 142 also requires that intangible assets with estimable useful lives be amortized over their respective estimated useful lives to

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their estimated residual values, and reviewed for impairment in accordance with SFAS No. 144, “Accounting for Impairment or Disposal of Long–Lived Assets.”

     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. At December 31, 2004, there were five turnkey wells in progress versus eight wells at December 31, 2003, with accrued revenue of $10.0 million and $5.0 million, respectively at such dates. Anticipated losses, if any, on uncompleted contracts are recorded at the time our estimated costs exceed the contract revenue. All turnkey wells in progress at December 31, 2004 have been completed and we did not incur any additional losses.

     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 $1.0 million for general liability claims. These policies include deductibles of $500,000 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, 2004 and 2003, we had $11.8 million and $9.4 million, respectively, accrued for losses incurred within the deductible amounts for workers’ compensation and general liability claims and for uninsured 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, 2004 are $158.3 million, which expires from 2010 to 2024. Approximately $7.2 million of these NOL’s expire in 2010 and 2011, while the remaining $151.1 million expire between 2019 and 2024. 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, 2004, 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 $20.9 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 eight 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.

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Financial Condition and Liquidity

     The following table summarizes our financial position as of December 31, 2004 and December 31, 2003.

Significant Changes in Financial Condition

     The acquisition of Patriot and the refinancing of our remaining 8 7/8% Notes significantly impacted our balance sheet in 2004. These changes included increases in net property and equipment, goodwill, other noncurrent assets, deferred income taxes and shareholders’ equity. On April 6, 2004, we acquired all the outstanding capital stock and stock equivalents of Patriot by merger in exchange for $14.2 million in cash and 4,610,480 shares of our common stock valued at $20.6 million. In addition, we made payments of $14.7 million to retire the outstanding debt of Patriot. Patriot had a fleet of ten drilling rigs and provided onshore contract land drilling services to the oil and natural gas industry in the Rocky Mountain region. The fair value of the property and equipment acquired was $42.4 million while intangible assets acquired were valued at $3.2 million. The intangible assets represent customer contracts and related customer relationships acquired and are included in “Other noncurrent assets” on our consolidated balance sheet. The intangible assets are included in other noncurrent assets in the table above. We also recorded goodwill of $10.4 million as a result of the acquisition. Net property and equipment was also affected by capital expenditures other than for Patriot of $47.0 million and depreciation for 2004 of $54.5 million. In conjunction with the Patriot acquisition, we recorded additional deferred tax liabilities valued at $6.0 million. This amount is included in “Other long-term liabilities” in the table above.

     On March 31, 2004, we issued $100.0 million aggregate principal amount of Floating Rate Contingent Convertible Senior Notes due 2024 (the “Floating Rate Notes”) in a private offering which yielded net proceeds of $97.8 million. Of the net proceeds, $90.0 million was irrevocably deposited with the trustee of the 8 7/8% Notes to redeem the outstanding $85.0 million aggregate principal amount of those notes at 102.9580%, plus accrued interest on April 30, 2004. The redemption premium of $2.5 million on the 8 7/8% Notes was included in interest expense for the year ended December 31, 2004.

     In addition, on April 27, 2004, one of the initial purchasers in our private offering of the Floating Rate Notes exercised its full option to purchase an additional $25.0 million aggregate principal amount of the Floating Rate Notes. As a result, we have $125.0 million aggregate principal amount of the Floating Rate Notes outstanding. The additional Floating Rate Notes have the same terms as those issued on March 31, 2004 and we will use, or have used, the net proceeds of approximately $24.4 million for general corporate purposes. The issuance of the Floating Rate Notes and redemption of the 8 7/8% Notes resulted in an increase in long-term debt of $40.1 million.

     Working capital increased by $46.3 million from December 31, 2003 to December 31, 2004, due primarily to an increase in accounts receivable and cash balances partially offset by an increase in accounts payable balances. These balances have increased because of the increase in rig activity. Shareholders’ equity also increased due to the exercise of stock options, which yielded proceeds of $10.2 million and increased due to net income.

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Floating Rate Notes

     The Floating Rate Notes bear interest at a per annum rate equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05% but will never be less than zero or more than 6.00%. These notes mature on April 1, 2024. The Floating Rate Notes are convertible into shares of our common stock, upon the occurrence of certain events, at a conversion price of $6.51 per share, which is equal to a conversion rate of approximately 153.6098 shares per $1,000 principal amount of the Floating Rate Notes, subject to adjustment. The Floating Rate Notes are our general unsecured senior obligations and are fully and unconditionally guaranteed, on a joint and several basis, by all our domestic wholly-owned subsidiaries. Non-guarantor subsidiaries are immaterial. The Floating Rate Notes and the guarantees rank equally with all of our other senior unsecured debt, including our 3.75% Contingent Convertible Senior Notes due 2023 (the “3.75% Notes”). Fees and expenses of $3.6 million incurred at the time of issuance are being amortized through April 1, 2014, the first date the holders may require us to repurchase the Floating Rate Notes.

     We may redeem some or all of the Floating Rate Notes at any time on or after April 1, 2014, at a redemption price equal to 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest and liquidated damages, if any, to the date of repurchase, payable in cash. Holders may require us to repurchase all or a portion of the Floating Rate Notes on April 1, 2014 or April 1, 2019, and upon a change of control, as defined in the indenture governing the Floating Rate Notes, at 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest and liquidated damages, if any, to the date of repurchase, payable in cash.

     The Floating Rate 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 120% of the conversion price per share, or $7.81 per share, on that 30th trading day;
	•	if we have called the Floating Rate Notes for redemption;
	•	during any period that the credit ratings assigned to our senior unsecured debt (currently the 3.75% Notes) by both Moody’s Investors Service (“Moody’s”) and Standard & Poor’s Ratings Group (“S&P”) are reduced below B1 and B+, respectively, or if neither rating agency is rating our senior unsecured debt;
	•	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 Floating Rate 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 Floating Rate Notes; or
	•	upon the occurrence of specified corporate transactions, including a change of control.

     As of the date of this report, none of the conditions enabling the holders of the Floating Rate Notes to convert them into shares of our common stock have occurred. At March 9, 2005, the credit ratings assigned to the Company’s senior unsecured debt (currently the 3.75% Notes) by Moody’s Investor Service and Standard and Poor’s Ratings Group were B1 and BB-, respectively. The indenture governing the Floating Rate 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.

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 Floating Rate Notes. Fees and expenses of approximately $4.0 million incurred at

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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.

     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, or $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 and S&P 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, 2004 or through the date of this report. At March 9, 2005, 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.

CIT Facility

     Our subsidiary Grey Wolf Drilling Company L.P. amended its credit facility in December 2004, with the CIT Group/Business Credit, Inc. (the “CIT Facility”) and extended the maturity of the credit facility until December 31, 2008. The CIT Facility was also increased from $75.0 million to $100.0 million. It also provides us with the ability to borrow up to the lesser of $100.0 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 provides that up to $50.0 million of the $100.0 million is available for letters of credit. Outstanding letters of credit reduce the amount available for borrowing under the CIT Facility. 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%. We are required to pay a commitment fee of 0.5% 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 $21.3 million of undrawn letters of credit at March 9, 2005. 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.

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     Among the various covenants that we must satisfy under the CIT Facility are the following two covenants, as defined in the CIT Facility, which apply whenever our liquidity, defined as the sum of cash, cash equivalents and availability under the CIT Facility, falls below $35.0 million. At December 31, 2004, our liquidity as defined above was $152.9 million.

	•	1 to 1 EBITDA coverage of debt service, tested monthly on a trailing 12 month basis; and
	•	minimum tangible net worth at the end of each quarter will be at least the prior year tangible net worth less non-cash write-downs since the prior year-end less fixed amounts for each quarter end for which the test is calculated.

     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;
	•	legal 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).

Cash Flow

     The net cash provided by or used in our operating, investing and financing activities is summarized below (amounts in thousands):

     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 generated from operating activities during the year ended December 31, 2004 was $45.1 million compared to cash used in operating activities during the year ended December 31, 2003 of $7.0 million. This increase in cash flow from operating activities from 2003 to 2004 is due primarily to an increase in EBITDA as a result of higher dayrates and rig activity.

     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. This decrease in cash flow from operating activities from 2002 to 2003 was principally due to a decrease in EBITDA per rig day between the two periods. This decline was due in large part to the replacement of expiring term contracts with spot market contracts at lower rates.

     Cash flow used in investing activities for the year ended December 31, 2004 primarily consisted of $28.9 million of cash paid in the Patriot acquisition and $47.0 million of capital expenditures. For the years ended December 31, 2003 and 2002, cash flow used in investing activities consisted of capital expenditures of $35.1

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million and $22.3 million, respectively. 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.

     Cash flow provided by financing activities for 2004 primarily consisted of the net proceeds of $122.2 million from the issuance of $125.0 million of Floating Rate Notes on March 31, 2004 and April 22, 2004, offset by $85.0 million for the redemption of the 8?% Notes on April 30, 2004. In addition, proceeds from stock option exercises provided $10.2 million in 2004. Cash flow used in financing activities for the year ended December 2003 consisted of the $165.0 million partial redemption of the 8?% and the sale of the 3.75% Notes, which yielded net proceeds of $146.6 million.

Certain Contractual Commitments

     The following table summarizes certain of our contractual cash obligations and related payments due by period at December 31, 2004 (amounts in thousands):

     Our CIT Facility provides up to $50.0 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 $81.2 million at December 31, 2004. The following table illustrates the undrawn outstanding standby letters of credit at December 31, 2004 and the potential maturities if drawn upon by the holders (amounts in thousands):

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Projected Cash Sources and Uses

     We expect to use cash generated from operations to cover cash requirements, including debt service on the 3.75% Notes and Floating Rate Notes and capital expenditures in 2005. Capital expenditures for 2005 are projected to be between $70.0 million and $90.0 million, subject to the actual level of rig activity and ultimate number of rig reactivations. We will make quarterly interest payments on the Floating Rate Notes on January 1, April 1, July 1, and October 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.

     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 such a transaction. We cannot give assurance that adequate funding will be available on satisfactory terms.

Results of Operations

     Our drilling contracts generally provide compensation on either a daywork, turnkey or footage basis. Successfully completed turnkey and footage contracts generally result in higher revenues per rig day worked than under daywork contracts. EBITDA per rig day worked on successful turnkey and footage jobs are also generally greater than under daywork contracts, although we are typically required to bear additional operating costs (such as drill bits) that would typically be paid by the customer under daywork contracts. Contract drilling revenues and EBITDA on turnkey and footage contracts are affected by a number of variables, which include the depth of the well, geological complexities and the actual difficulties encountered in drilling the well.

     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 the rules and regulations of the Securities and Exchange Commission (“SEC”). 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. In accordance with SEC rules, we have included below a reconciliation of EBITDA to net income (loss), which is the nearest comparable financial GAAP measure.

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     The following tables highlight rig days worked, contract drilling revenue and EBITDA for our daywork and turnkey operations for the years ended December 31, 2004, 2003 and 2002.

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Comparison of Fiscal Years ended December 31, 2004 and 2003

     Our EBITDA increased by $53.6 million, or 174%, to $84.3 million for the year ended December 31, 2004 from $30.8 million for the year ended December 31, 2003. The increase resulted from a $51.9 million increase in EBITDA from daywork operations and a $1.7 million increase in EBITDA from turnkey operations. On a per rig day basis, our total EBITDA increased by $1,316, or 95% to $2,705 in 2004 from $1,389 in 2003. This increase included a $1,689 per rig day increase from daywork operations. Total general and administrative expenses increased by $1.4 million due primarily to higher payroll costs, professional fees, and costs associated with being a public company.

Daywork Operations

     The increase in EBITDA discussed above was due in part to an increase of 48%, or 8,916 rig days worked on daywork contracts during 2004 compared to 2003. This increase in days was due to the acquisition of Patriot and overall higher demand for our services. Higher dayrates in 2004 also contributed to the increase. Contract drilling revenue per rig day increased $1,622, or 17%, the bulk of which also increased EBITDA per day, which increased by $1,689 per rig day. Overall, expenses increased as a result of the increase in activity but remained relatively flat on a per rig day basis.

Turnkey Operations

     Days worked under turnkey contracts increased by 114, or 3%, while EBITDA per rig day increased by $283, or 5%, to $5,990 for the year ended December 31, 2004, from $5,707 for the year ended December 31, 2003. The increase in EBITDA per rig day was due to differences in the mix, success and complexity of the wells drilled in 2004 compared to 2003.

Other

     Depreciation and amortization expense increased by $4.8 million, or 9.5%, to $55.3 million for the year ended December 31, 2004 compared to $50.5 million for the year ended December 31, 2003. Depreciation and amortization expense is higher due to the acquisition of Patriot and capital expenditures during 2004.

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     Interest expense decreased by $13.1 million, or 47%, to $14.8 million for 2004 from $27.8 million for 2003. The decrease is due to the issuance of the 3.75% Notes and Floating Rate Notes and subsequent redemption of our 8 7/8% Notes. This refinancing resulted in substantial interest savings given the lower interest rate debt outstanding.

     Our income tax expense increased by $23.6 million to $6.2 million in 2004 from an income tax benefit of $17.4 million in 2003. The increase is due to the level of income 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 that were purchased in capital stock acquisitions. The permanent difference will be reduced as these assets are depreciated for financial accounting purposes on a straight-line basis over their remaining useful lives of approximately eight years. As the amortization of these permanent differences is a fixed amount, our book effective tax rate varies widely based upon the current and projected levels of income or loss.

Comparison of Fiscal Years ended December 31, 2003 and 2002

     Our EBITDA decreased by $10.1 million, or 25%, to $30.8 million for the year ended December 31, 2003 from $40.8 million for the year ended December 31, 2002. The decrease resulted from a $20.2 million decrease in EBITDA from daywork operations partially offset by a $10.2 million increase in EBITDA from turnkey operations. On a per rig day basis, our total EBITDA decreased by $645, or 32% to $1,389 in 2003 from $2,034 in 2002. This decrease included a $1,124 per rig day decrease from daywork operations offset by a $519 per rig day increase from turnkey operations. Total general and administrative expenses increased by $666,000 due primarily to higher payroll costs, professional fees, increases in insurance costs, and costs associated with being a public company. Total interest income decreased by $778,000 in 2003 from 2002, due primarily to lower cash balances in 2003.

Daywork Operations

     Days worked under daywork contracts increased slightly by 452 rig days, 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.

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.

     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

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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.

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 natural 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 natural gas industry and to a lesser extent by changes in general inflation.

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 the Floating Rate Notes and the CIT Facility. The Floating Rate Notes bear interest at a per annum rate which is equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05%. We had $125.0 million of the Floating Rate Notes outstanding at December 31, 2004. A 1% change in the interest rate on the Floating Rate Notes would change our interest expense by $1.3 million on an annual basis. However, the annual interest on the Floating Rate Notes will never be below zero or more than 6.00%, which could yield interest expense ranging from zero to $7.5 million on an annual basis. Interest on borrowings under the CIT Facility accrues at a variable rate, using either the prime rate plus 0.25% to 1.50% or LIBOR plus 1.75% to 3.50%, depending upon our debt service coverage ratio for the trailing 12 month period. We have no outstanding balance under the CIT Facility at March 9, 2005 and as such have no exposure under this facility to a change in interest rates.

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Item 8. Financial Statements and Supplementary Data

Index to
Consolidated Financial Statements
and Financial Statement Schedule

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.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

      Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      We assessed the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included on page 35.

Thomas P. Richards
Chairman, President and Chief Executive Officer

David W. Wehlmann
Executive Vice President and Chief Financial Officer

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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, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2004. In connection with our audits of the consolidated financial statements, we have also audited the financial statement schedule for the years ended December 31, 2004, 2003 and 2002. 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. 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.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Grey Wolf, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Houston, Texas
March 15, 2005

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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 management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting that Grey Wolf, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Grey Wolf, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

     We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, management’s assessment that Grey Wolf, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Grey Wolf, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Grey Wolf, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 15, 2005, expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Houston, Texas
March 15,2005

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GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Balance Sheets
(Amounts in thousands, except share data)

See accompanying notes to consolidated financial statements

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GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Statements of Operations
(Amounts in thousands, except per share data)

See accompanying notes to consolidated financial statements

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GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Equity And Comprehensive Income (Loss)
(Amounts in thousands)