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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the Fiscal Year Ended December 31, 2005

Commission file number 1-8226

GREY WOLF, INC.

(Exact name of registrant as specified in its charter)


Texas (State or other jurisdiction of incorporation or organization)		74-2144774 (I.R.S. Employer Identification Number)

10370 Richmond Avenue, Suite 600, Houston, Texas (Address of principal executive offices)		77042 (Zip Code)

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

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


		Name of each exchange
Title of each class		on which registered

Common Stock, par value $0.10 Rights to Purchase Junior Participating Preferred Stock, par value $1.00		American Stock Exchange American Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No þ

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 check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Act.) Yes o No þ

The aggregate market value of the registrant’s voting stock held by non-affiliates on June 30, 2005 based upon the closing price on the American Stock Exchange on that date was approximately $1.4 billion.

At February 23, 2006, 192,715,080 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 2006 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, 2005, are incorporated by reference into Part III hereof.

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 the 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 recover, after operating expenses, a majority of the incremental capital expended for refurbishments on rigs or the purchase of new rigs;

Equipment and Operations

	•		maintaining a premium fleet of equipment with a bias toward deep 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 diversify operations and 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 1,375 rigs working during the fourth quarter of 2005. As of February 24, 2006, the land rig count climbed to 1,436 rigs working. We believe this increase is due to higher commodity prices which our customers are receiving for their production. As of February 23, 2006, the average NYMEX near month

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contract price of natural gas was $8.51 per Mmbtu, while the average NYMEX near month contract price of West Texas Intermediate Crude was $64.12 per barrel.

Across the industry, we believe that most marketed rigs are contracted and that there is limited excess rig capacity.

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 2006. The land rig count is at a level that we believe provides support for continual increases in dayrates and improved contractual terms. The current high oil and natural gas commodity prices are providing our customers with higher cash flow to pursue oil and natural gas prospects in the areas where we operate.

We, and some of our competitors, are continuing to refurbish and redeploy previously stacked rigs in response to strong demand. This reactivation of rigs will likely proceed at a modest pace, we believe, because of the long lead times for delivery of major components generally required to refurbish rigs, such as engines, mud pumps, top drives and drill pipe.

Since December 31, 2004 through the date of this report, we have refurbished and returned to service 12 rigs at an average capital cost of $3.7 million per rig. Each of those rigs began operating under term contracts which we expect will, in the aggregate, fully recover our refurbishment costs over the term of the contracts. We reviewed the remaining rigs held for refurbishment and determined to utilize the component parts of seven of these rigs as spare equipment. There was no current financial statement impact as a result of this decision. We plan to redeploy the four remaining rigs in our inventory during 2006. See “—Rigs Available for Refurbishment.”

Rig safety is a critical priority for us. While our average working rig count increased by 17 in 2005, our ongoing commitment to rig safety led to an 18% reduction in our recordable accident rate for 2005.

The current market conditions are also leading us and some drilling contractors to invest in new drilling rigs. There is limited manufacturing capability for new rigs, and therefore we expect the number of new builds to be brought to market in 2006 will also be limited. We have entered into agreements to purchase four new drilling rigs that will be delivered late in 2006 and have signed three-year term contracts with customers to operate these rigs. These term contracts are expected to provide solid returns on the capital invested and, in the aggregate, fully recover, after operating expenses, the purchase price of the rigs over their term.

In accordance with our business strategy, we have signed a number of term contracts. We currently have 68 rigs working under term contracts with terms ranging from one to three years. A majority of these contracts end at various times over the next twelve months providing future earnings and an opportunity to reprice 53% of the term contracts in the first and second quarters of 2006. We have approximately 20,500 rig days, or an average of 56 rigs, contracted in 2006; and 8,000 rig days, or an average of 22 rigs, contracted in 2007, under term contracts.

Operations

On January 3, 2006, we completed a sale of five rigs that were previously held for future refurbishment for an aggregate purchase price of $15.3 million. The sale resulted in a pre-tax gain of $9.4 million which will be included in our first quarter 2006 results.

After this sale and the movement of the component parts of seven rigs to spare equipment, our rig fleet includes 111 marketed rigs and four rigs available for refurbishment which we plan to reactivate in 2006.

We currently conduct our operations primarily in the following domestic drilling markets:

	•		Ark-La-Tex;

	•		Gulf Coast;

	•		Mississippi/Alabama;

	•		South Texas;

	•		Rocky Mountain;

	•		Mid-Continent.

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We conduct our operations primarily in domestic markets which we believe have historically experienced greater utilization 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 into term contracts to support such a commitment. Most of the wells we drilled for our customers were drilled in search of natural gas. Larger natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells. With continued technological advances in the industry, our customers are drilling an increasing number of directional and horizontal wells. Drilling directional and horizontal wells generally requires larger rigs capable of drilling to depths in excess of 15,000 feet. Our fleet of rigs consists of 81 rigs capable of drilling to 15,000 feet or deeper and fit well with the trend in the industry.

Ark-La-Tex Division. Our Ark-La-Tex division provides drilling services primarily in Northeast Texas, Northern Louisiana and Southern Arkansas, and the Mississippi/Alabama market. At February 23, 2006, we had 23 marketed rigs in this division which consisted of 13 diesel electric rigs and 10 mechanical rigs, including four trailer-mounted rigs. Our Ark-La-Tex division also operates a fleet of trucks which is used exclusively to move our rigs. The Ark-La-Tex division manages the operations of our Mid Continent district.

We had an average of 21 rigs working in our Ark-La-Tex division during 2005. Daywork contracts generated approximately 93% of the division’s revenues, while turnkey contracts generated the remaining 7%. The average revenue per rig day worked by the division during 2005 was $15,525.

Gulf Coast Division. Our Gulf Coast division provides drilling services in Southern Louisiana and along the upper Texas Gulf Coast. At February 23, 2006, we had 25 marketed rigs in this division which consisted of 20 diesel electric rigs and five mechanical rigs.

We had an average of 25 rigs working in our Gulf Coast division during 2005. Daywork contracts generated approximately 56% of the division’s revenues, while turnkey contracts generated the remaining 44%. The average revenue per rig day worked by the division during 2005 was $22,716.

South Texas Division. At February 23, 2006, we had 29 marketed rigs in this division. The marketed rigs consisted of 16 diesel electric rigs, and 13 mechanical rigs. Eight 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 29 rigs working in our South Texas division during 2005. Daywork contracts generated approximately 70% of the division’s revenues, while turnkey contracts generated the remaining 30%. The average revenue per rig day worked by the division during 2005 was $19,840.

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 February 23, 2006, which consisted of seven diesel electric rigs and 10 mechanical rigs.

We had an average of 14 rigs working in our Rocky Mountain Division during 2005. Daywork contracts generated 100% of the revenue in this division and the average revenue per rig day worked during 2005 was $13,693.

Mid-Continent District. Our Mid-Continent district provides drilling services in West Texas, Southeast New Mexico, the Barnett Shale area in North Texas, and the Mid-Continent region. We began operations in the Mid-Continent district in October 2001. Since that time, we have increased the number of marketed rigs in this district to 17, including eight diesel electric rigs and nine mechanical rigs at February 23, 2006. Two of these marketed rigs are trailer-mounted. During 2005, we averaged revenue per rig day worked of $15,166 all of which was under daywork contracts.

Rigs Available for Refurbishment

During 2006, we intend to reactivate our four remaining rigs held for refurbishment. Each is expected to be significantly upgraded, with estimated average capital expenditures of $11.4 million per rig. Refurbishment of two of these rigs is underway. One of these rigs (1,000 horsepower) is projected to commence

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operations under a term contract near the end of the first quarter of 2006 and another rig (3,000 horsepower) is expected to start work under a term contract in the second quarter of 2006. The long-term contracts on each of these rigs are expected to recover our capital costs of refurbishment.

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 or multiple wells. Term drilling contracts typically contain early termination penalties while non-term contracts are typically subject to termination by the customer on short notice with little or no penalty. The 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 daywork contracts generally allow us to pass crew wage increases to our customers in the form of higher dayrates.

We also enter into term contracts to provide drilling services on a daywork basis. Typically, the length of our term contracts have ranged from one to three 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 potential decline in dayrates during the period in which the term contract is in effect. This provides greater stability to our business and allows us to plan and manage our business more efficiently. 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. As of February 23, 2006, 61% of our rigs are working under term contracts. 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 major complications and in a timely manner.

The risks to us under a turnkey contract are substantially greater than on a daywork basis because we assume most of the risks 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 we assume. 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 our expertise, 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. However, the overall risk we assume is generally 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. During 2005, we did not drill under any footage contracts.

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Customers and Marketing

Our contract drilling customers include independent producers and major oil and natural gas companies. In 2005, 36% of our revenue came from major oil and natural gas companies and large independent producers, while the remaining 64% came from other independents. For the year ended December 31, 2005, no individual customer accounted for more than 10% of our revenues. We primarily market our drilling rigs on a regional basis through employee sales personnel. These sales representatives utilize personal contacts and industry 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 February 23, 2006.


			Deductible/
	Limit	Aggregate	Self-Insured Retention
Coverage	Per Occurrence	Limit	per Occurrence

Workers’ compensation/employer liability	Statutory⁽¹⁾ /$1.0 million	None	$	500,000

Automobile liability	$1.0 million	None	$	500,000

Commercial general liability	$1.0 million	$2.0 million	$	250,000

Commercial excess liability	$10.0 million	$10.0 million	Underlying insurance

Commercial excess liability	$90.0 million	$90.0 million	Underlying insurance


(1)		Workers’ compensation policy limits vary depending on the laws of the particular states in which we operate.

Our property casualty insurance coverage for damage to our rigs and drilling equipment is based on our estimate of the cost of comparable used equipment to replace the insured property. There is a $125,000 maintenance deductible per occurrence for losses on our rigs. In addition, there is a deductible of $850,000 in the aggregate over the policy period, exclusive of the maintenance deductible. There is a $25,000 deductible per occurrence on other equipment. We do not have insurance coverage against loss of earnings resulting from damage to our rigs.

We also maintain insurance coverage to protect against certain hazards inherent in our turnkey and footage contract drilling operations. This insurance covers “control of well” (including blowouts above and below the surface), cratering, seepage and pollution, and care, custody and control. Our insurance 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

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and their outlook for future prices. Natural gas storage is at historically high levels which has affected the price of natural gas. Mild weather conditions and increased supply for any other reason could continue to affect these 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, Nigeria 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 oil 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.

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

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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 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 or distract management attention.

As part of our business strategy, we plan to consider acquisitions of, or significant investments in, businesses and assets that are complementary to ours. Any acquisition that we complete could have a material adverse affect on our operating results and/or the price of our securities. Acquisitions involve numerous risks, including:

	•		unanticipated costs and liabilities;

	•		difficulty of integrating the operations and assets of the acquired business;

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	•		our ability to properly access and maintain an effective internal control environment over an acquired company, in order to comply with 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 four profitable years since 1996.

We have a history of losses with only four profitable years since 1996. In 1997, we had net income of $10.2 million, in 2001 we had net income of $68.5 million, in 2004 we had net income of $8.1 million, and in 2005 we had net income of $120.6 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.

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.

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We could be adversely affected if delivery times for rigs and rig equipment lengthen.

The land drilling industry is experiencing price increases and extended delivery times for newly-built rigs. Prices and delivery times for important rig components, including engines, mud pumps, top drives and drill pipe that may be needed to refurbish or repair rigs have also increased. If these price increases continue or extended delivery times lengthen, it could adversely affect our business and results of operations by increasing our costs for, and delaying:

	•		deployment of newly-built rigs;

	•		redeployment of the rigs we are refurbishing or plan to refurbish;

	•		upgrades to our marketed fleet of rigs; and

	•		repair and maintenance of our rigs.

We could be adversely affected if the demand for qualified rig personnel increases.

Although we have not encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel have occurred in the past in our industry during periods of high demand. The demand for qualified rig personnel has increased as a result of overall stronger demand for land drilling services in 2005 and 2006. We believe the demand for qualified rig personnel may increase further as new and refurbished rigs are brought into service by us and our competitors.

If the demand for qualified rig personnel persists or increases, we may experience shortages of qualified personnel to operate our rigs despite these and any other employee retention and hiring measures we may implement. Any such personnel shortages 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 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.

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, 2005, 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).

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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 an 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 February 23, 2006, we had the ability to borrow approximately $76.1 million under our credit facility (after reductions for undrawn outstanding standby letters of credit of $23.9 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 years ended December 31, 2005 and 2004, respectively, there can be no assurances 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.

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, 2005, 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.

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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. 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 February 23, 2006, 192,715,080 million shares of our common stock were issued and outstanding. An additional 4.5 million shares of our common stock were issuable upon exercise of outstanding stock options (of which 2.3 million shares are currently exercisable) and 23.3 million shares were issuable upon conversion of the 3.75% Notes and 19.2 million shares are issuable upon conversion of the Floating Rate Notes, in each case once a conversion contingency is met. Our 3.75% Notes are presently convertible through the end of the first quarter of 2006. 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.

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;

	•		spending by our customers;

	•		2006 rig activity and financial results;

	•		projected depreciation expense and interest expense;

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	•		reactivation, timing and cost of reactivation of rigs available for refurbishment;

	•		cost of building new rigs;

	•		projected dayrates;

	•		the ability to recover our refurbishment costs or the purchase price of rigs from term contracts;

	•		the availability and financial terms of term contracts;

	•		rigs expected to be engaged in turnkey and footage operations;

	•		projected tax rate;

	•		wage rates and retention of employees;

	•		sufficiency of our capital resources and liquidity; and

	•		depreciation and capital expenditures in 2006.

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.

The risks and uncertainties generally described above in this Item 1A. Risk Factors could cause actual results to differ materially from those expressed in our forward-looking statements. Accordingly, we urge you not to place undue reliance on forward-looking statements.

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 1B. Unresolved Staff Comments

Not applicable.

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 pneumatic clutches. Diesel electric rigs are further broken down into two subcategories, direct current rigs and Silicon Controlled Rectifier (“SCR”) rigs. Direct current rigs transmit the power generated by a diesel engine to a direct current generator. This direct current electrical system then distributes the electricity generated to direct current motors on the drawworks and mud pumps. An SCR rig’s diesel engines drive alternating current generators and this alternating current can be transmitted to use for rig lighting and rig quarters or converted to direct current to drive the direct current motors on the rig. As of February 23, 2006, we owned nine direct current diesel electric rigs and 58 SCR diesel electric rigs.

We also owned at February 23, 2006, 13 mechanical rigs and one diesel electric rig that are trailer-mounted for greater mobility. We believe trailer-mounted rigs are in highest demand in the South Texas market. Trailer-mounted rigs are more mobile than conventional rigs, thus decreasing the time and expense to the customer of moving the rig to and from the drill site. Under ordinary conditions, trailer-mounted rigs are capable of drilling an average of two 10,000 foot wells per month.

We also utilize top drives in our drilling operations. A top drive allows drilling with 90-foot lengths of drill pipe rather than 30-foot lengths, thus reducing the number of required connections in the drill string. A top drive also permits rotation of the drill string while moving in or out of the hole. These characteristics increase drilling speed, personnel safety and drilling efficiency, and reduce the risk of the drill string sticking during operations. At February 23, 2006, we owned 17 top drives.

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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 February 23, 2006:


	Maximum Rated Depth Capacity⁽¹⁾
	Under		10,000’		15,000’		20,000’
	10,000’		to 14,999’		to 19,999’		and Deeper		Total
Marketed
Ark-La-Tex
Diesel Electric		—		1		7		4		12
Trailer-Mounted		—		3		—		1		4	⁽²⁾
Mechanical		—		—		4		3		7
Gulf Coast
Diesel Electric		—		—		1		19		20
Mechanical		—		1		2		2		5
South Texas
Diesel Electric		—		1		6		9		16
Trailer-Mounted		—		8		—		—		8
Mechanical		—		4		—		1		5
Rocky Mountain
Diesel Electric		—		—		4		3		7
Mechanical		3		7		—		—		10
Mid-Continent
Diesel Electric		—		—		3		5		8
Trailer-Mounted		—		2		—		—		2
Mechanical		—		4		3		—		7

Total Marketed		3		31		30		47		111


Non-marketed
Rigs Being Refurbished
Mechanical		—		—		—		—		—
Diesel Electric		—		—		1		1		2

Total Rigs Being Refurbished		—		—		1		1		2


Rigs Available For Refurbishment Diesel Electric		—		—		—		2		2
Total Rigs Available For Refurbishment		—		—		—		2		2

Total Non-Marketed		—		—		1		3		4

Total Rig Fleet⁽³⁾		3		31		31		50		115


(1)		The actual drilling capacity of a rig may be less than its rated capacity due to numerous factors, such as the length of the drill string and casing size. The intended well depth and the drill site conditions determine the length of the drill string and other equipment needed to drill a well.

(2)		Includes one diesel electric rig.

(3)		The Company has ordered four new 1,500 hp diesel electric rigs with delivery expected in the fourth quarter of 2006 that will bring the total rig fleet to 119.

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Facilities

The following table summarizes our significant real estate:


Location	Interest	Uses
Houston, Texas	Leased	Corporate Office
Alice, Texas	Owned	Division Office, Rig Yard, Truck Yard
Eunice, Louisiana	Owned	Division Office, Rig Yard
Haughton, Louisiana	Owned	Rig Yard
Shreveport, Louisiana	Leased	Division Office
Shreveport, Louisiana	Owned	Rig Yard, Truck Yard
Casper, Wyoming	Owned	Division Office, Rig Yard
Grand Junction, Colorado	Leased	Division Satellite Office
Midland, Texas	Leased	District Office

We lease approximately 25,250 square feet of office space in Houston, Texas for our principal corporate offices at a cost of approximately $41,176 per month. We believe all of our facilities are in good operating condition and 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.

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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 February 23, 2006, we had 892 shareholders of record. The following table sets forth the high and low prices of our common stock on the AMEX for the periods indicated:


	High		Low
Period from January 1, 2006 to February 23, 2006	$	8.93	$	7.00

Year Ended December 31, 2005
Quarter ended March 31, 2005		6.85		3.70
Quarter ended June 30, 2005		8.00		5.52
Quarter ended September 30, 2005		8.60		6.75
Quarter ended December 31, 2005		8.57		6.81

Year Ended December 31, 2004
Quarter ended March 31, 2004		4.63		3.63
Quarter ended June 30, 2004		4.35		3.30
Quarter ended September 30, 2004		4.89		3.75
Quarter ended December 31, 2004		5.58		4.61

On February 23, 2006, the last reported sales price of our common stock on the AMEX was $7.19 per share.

We have never declared or paid cash dividends on our common stock and do not expect to pay cash dividends in 2006 or for the foreseeable future. We anticipate 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.

Item 6. Selected Financial Data


	Years Ended December 31,
	2005		2004		2003			2002			2001
	(In thousands, except per share amounts)
Revenues	$	696,979	$	424,634	$	285,974		$	250,260		$	433,739
Net income (loss)		120,637		8,078		(30,200	)		(21,476	)		68,453
Net income (loss) per common share
Basic		0.63		0.04		(0.17	)		(0.12	)		0.38
Diluted		0.54		0.04		(0.17	)		(0.12	)		0.38
Total assets		869,035		635,876		532,184			593,964			627,900
Senior and contingent convertible notes & other long-term debt		275,000		275,000		234,898			249,613			250,695

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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 intercompany transactions have been eliminated.

Overview

We are a leading provider of contract land drilling services in the United States with a fleet, at February 23, 2006, of 115 rigs, of which 111 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, Mid-Continent 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 dayrates we receive for our services, the level of demand for turnkey and footage services, our success drilling turnkey and footage wells and the demand for deep versus shallow drilling services.

New Rig Purchases and Reactivations

In early 2006, we entered into agreements to purchase four new 1,500 horsepower rigs for a total of $60 million that will be delivered throughout the fourth quarter of 2006. These new rigs are designed to enhance safety, increase the efficiency of rig moves, and maximize performance for our customers, who have signed three-year term contracts for each of these rigs. These term contracts should provide solid returns on the capital invested and, in the aggregate, should recover the purchase price after operating expenses.

Work is underway to reactivate two of our four rigs available for refurbishment, and we intend to refurbish the remaining two rigs during 2006. The reactivation of these four rigs and purchase of the four new rigs is anticipated to increase our marketed rig count to 119 by the end of the fourth quarter of 2006.

Rig Activity

The United States land rig count has continued to climb to levels not seen since the early nineteen eighties. The land rig count at February 24, 2006 per the Baker Hughes rotary rig count, is over 1,430 rigs. Our average rigs working has also continued to escalate because of the demand for our services. For the week ended February 24, 2006, we had an average of 109 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.


	2004										2005										2006
Domestic
Land Rig									Full										Full		1/1 to
Count	Q-1		Q-2		Q-3		Q-4		Year		Q-1		Q-2		Q-3		Q-4		Year		2/24
Baker Hughes		1,002		1,049		1,115		1,131		1,074		1,153		1,218		1,307		1,375		1,263		1,406
Grey Wolf		65		86		94		96		85		98		99		103		108		102		109

Term Contracts

We have signed a number of term contracts to provide drilling services on a daywork basis. We currently have 68 rigs working under term contracts. A majority of these contracts end at various times over the next twelve months providing future earnings and an opportunity to reprice at then-current market rates. We had or will have the opportunity to reprice 53% of the term contracts in the first and second quarters of 2006. Of the long-term contracts that have been renewed over the past two months, the average increase in contracted revenue per rig day has been $5,500. We have approximately 20,500 days, or an average of 56 rigs, contracted for 2006; and 8,000 days, or an average of 22 rigs, committed under term contracts in 2007. These contracts should provide revenue of $363.1 million in 2006 and $158.1 million in 2007.

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Our term contracts typically range in length from one to three years and include a per rig day cancellation fee approximately equal to the dayrate under the contract less estimated operating expenses for the unexpired term of the contract. In addition, we are able to pass the cost of any labor increases on to our customers through our dayrates on all daywork contracts, including term contracts.

Drilling Contract Rates

Improvements in the level of land drilling in the United States during 2004 and 2005 have positively impacted the dayrates we are receiving for our rigs. We saw a $4,700 per day increase in dayrates from 2004 to 2005 on average, which is a 50% improvement. This was the primary factor in our 164% increase in earnings before interest expense, taxes, depreciation and amortization (“EBITDA”) per rig day from $2,705 in 2004 to $7,139 in 2005. A rig day is defined as a twenty-four hour period in which a rig us under contract and should be earning revenue. As of February 23, 2006, our leading edge rates have risen to between $17,500 to $25,000 per rig day, without fuel or top drives.

In addition to our fleet of drilling rigs, we owned 17 top drives at February 23, 2006, for which our rates are up to $3,000 per rig day, at that date. Rates for our top drives are in addition to the above stated rates for our rigs.

Turnkey and Footage Contract Activity

Turnkey and footage work is an important part of our business and operating strategy and produced record results during 2005 . Our engineering and operating expertise allow us to provide this service to our customers and has historically provided higher revenues and EBITDA per rig day worked than under daywork contracts. 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 2005, our turnkey and footage EBITDA per rig day was $13,568 compared to a daywork EBITDA per rig day of $6,470, and our turnkey and footage revenue was $45,209 per rig day compared to $15,963 per rig day for daywork. 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, 2005, turnkey and footage work represented 9% of total rig days worked compared to 11% of total rig days worked in 2004. This percentage decrease in 2005 is due to the increase in the number of days worked under daywork contracts, as roughly the same number of days were worked under turnkey contracts in 2004 and 2005.

EBITDA generated on turnkey and footage contracts can vary widely based upon a number of factors, including the location of the contracted work, the depth and level of complexity of the wells drilled and the ultimate success of drilling the well. The demand for drilling services under turnkey and footage contracts has historically been lower during periods of overall higher rig demand. While overall rig demand has been higher as evidenced by the increase in rig count, the demand for turnkey services has not declined.

2005 Results and First Quarter 2006 Outlook

We produced record results for revenue, net income, and EBITDA for the last three consecutive quarters and completed 2005 with the best annual results in the Company’s history. Our revenue increased 64% from 2004 and net income was 76% greater than our previous high in 2001, supported by continued strength in both turnkey and daywork operations.

An estimate of results for the first quarter of 2006 has been prepared based on current anticipated levels of activity and dayrates. During the first quarter of 2006, we expect to average 108 rigs working and to generate EBITDA of approximately $85.0 million (see reconciliation of EBITDA to net income in Results of Operations.) We expect depreciation expense of approximately $17.2 million and interest expense of approximately $3.3 million in the first quarter of 2006. Net income per share is expected to be approximately $0.18 on a diluted basis, using a tax rate of approximately 37% based upon the expected net income of $40.3 million. These projected results do not include an after tax gain of $5.9 million ($0.02 per diluted share) on the sale of five rigs during the first quarter of 2006. Capital expenditures for the full year 2006 are projected to be $180.0 million to $190.0 million subject to the ultimate number or rigs purchased or returned to service during 2006. 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 10 and 12 rigs working under turnkey and footage contracts during the first quarter of 2006; 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

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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 15 years.

Impairment of Long-Lived Assets. We assess the impairment of our long-lived assets under Statement of Financial Accounting Standards Board (“SFAS”) No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Such indicators include changes in our business plans, a change in the physical condition of a long-lived asset or the extent or manner in which it is being used, or a severe or sustained downturn in the oil and 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. 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 rigs available for refurbishment 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 rigs available for refurbishment, we could be required under SFAS No. 144 to record an impairment charge.

In 2005, we reviewed the rigs held for refurbishment and determined to utilize the component parts of seven of these rigs as spare equipment. The net book value of these rigs was $7.4 million at December 31, 2005. There was, however, no impairment as a result of this decision. Below is a summary of our rig fleet and the estimated cost to refurbish and reactivate, excluding drill pipe, by category as of February 23, 2006:

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		Estimated
		Per Rig
		Refurbishment
		and Reactivation
	Number	Cost
Rig Category	Of Rigs	(excluding drill pipe)
Marketed	111	N/A
Rigs being refurbished	2	$10.4 Million
Available for refurbishment	2	$12.3 Million

We may also need to purchase drill pipe for these rigs based upon inventory levels at the time of reactivation. The cost of drill pipe, at current prices, could range from $700,000 to $1.5 million for each rig. The net book value of the rigs available for refurbishment in the table above, including the rigs being refurbished, at December 31, 2005 was $9.1 million.

Goodwill and Other Intangible Assets. During the second quarter of 2004, we completed the acquisition of New Patriot Drilling Corp. (“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 their estimated residual values, and reviewed for impairment in accordance with SFAS No. 144, “Accounting for Impairment or Disposal of Long–Lived Assets.” No impairment of our goodwill and intangible assets was recorded during 2005.

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, 2005, there were nine turnkey wells in progress versus five wells at December 31, 2004, with accrued revenue of $17.5 million and $10.0 million, respectively at such dates. Anticipated losses, if any, on uncompleted contracts are recorded at the time our estimated costs exceed the contract revenue.

Insurance Accruals. We maintain insurance coverage related to workers’ compensation and general liability claims up to $1.0 million per occurrence with an aggregate of $2.0 million for general liability claims. These policies include deductibles of $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 $100.0 million. At December 31, 2005 and 2004, we had $18.1 million and $11.8 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

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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. We are subject to income and other similar taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of our annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when we recognize income tax expenses and benefits. We have deferred tax assets mostly relating to workers compensation liabilities. We routinely evaluate all deferred tax assets to determine the likelihood of their realization. We have not recorded a valuation allowance as of December 31, 2005 and 2004, respectively.

In addition, as of December 31, 2005 and 2004 we had $18.1 million and $20.9 million, respectively, 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 differences will be reduced as the assets are depreciated for financial accounting purposes on a straight-line basis over the next seven years. As the amortization of these permanent differences is a fixed amount, our effective tax rate varies widely based upon the current level of income or loss. See Note 3 to our consolidated financial statements for a reconciliation of our statutory to effective tax rate.

Financial Condition and Liquidity

The following table summarizes our financial position as of December 31, 2005 and December 31, 2004.


	December 31, 2005				December 31, 2004
			(Dollars in thousands)
	Amount		%		Amount		%
Working capital	$	250,446		32	$	118,096		20
Property and equipment, net		499,965		65		437,330		76
Goodwill		10,377		1		10,377		2
Other noncurrent assets		13,098		2		9,489		2

Total	$	773,886		100	$	575,292		100


Long-term debt	$	275,000		35	$	275,000		48
Other long-term liabilities		129,654		17		62,810		11
Shareholders’ equity		369,232		48		237,482		41

Total	$	773,886		100	$	575,292		100

Significant Changes in Financial Condition

The significant changes in our financial position from December 31, 2004 to December 31, 2005 are an increase in working capital of $132.4 million, an increase in net property and equipment of $62.6 million, an increase in other long-term liabilities of $66.8 million, and an increase in shareholders’ equity of $131.8 million. The increase in working capital is primarily the result of higher balances in cash and cash equivalents and accounts receivable, partially offset by higher accounts payable and accrued current liability balances. The increases in cash and cash equivalents, accounts receivable and accounts payable are due to more rigs working and increased dayrates during 2005 and higher current income taxes payable due to higher income. In addition, accrued liability balances are higher due primarily to accrued payroll and workers’ compensation costs as a result of the increase in activity. The increase in net property and equipment is due to capital expenditures during 2005, partially offset by depreciation. Capital expenditures of $131.4 million in 2005 include the costs to reactivate 11 rigs that were held for refurbishment, drill pipe purchases, and betterments and improvements to our rigs. The increase in other long-term liabilities is primarily due to deferred tax liabilities which increased as a result of current-period net income and the use of net operating loss carryforwards that were previously included in this line. The increase in shareholders’ equity is primarily due to the net income for the period and the exercise of stock options.

Floating Rate Notes

On March 31, 2004, we issued $100.0 million aggregate principal amount of Floating Rate Notes in a private offering that yielded net proceeds of approximately $97.8 million. On April 27, 2004, one of the initial purchasers in our private offering of Floating Rate Notes exercised its option to purchase an additional $25.0 million

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aggregate principal amount of the Floating Rate Notes with the same terms. This yielded net proceeds of $24.4 million. 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%. The Floating Rate Notes mature on April 1, 2024. The average interest rate was 3.27% and 1.56% on the Floating Rate Notes for the years ended December 31, 2005 and 2004, respectively. The interest rate is 4.53% for the first quarter of 2006. 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 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, currently 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 holder’s 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 ($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 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 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 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.

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 0.50% per annum during any six-month period, with the initial six-month period commencing May 7, 2008, if the average trading price of the 3.75% Notes per $1,000 principal amount for the five day trading period ending on the third day immediately preceding the first day of the applicable six-month period equals $1,200 or more. The 3.75% Notes are general unsecured senior obligations 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 all of our other senior unsecured debt, including our Floating Rate Notes. Fees and expenses of approximately $4.0 million incurred at the time of issuance are being amortized through May 2013, the first date the holders may require us to repurchase the 3.75% Notes. We may redeem some or all of the 3.75% Notes at any time on or after May 14, 2008, payable in cash, plus accrued but unpaid interest, including contingent interest, if any, to the date of redemption at various redemption prices shown in Note 4 to our consolidated financial statements.

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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 holder’s option, prior to the maturity date into shares of our common stock in the following circumstances:

	•		during any calendar quarter, if the closing sale price per share of our common stock for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the calendar quarter preceding the quarter in which the conversion occurs, is more than 110% of the conversion price per share ($7.10 per share) on that 30th trading day;

	•		if we have called the 3.75% Notes for redemption;

	•		during any period that the credit ratings assigned to the 3.75% Notes by both Moody’s 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.

As of October 1, 2005, and through the first quarter of 2006, the 3.75% Notes were convertible into shares of our common stock because one of the triggering events permitting note holders to convert their 3.75% Notes occurred during the third and fourth quarters of 2005. The triggering event was that the closing price per share of our common stock exceeded 110% of the conversion price ($7.10 per share) of the 3.75% Notes for at least 20 trading days in the period of 30 consecutive trading days ended on both September 30, 2005 and December 31, 2005. As of February 23, 2006, none of the note holders had exercised their right to convert the 3.75% Notes into shares of our common stock.

The 3.75% Notes will cease to be convertible after March 31, 2006 unless this triggering event is again met during the first quarter of 2006. The 3.75% Notes may also become convertible (or remain convertible) after the first quarter of 2006 if any of the other events that entitle note holders to convert the 3.75% Notes occur.

8 7/8% Senior Notes due 2007

On March 31, 2004, $90.0 million of the net proceeds received from the issuance of the Floating Rate Notes was irrevocably deposited with the trustee for the 8 7/8% Senior Notes due 2007 (the “8 7/8% Notes”) to redeem all outstanding notes at 102.9580%, plus accrued interest. On April 30, 2004, the cash deposited with the trustee was used to redeem the $85.0 million aggregate principal amount of the 8 7/8% Notes. The redemption premium of $2.5 million is included in interest expense during the quarter ended March 31, 2004 and the remaining $1.1 million of deferred financing costs associated with the 8 7/8% Notes was accelerated and amortized through the redemption date of April 30, 2004.

CIT Facility

Our subsidiary Grey Wolf Drilling Company L.P. has a $100.0 million credit facility with the CIT Group/Business Credit, Inc. (the “CIT Facility”) which was amended in December 2004 and expires December 31, 2008. The CIT Facility 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 is a revolving facility with automatic renewals after expiration unless terminated by the lender on any subsequent anniversary date and then only upon 60 days prior notice. Periodic interest payments are due at a floating rate based upon our debt service coverage ratio within a range of either LIBOR plus 1.75% to 3.50% or prime plus 0.25% to 1.50%. The CIT Facility provides up to $50.0 million available for letters of credit. We are required to pay a quarterly commitment fee of 0.50% 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 guarantees of certain of our wholly-owned

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subsidiaries. We, however, 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.

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:

	•		1 to 1 EBITDA coverage of debt service, tested monthly on a trailing 12 month basis; and

	•		minimum tangible net worth (as defined in the CIT Facility) at the end of each quarter will be at least the prior year tangible net worth less non-cash write-downs since the prior year-end and less fixed amounts for each quarter end for which the test is calculated.

At December 31, 2005, our liquidity as defined above was $249.2 million. 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 Company or obtained the power to elect a majority of our board of directors, or our board of directors ceases to consist of a majority of “continuing directors” (as defined by the CIT Facility).

As of the date of this report, we did not have an outstanding balance under the CIT Facility and had $23.9 million of undrawn, standby letters of credit. These standby letters of credit are for the benefit of various insurance companies as collateral for premiums and losses which may become payable under the terms of the underlying insurance contracts. Outstanding letters of credit reduce the amount available for borrowing under 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):


	Years Ended December 31,
	2005			2004			2003
Net cash provided by (used in):
Operating activities	$	221,612		$	45,146		$	(7,040	)
Investing activities		(128,250	)		(74,077	)		(33,927	)
Financing activities		8,073			46,291			(18,582	)

Net increase (decrease) in cash:	$	101,435		$	17,360		$	(59,549	)

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, 2005 was $221.6 million compared to $45.1 million during the year ended December 31, 2004. This increase is due primarily to an increase in EBITDA and net income as a result of higher dayrates and rig activity.

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 is due to an increase in EBITDA and net income as a result of higher dayrates and rig activity.

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Cash flow used in investing activities for the year ended December 31, 2005 primarily consisted of $131.4 million of capital expenditures partially offset by proceeds from sales of equipment. Capital expenditures in 2005 included costs for the reactivation of 11 rigs available for refurbishment. For the year ended December 31, 2004, cash flow used in investing activities consisted primarily of $28.9 million of cash paid in the Patriot acquisition and $47.0 million in capital expenditures. For the year ended December 31, 2003, cash flow used in investing activities consisted of capital expenditures of $35.1 million. Capital expenditures for 2005, 2004 and 2003 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 the year ended December 31, 2005, consisted of proceeds of $8.1 million from the exercise of stock options. 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, partially offset by $85.0 million for the redemption of the 8 7/8% 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 7/8% Notes 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 as of December 31, 2005 (amounts in thousands):


	Payments Due by Period ⁽¹⁾
			Less than		1-3		4-5		After 5
Contractual Obligation	Total		1 year		years		years		years
3.75% Notes⁽²⁾
Principal	$	150,000	$	—	$	—	$	—	$	150,000
Interest		98,438		5,625		11,250		11,250		70,313
Floating Rate Notes⁽²⁾
Principal		125,000		—		—		—		125,000
Interest⁽³⁾		103,341		5,663		11,325		11,325		75,028
Operating leases		3,166		757		1,254		1,108		47

Total contractual cash obligations	$	479,945	$	12,045	$	23,829	$	23,683	$	420,388


(1)		This assumes no conversion under, or acceleration of maturity dates due to redemption, breach of, or default under, the terms of the applicable contractual obligation.

(2)		See “Floating Rate Notes” and “3.75% Notes”, above, for information relating to covenants, the breach of which could cause a default under, and acceleration of, the maturity date. Also see “3.75% Notes” and “Floating Rate Notes” for information related to the holders’ conversion rights.

(3)		Assumes the 3-month LIBOR effective for the first quarter of 2006 of 4.58% minus a spread of 0.05% (4.53%)

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 $76.1 million at December 31, 2005. The following table illustrates the undrawn outstanding standby letters of credit at December 31, 2005 and the potential maturities if drawn upon by the holders (amounts in thousands):


	Payments Due by Period ⁽¹⁾
Potential	Total		Less than		1-3		4-5		Over 5
Contractual Obligation	Committed		1 year		years		years		Years
Standby letters of credit	$	23,874	$	—	$	23,874	$	—	$	—

Total	$	23,874	$	—	$	23,874	$	—	$	—


(1)		Assumes no acceleration of maturity date due to breach of, or default under, the potential contractual obligation.

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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 2006. 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.

Capital expenditures for 2006 are projected to be between $180.0 million and $190.0 million, subject to the actual level of rig activity and the ultimate number of new rig purchases and rig reactivations. We expect to spend approximately $45.6 million to reactivate all four of our remaining rigs held for refurbishment during 2006. Each is expected to be significantly upgraded. Refurbishment of two of these rigs is currently underway with one of these rigs (1,000 horsepower) projected to start work near the end of the first quarter of 2006 and another rig (3,000 horsepower) expected to start work in the second quarter of 2006. We have obtained long-term contracts on each of these rigs which, in the aggregate, are expected to generate revenue of approximately $34.8 million over the term of the contracts. We believe that this revenue will be sufficient to recover, after operating expenses, our capital cost of refurbishing the rigs.

We also expect to spend approximately $60.0 million to purchase four new 1,500 horsepower drilling rigs to be delivered late in 2006. We have obtained long-term contracts on each of these rigs which, in the aggregate, are expected to generate revenue of approximately $104.4 million over the term of the contracts. We believe that this revenue will be sufficient to recover, after operating expenses, the purchase price of these rigs.

In addition, our projected capital expenditures for 2006 include costs for betterments and improvements to our rigs, the acquisition of drill pipe and drill collars, the purchase of top drives, and other capital items.

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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	Three Months
	Ended
	March 31, 2006			Years Ended December 31,
	(projected)⁽¹⁾			2005			2004			2003
Earnings before interest expense, taxes, depreciation and amortization	$	84,950		$	265,775		$	84,342		$	30,770
Depreciation and amortization		(17,190	)		(61,279	)		(55,329	)		(50,521	)
Interest expense		(3,285	)		(11,364	)		(14,759	)		(27,832	)
Total income tax (expense) benefit		(24,204	)		(72,495	)		(6,176	)		17,383

Net income (loss) applicable to common shares	$	40,271		$	120,637		$	8,078		$	(30,200	)


(1)		These projections do not include an after tax gain of $5.9 million related to the sale of five of our rigs available for refurbishment on January 3, 2006.

The following tables highlight rig days worked, contract drilling revenues and EBITDA for our daywork and turnkey operations for the years ended December 31, 2005, 2004 and 2003.


	For the Year Ended December 31, 2005
	Daywork			Turnkey
	Operations			Operations⁽¹⁾			Total
	(Dollars in thousands, except averages per rig day worked)
Rig days worked		33,718			3,511			37,229

Contract drilling revenues	$	538,250		$	158,729		$	696,979
Drilling operations expenses		(308,708	)		(109,936	)		(418,644	)
General and administrative expense⁽²⁾		(14,750	)		(1,498	)		(16,248	)
Interest income⁽²⁾		3,236			337			3,573
Gain on sale of assets⁽²⁾		111			4			115
EBITDA	$	218,139		$	47,636		$	265,775


Averages per rig day worked:
Contract drilling revenues	$	15,963		$	45,209		$	18,721

EBITDA	$	6,470		$	13,568		$	7,139


	For the Year Ended December 31, 2004
	Daywork			Turnkey
	Operations			Operations⁽¹⁾			Total
	(Dollars in thousands, except averages per rig day worked)
Rig days worked		27,616			3,561			31,177

Contract drilling revenues	$	308,851		$	115,783		$	424,634
Drilling operations expenses		(234,630	)		(93,167	)		(327,797	)
General and administrative expense⁽²⁾		(11,935	)		(1,382	)		(13,317	)
Interest income⁽²⁾		691			86			777
Gain on sale of assets⁽²⁾		34			11			45
EBITDA	$	63,011		$	21,331		$	84,342


Averages per rig day worked:
Contract drilling revenues	$	11,184		$	32,515		$	13,620

EBITDA	$	2,282		$	5,990		$	2,705

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	For the Year Ended December 31, 2003
	Daywork			Turnkey
	Operations			Operations⁽¹⁾			Total
	(Dollars in thousands, except averages per rig day worked)
Rig days worked		18,700			3,447			22,147

Contract drilling revenues	$	178,818		$	107,156		$	285,974
Drilling operations expenses		(158,141	)		(86,146	)		(244,287	)
General and administrative expenses⁽²⁾		(10,472	)		(1,494	)		(11,966	)
Interest income⁽²⁾		812			142			954
Gain on sale of assets⁽²⁾		69			12			81
Other, net⁽²⁾		12			2			14

EBITDA	$	11,098		$	19,672		$	30,770


Averages per rig day worked:
Contract drilling revenues	$	9,562		$	31,087		$	12,913

EBITDA	$	593		$	5,707		$	1,389


(1)		Turnkey operations include the results from turnkey and footage contracts.

(2)		These income and expense items are not contract related and are allocated between daywork and turnkey based upon operating rig days.

Comparison of Fiscal Years ended December 31, 2005 and 2004

Our EBITDA increased by $181.4 million, or 215%, to $265.8 million for the year ended December 31, 2005 from $84.3 million for the year ended December 31, 2004. The increase resulted from a $155.1 million increase in EBITDA from daywork operations and a $26.3 million increase in EBITDA from turnkey operations. On a per rig day basis, our total EBITDA increased by $4,434, or 164% to $7,139 in 2005 from $2,705 in 2004. This increase included a $4,188 per rig day increase from daywork operations and a $7,578 per rig day increase from turnkey operations. Total general and administrative expenses increased by $2.9 million primarily due to higher payroll and short-term incentive costs, and professional fees. Total interest income increased by $2.8 million due to higher cash balances and higher interest rates in 2005 compared to 2004.

Daywork Operations

The increase in EBITDA discussed above was due in part to an increase of 22%, or 6,102 rig days worked on daywork contracts during 2005 compared to 2004. This increase in days was due primarily to overall higher demand for our services. Higher dayrates contributed significantly to the increase in EBITDA with contract drilling revenue per rig day increasing $4,779, or 43%; however, this increase includes approximately $250 average per rig day related to a wage increase effective June 1, 2005 that was passed on to our customers in the form of higher dayrates.

Drilling operations expenses increased overall, and on a per rig day basis, due to higher activity levels, as well as several other factors. Those factors include the above-mentioned wage increase, crews being kept on the payroll during unanticipated maintenance, the implementation of an employee retention program and increases in other labor costs. In November 2005, we implemented a two-year employee retention program for our experienced rig-based personnel. The purpose of this program is to retain key operational personnel on our rigs and reduce the cost of turnover and improve safety and efficiency at the rig site. The program had a $50 per rig day impact on operating costs during the year ended December 31, 2005 and is expected to have an estimated $300 per rig day impact on operating costs in 2006.

Turnkey Operations

Turnkey EBITDA per rig day increased $7,578, or 127%, to $13,568 for the year ended December 31, 2005, from $5,990 for the year ended December 31, 2004. The increase in EBITDA per rig day was due primarily to higher revenue in total and on a per rig day basis. Contract drilling revenue per rig day increased $12,694, or 39% primarily resulting from higher daywork dayrates, which are considered in our turnkey bidding process. Also,

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differences in the complexity and success of the wells drilled between the two periods contributed to the increased EBITDA.

Other

Depreciation and amortization expense increased by $6.0 million, or 11% to $61.3 million for the year ended December 31, 2005 compared to $55.3 million for the year ended December 31, 2004. Depreciation and amortization expense is higher due to the acquisition of Patriot during the second quarter of 2004, and capital expenditures during 2004 and 2005 for the reactivation of rigs available for refurbishment, betterments and improvements to our rigs, the acquisition of drill pipe and drill collars, and other capital items.

Interest expense decreased by $3.4 million, or 23%, to $11.4 million for 2005 from $14.8 million for 2004. The decrease is due to the issuance of the 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. In addition, the first half of 2004 included a $2.5 million redemption premium and accelerated amortization of $1.1 million of deferred financing costs on the 8 7/8%Notes.

Our income tax expense increased by $66.3 million to $72.5 million in 2005, from $6.2 million in 2004. 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 seven years. As the amortization of these permanent differences is a fixed amount, our book effective tax rate decreased from 43% in 2004 to 37% in 2005 based upon the level of income.

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, drilling operations 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 for the reactivation of rigs available for refurbishment, betterments and improvements to our rigs, the acquisition of drill pipe and drill collars, and other capital items.

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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 based upon the levels of income or loss.

Inflation and Changing Prices

Contract drilling revenues do not necessarily track the changes in general inflation as they tend to respond to the level of activity of the oil and 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 demand for drilling services and to a lesser extent by changes in general inflation. Our daywork contracts generally allow us to pass wage increases, the most significant component of our operating costs, on to our customers in the form of higher dayrates.

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, 2005. 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 February 23, 2006 and as such have no exposure under this facility to a change in interest rates.

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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 of the Treadway Commission (COSO). 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, 2005. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included on page 36.


/s/ Thomas P. Richards		/s/ David W. Wehlmann

Thomas P. Richards		David W. Wehlmann
Chairman, President and Chief Executive Officer		Executive Vice President and Chief Financial Officer

March 1, 2006

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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, 2005 and 2004, 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, 2005. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule for the years ended December 31, 2005, 2004 and 2003. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, 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, 2005, 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 1, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Houston, Texas
March 1, 2006

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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, 2005, 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.

In our opinion, management’s assessment that Grey Wolf, Inc. maintained effective internal control over financial reporting as of December 31, 2005, 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, 2005, 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, 2005 and 2004, 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, 2005, and our report dated March 1, 2006, expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Houston, Texas
March 1, 2006

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GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Amounts in thousands, except share data)


	December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	173,145		$	71,710
Restricted cash — insurance deposits		780			758
Accounts receivable, net of allowance of $2,674 and $2,424, respectively		159,438			98,065
Prepaids and other current assets		8,010			5,097
Deferred tax assets		4,222			3,050

Total current assets		345,595			178,680


Property and equipment:
Land, buildings and improvements		6,530			5,061
Drilling equipment		934,648			824,901
Furniture and fixtures		4,217			3,578

Total property and equipment		945,395			833,540
Less: accumulated depreciation		(445,430	)		(396,210	)

Net property and equipment		499,965			437,330

Rigs held for sale, net		5,524			—
Goodwill		10,377			10,377
Other noncurrent assets, net		7,574			9,489

	$	869,035		$	635,876


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable — trade	$	61,087		$	42,754
Accrued workers’ compensation		6,575			4,303
Payroll and related employee costs		12,131			8,699
Accrued interest payable		2,156			1,516
Current income taxes payable		6,141			200
Other accrued liabilities		7,059			3,112

Total current liabilities		95,149			60,584


Contingent convertible notes		275,000			275,000
Other long-term liabilities		12,403			7,509
Deferred income taxes		117,251			55,301

Commitments and contingent liabilities		—			—

Shareholders’ equity:
Series B Junior Participating Preferred stock, $1 par value; 250,000 shares authorized, none outstanding		—			—
Common stock, $.10 par value; 300,000,000 shares authorized 192,625,650 and 190,136,471 issued and outstanding, respectively		19,263			19,014
Unearned restricted stock awards		(937	)		—
Additional paid-in capital		374,949			363,148
Accumulated deficit		(24,043	)		(144,680	)

Total shareholders’ equity		369,232			237,482

	$	869,035		$	635,876

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)


	Years Ended December 31,
	2005			2004			2003
Revenues:
Contract drilling	$	696,979		$	424,634		$	285,974

Costs and expenses:
Drilling operations		418,644			327,797			244,287
Depreciation and amortization		61,279			55,329			50,521
General and administrative		16,248			13,317			11,966
Gain on sale of assets		(115	)		(45	)		(81	)

Total costs and expenses		496,056			396,398			306,693


Operating income (loss)		200,923			28,236			(20,719	)

Other income (expense):
Interest expense		(11,364	)		(14,759	)		(27,832	)
Interest income		3,573			777			954
Other, net		—			—			14

Other expense, net		(7,791	)		(13,982	)		(26,864	)


Income (loss) before income taxes		193,132			14,254			(47,583	)

Income tax expense (benefit):
Current		11,717			200			(938	)
Deferred		60,778			5,976			(16,445	)

Total income tax expense (benefit)		72,495			6,176			(17,383	)


Net income (loss)	$	120,637		$	8,078		$	(30,200	)


Net income (loss) per common share (Note 1):
Basic	$	0.63		$	0.04		$	(0.17	)

Diluted	$	0.54		$	0.04		$	(0.17	)


Weighted average common shares outstanding:
Basic		191,364			185,868			181,210

Diluted		235,412			187,654			181,210

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)


	Series B
	Junior
	Participating				Common				Unearned
	Preferred				Stock		Additional		Restricted
	Stock		Common		$.10 par		Paid-in		Stock
	$1 par Value		Shares		Value		Capital		Awards			Deficit			Total
Balance, December 31, 2002		—		181,038	$	18,104	$	329,712		—		$	(122,558	)	$	225,258

Exercise of stock options		—		245		25		343		—			—			368

Tax benefit of stock option exercises		—		—		—		211		—			—			211

Comprehensive net loss		—		—		—		—		—			(30,200	)		(30,200	)


Balance, December 31, 2003		—		181,283		18,129		330,266		—			(152,758	)		195,637

Non-cash compensation expense		—		—		—		77		—			—			77

Exercise of stock options		—		4,243		424		9,729		—			—			10,153

Tax benefit of stock option exercises		—		—		—		3,193		—			—			3,193

Issuance of common stock		—		4,610		461		19,883		—			—			20,344

Comprehensive net income		—		—		—		—		—			8,078			8,078


Balance, December 31, 2004		—		190,136		19,014		363,148		—			(144,680	)		237,482

Exercise of stock options		—		2,292		229		7,844		—			—			8,073

Tax benefit of stock option exercises		—		—		—		2,842		—			—			2,842

Issuance of restricted stock		—		198		20		1,115		(1,135	)		—			—

Amortization of restricted stock awards		—		—		—		—		198			—			198

Comprehensive net income		—		—		—		—		—			120,637			120,637


Balance, December 31, 2005		—		192,626	$	19,263	$	374,949	$	(937	)	$	(24,043	)	$	369,232

See accompanying notes to consolidated financial statements

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GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Amounts in thousands)


	Years Ended December 31,
	2005			2004			2003
Cash flows from operating activities:
Net income (loss)	$	120,637		$	8,078		$	(30,200	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		61,279			55,329			50,521
Non-cash compensation expense		—			77			—
Gain on sale of assets		(115	)		(45	)		(81	)
Amortization of restricted stock awards		198			—			—
Foreign exchange gain		—			—			(14	)
Deferred income taxes		60,778			2,778			(16,656	)
Accretion of debt discount		—			102			285
Tax benefit of stock option exercises		2,842			3,193			211
(Increase) decrease in restricted cash		(22	)		(9	)		35
Increase in accounts receivable		(61,373	)		(34,128	)		(13,147	)
Increase in other current assets		(2,913	)		(718	)		(961	)
Increase in trade accounts payable		18,333			9,596			8,476
Increase (decrease) in accrued workers’ compensation		6,257			2,402			(326	)
Increase (decrease) in other current liabilities		13,960			(3,442	)		(8,660	)
Increase in other		1,751			1,933			3,477

Cash provided by (used in) operating activities		221,612			45,146			(7,040	)


Cash flows from investing activities:
Property and equipment additions		(131,352	)		(46,951	)		(35,102	)
Payments to acquire New Patriot Drilling Corp.		—			(28,906	)		—
Proceeds from sales of equipment		3,102			1,780			1,175

Cash used in investing activities		(128,250	)		(74,077	)		(33,927	)


Cash flows from financing activities:
Net proceeds from long-term debt		—			122,187			146,625
Repayments of long-term debt		—			(85,000	)		(165,000	)
Financing costs		—			(1,049	)		(575	)
Proceeds from exercise of stock options		8,073			10,153			368

Cash provided by (used in) financing activities		8,073			46,291			(18,582	)


Net increase (decrease) in cash and cash equivalents		101,435			17,360			(59,549	)
Cash and cash equivalents, beginning of year		71,710			54,350			113,899

Cash and cash equivalents, end of year	$	173,145		$	71,710		$	54,350


Supplemental Cash Flow Disclosure:
Cash paid for interest	$	9,862		$	15,872		$	30,510

Cash paid for (refund of) taxes	$	2,985		$	—		$	(879	)

See accompanying notes to consolidated financial statements

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)

Summary of Significant Accounting Policies

Nature of Operations. Grey Wolf, Inc. is a Texas corporation formed in 1980. Grey Wolf, Inc. is a holding company with no independent assets or operations but through its subsidiaries is engaged in the business of providing onshore contract drilling services to the oil and natural gas industry. Grey Wolf, Inc., through its subsidiaries, currently conducts operations primarily in Alabama, Arkansas, Colorado, Louisiana, Mississippi, New Mexico, Oklahoma, Texas, Utah and Wyoming. The consolidated financial statements include the accounts of Grey Wolf, Inc. and its majority-owned subsidiaries (the “Company” or “Grey Wolf”). All significant intercompany accounts and transactions are eliminated in consolidation.

Property and Equipment. Property and equipment are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, as follows:


	Useful Lives (in years)
Drilling rigs and related equipment		3-15
Furniture and fixtures		7
Buildings and improvements		5-20
Vehicles		3-6
Other		3-5

Depreciation expense for the years ended December 31, 2005 and 2004 was $60.2 million and $54.5 million, respectively.

Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment of assets to be held and used is determined by a comparison of the carrying amount of an asset to undiscounted future net cash flows expected to be generated by an asset. If such assets are considered to be impaired, the impairment to be recognized is measured by an amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

Goodwill and Intangible Assets. Goodwill represents the excess of costs over the fair value of assets of a business acquired. The Company follows 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 their estimated residual values, and reviewed for impairment in accordance with SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” The Company’s intangible assets represent customer contracts and related relationships acquired and are being amortized over the useful life of three years.

Revenue Recognition. Contract drilling revenues are earned under daywork, turnkey and footage contracts. Revenue from daywork and footage contracts is recognized when it is realized or realizable and earned. On daywork contracts revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. On footage contracts revenue is recognized based on the number of feet that have been drilled at fixed rates stipulated by the contract. Revenue from turnkey drilling contracts is recognized using the percentage-of-completion method based upon costs incurred to date and estimated total contract costs. Provision is made currently for anticipated losses, if any, on uncompleted contracts.

Accounts Receivable. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts represents the Company’s estimate of the amount of probable credit losses existing in the Company’s accounts receivable. The Company determines the allowance based on a review of customer balances and the deemed probability of collection. This review consists of analyzing the age of individual balances, payment history of customers and other known factors.

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Earnings per Share. Basic earnings per share (“EPS”) is based on the weighted average number of common shares outstanding during the applicable period and excludes the nonvested portion of restricted stock. The computation of diluted earnings per share is based on the weighted average number of common shares outstanding during the period plus, when their effect is dilutive, incremental shares consisting of shares subject to stock options, restricted stock and shares issuable upon conversion of the Floating Rate Contingent Convertible Senior Notes due 2024 (the “Floating Rate Notes”) and the 3.75% Contingent Convertible Senior Notes due 2023 (the “3.75% Notes”) (collectively referred to as the “Contingent Convertible Senior Notes”).

Consistent with the provisions of Emerging Issues Task Force (“EITF”) Issue No. 04-08, “The Effect of Contingently Convertible Instruments on Diluted Earnings per Share,” the Company accounts for the Contingent Convertible Senior Notes using the “if converted” method set forth in the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 128 “Earnings Per Share” for calculating diluted earnings per share. Under the “if converted” method, the after-tax effect of interest expense related to the Contingent Convertible Senior Notes is added back to net income, and the convertible debt is assumed to have been converted to common equity at the beginning of the period and is added to outstanding shares. The following is a reconciliation of the components of the basic and diluted earnings per share calculations for the applicable periods:


	2005		2004		2003
	(In thousands, except per share amounts)
Numerator:
Net income (loss)	$	120,637	$	8,078	$	(30,200	)

Add interest expense on contingent convertible senior notes, net of related tax effects		6,596		—		—

Adjusted net income (loss) — diluted	$	127,233	$	8,078	$	(30,200	)


Denominator:
Weighted average common shares outstanding — basic		191,364		185,868		181,210

Effect of dilutive securities:
Options — treasury stock method		1,552		1,786		—
Restricted stock — treasury stock method		39		—		—
Contingent convertible senior notes		42,457		—		—


Weighted average common shares outstanding — diluted		235,412		187,654		181,210


Earnings (loss) per common share:
Basic	$	0.63	$	0.04	$	(0.17	)

Diluted	$	0.54	$	0.04	$	(0.17	)

In 2005, the Company excluded 197,750 shares of restricted stock from the computation of basic EPS as the vesting conditions had not been met. In 2004, the Company excluded approximately 23.3 million shares and 19.2 million shares issuable upon conversion of the 3.75% Notes and Floating Rate Notes, respectively (see Note 4) as the inclusion of these shares would be anti-dilutive at the level of income in 2004. The Company also excluded approximately 900,000 options in 2004 as the option prices were greater than the market price of the underlying common stock and, therefore, the effect would be anti-dilutive. The Company incurred a net loss for the year ended December 31, 2003 and, therefore, excluded securities from the computation of diluted earnings per share as the effect would be anti-dilutive. Securities excluded from the computation of diluted earnings per share for the year ended December 31, 2003 included the 23.3 million shares issuable upon conversion of the 3.75% Notes. In

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

addition to those securities, options to purchase 10.2 million shares for the years ended December 31, 2003 were excluded from the diluted EPS calculation.

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

Stock-Based Compensation. The Company applies Accounting Principles Board Opinion No. 25 (“APB 25”), “Accounting for Stock Issued to Employees,” and related interpretation in accounting for its stock-based compensation. Accordingly, no compensation expense has been recognized for stock option grants as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Had compensation expense for the stock option grants been determined on the fair value at the grant dates consistent with the method of Statement of Financial Accounting Standard No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation,” the Company’s net income (loss) and net income (loss) per share would have been adjusted to the pro forma amounts indicated below (amounts in thousands, except per share data):


	2005			2004			2003
Net income (loss), as reported	$	120,637		$	8,078		$	(30,200	)
Add: Stock-based employee compensation expense included in reporting net income (loss), net of related tax effects		124			52			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,322	)		(2,082	)		(2,523	)

Pro forma net income (loss)	$	118,439		$	6,048		$	(32,723	)


Basic earnings per share
As reported	$	0.63		$	0.04		$	(0.17	)
Pro forma	$	0.62		$	0.03		$	(0.18	)
Diluted earnings per share
As reported	$	0.54		$	0.04		$	(0.17	)
Pro forma	$	0.53		$	0.03		$	(0.18	)

For purposes of determining compensation costs using the provisions of SFAS No. 123, the fair value of option grants was determined using the Black-Scholes option-valuation model. The weighted average fair value per share of stock options granted was $2.99 in 2005, $3.92 in 2004 and $2.36 in 2003. The key input variables used in valuing the options granted in 2005, 2004 and 2003 were: risk-free interest rate based on five-year Treasury strips of 3.86% to 4.46% in 2005, 3.36% to 3.67% in 2004, and 2.89% to 3.35% in 2003; dividend yield of zero in each year; stock price volatility of 53% to 57% for 2005, 55% to 56% for 2004, and 66% to 71% for 2003, respectively; and expected option lives of five years for each year presented.

Compensation expense on shares of the Company’s restricted stock is recognized on straight-line basis over the five-year service period in which the shares vest. The value of restricted stock not yet expensed is shown as unearned restricted stock awards within shareholders’ equity.

Fair Value of Financial Instruments. The carrying amount of the Company’s cash and short-term investments approximates fair value because of the short maturity of those instruments. The carrying amount of the Company’s credit facility approximates fair value as the interest is indexed to the prime rate or LIBOR. The fair value of the 3.75% Contingent Convertible Senior Notes was $192.6 million and $154.2 million at December 31, 2005 and 2004, respectively versus a face value of $150.0 million. The fair value of the Floating Rate Notes was

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$170.5 million and $131.1 million at December 31, 2005 and 2004, respectively, versus a face value of $125.0 million. Fair value was estimated based on quoted market prices.

Cash Flow Information. Cash flow statements are prepared using the indirect method. The Company considers all unrestricted highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents.

Restricted Cash. Restricted cash consists of investments in interest bearing certificates of deposit which are used as collateral for letters of credit securing insurance deposits. The carrying value of the investments approximates the current market value.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the use of certain estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

Concentrations of Credit Risk. Substantially all of the Company’s contract drilling activities are conducted with major and independent oil and natural gas companies in the United States. Historically, the Company has not required collateral or other security for the related receivables from such customers. However, the Company has required certain customers to deposit funds in escrow prior to the commencement of drilling. Actions typically taken by the Company in the event of nonpayment include filing a lien on the customer’s producing properties and filing suit against the customer.

Comprehensive Income. Comprehensive income includes all changes in a company’s equity during the period that result from transactions and other economic events, other than transactions with its shareholders.

Recent Accounting Pronouncements. In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets”, which amends APB Opinion No. 29. The guidance in APB 29, Accounting for Nonmonetary Transactions, is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The amendment made by SFAS 153 eliminates the exception for exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions of the statement were effective for exchanges taking place in fiscal periods beginning after June 15, 2005. The adoption of the standard did not have a material impact on the consolidated financial statements.

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which replaces SFAS 123 and supersedes APB 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first fiscal year beginning after June 15, 2005. The Company will adopt SFAS 123R effective January 1, 2006 using a modified prospective method. The modified prospective method requires companies to recognize compensation cost for unvested awards that are outstanding on the effective date based on the fair value that the company had originally estimated for purposes of preparing its SFAS 123 pro forma disclosures. For all new awards that are granted or modified after the effective date; however, SFAS 123R will result in some amounts previously reported in the statement of cash flow as operating activities, to be reported as financing activities. These amounts are the benefits of tax deductions in excess of recognized compensation, which for the Company were $2.8 million, $3.2 million and $211,000 in 2005, 2004 and 2003, respectively.

In March 2005, the FASB issued FASB Interpretation No. (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 clarifies that the term conditional asset retirement obligation, as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company adopted FIN 47 as of the effective date. The adoption of the standard did not have a material effect on the Company’s consolidated financial statements for the year ending December 31, 2005.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”. This Statement replaces APB Opinion No. 20, “Accounting Changes,” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements,” and changes the requirements of accounting for and reporting of a change in accounting principle. SFAS No. 154 requires, among other things, retrospective application of a voluntary change in accounting principle. Previously, voluntary changes in accounting principle were accounted for by including a one-time cumulative effect in the period of change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

Reclassification. Certain prior period balances have been reclassified to conform to the presentations in 2005.

(2)

Acquisitions and Intangible Assets

On April 6, 2004, the Company acquired all of the outstanding capital stock and stock equivalents of New Patriot Drilling Corp. (“Patriot”) by merger. The Company recorded all revenue and expenses since that date. 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 aggregate purchase price for Patriot was $49.5 million, including $14.2 million in cash, $14.7 million in cash to retire the outstanding debt of Patriot and 4,610,480 shares of the Company’s common stock valued at $20.6 million. The value of the common stock issued was determined based upon the average market price of the Company’s common stock over the five day period beginning two days before and ending two days after the signing of the agreement and plan of merger.

The purchase price was allocated among assets acquired and liabilities assumed based on their fair market value at the date of acquisition. The purchase price allocation is as follows (in thousands):


Current assets	$	3,992
Property and equipment		42,384
Intangible assets		3,200
Goodwill		10,377

Total assets acquired		59,953

Current liabilities		(4,490	)
Deferred tax liabilities		(5,977	)


Total liabilities assumed		(10,467	)


Net assets acquired	$	49,486

Goodwill represents the excess of costs over the fair value of assets of the business acquired. At June 30, 2004, the Company had goodwill of $9.2 million. Goodwill increased to $10.4 million at September 30, 2004 due to working capital adjustments per the terms of the purchase and sales agreement. None of the goodwill resulting from this acquisition is deductible for tax purposes. The intangible assets represent customer contracts and related relationships acquired and are being amortized over the useful life of three years. Amortization expenses related to these intangible assets was $1.1 million and $781,000 at December 31, 2005 and 2004, respectively. Accumulated amortization was $1.8 million at December 31, 2005. Amortization expense related to these intangible assets over the next five fiscal years will be: 2006 – $1.1 million; 2007 – $219,000; and thereafter – $0. The net balance of these intangible assets was included in net other noncurrent assets on the consolidated balance sheets.

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3) Income Taxes

The Company and its U.S. subsidiaries file a consolidated federal income tax return. The components of the provision for income taxes consisted of the following (amounts in thousands):


	For the Years Ended December 31,
	2005		2004			2003
Current
Federal	$	10,260	$	125		$	—
Foreign		107		75			—
State		1,350		—			(938	)

	$	11,717	$	200		$	(938	)


Deferred
Federal	$	56,937	$	6,082		$	(14,958	)
State		3,841		(106	)		(1,487	)

	$	60,778	$	5,976		$	(16,445	)

Deferred income taxes are determined based upon the difference between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes, and net operating loss and tax credit carryforwards. The tax effects of the Company’s temporary differences and carryforwards are as follows (amounts in thousands):


	December 31,
	2005		2004
Deferred tax assets
Net operating loss carryforwards	$	—	$	49,013
Tax credit carryforwards		—		139
Workers compensation accruals		6,717		4,395
Other		1,567		1,847

		8,284		55,394

Deferred tax liabilities
Depreciation		121,313		107,645


Net deferred tax liability	$	113,029	$	52,251

As of December 31, 2005, the Company had utilized all of its U.S. net operating loss (“NOL”) carryforwards. At December 31, 2004, the Company had $158.3 million in NOL carryforwards. No valuation allowance was recorded as of December 31, 2005 and 2004, respectively, as management believes that it is more likely than not that future earnings and reversal of deferred tax liabilities will be sufficient to permit the Company to realize its deferred tax assets.

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following summarizes the differences between the federal statutory tax rate of 35% (amounts in thousands):


	For the Years Ended December 31,
	2005		2004			2003
Income tax expense (benefit) at statutory rate	$	67,596	$	4,989		$	(16,654	)

Increase (decrease) in taxes resulting from:
Permanent differences, primarily due to basis differences in assets that were purchased in capital stock acquisitions		1,360		1,179			1,208
State taxes, net		3,131		(69	)		(1,576	)
Other		408		77			(361	)

Income tax expense (benefit)	$	72,495	$	6,176		$	(17,383	)

(4)

Long-Term Debt

Long-term debt consists of the following (amounts in thousands):


	December 31,
	2005		2004
Contingent convertible senior notes due May 2023, general unsecured senior obligations guaranteed by the Company’s domestic subsidiaries, bearing interest at 3.75% per annum payable semi-annually	$	150,000	$	150,000

Floating rate contingent convertible senior notes due April 2024, general unsecured senior obligations guaranteed by the Company’s domestic subsidiaries, bearing interest of no less than zero or more than 6.00% per annum payable semi-annually		125,000		125,000

		275,000		275,000

Less current maturities		—		—

Long-term debt	$	275,000	$	275,000

Floating Rate Notes

On March 31, 2004, the Company issued $100.0 million aggregate principal amount of Floating Rate Notes in a private offering that yielded net proceeds of approximately $97.8 million. On April 27, 2004, one of the initial purchasers in the Company’s private offering of the Floating Rate Notes exercised its option to purchase an additional $25.0 million aggregate principal amount of the Floating Rate Notes with the same terms. This yielded net proceeds of $24.4 million. The Floating Rate Notes bear interest at a per annum rate equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05%. The per annum interest rate will never be less than zero or more than 6.00%. The average interest rate was 3.27% and 1.56% on the Floating Rate Notes for the years ended December 31, 2005 and 2004, respectively. The interest rate was 4.05% and 1.96% for the quarters ended December 31, 2005 and 2004, respectively. The Floating Rate Notes mature on April 1, 2024. The Floating Rate Notes are convertible into shares of the Company’s 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 general unsecured senior obligations of the Company and are fully and unconditionally guaranteed, on a joint and several basis, by all domestic wholly-owned subsidiaries of the Company. Non-guarantor subsidiaries are immaterial. The Floating Rate Notes and the guarantees rank equally with all of the Company’s other senior unsecured debt, currently the Company’s 3.75%

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Notes. Fees and expenses of approximately $3.6 million incurred at the time of issuance are being amortized through April 1, 2014, the first date the holders may require the Company to repurchase the Floating Rate Notes.

The Company 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 the Company 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 the Company’s common stock under the following circumstances:

	•		during any calendar quarter, if the closing sale price per share of the Company’s 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 ($7.81 per share) on that 30th trading day;

	•		if the Company has called the Floating Rate Notes for redemption;

	•		during any period that the credit ratings assigned to the Company’s 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 the Company’s 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 Floating Rate Notes for each day of such period was less than 95% of the product of the closing sale price per share of the Company’s common stock on that day multiplied by the number of shares of common stock issuable upon conversion of $1,000 principal amount of the Floating Rate Notes; or

	•		upon the occurrence of specified corporate transactions, including a change of control.

The Floating Rate Notes did not meet the criteria for conversion into common stock at any time during the years ended December 31, 2005 and 2004.

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 the Company’s 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 the 3.75% Notes, subject to adjustment. The Company will pay contingent interest at a rate equal to 0.50% per annum during any six-month period, with the initial six-month period commencing May 7, 2008, if the average trading price of the 3.75% Notes per $1,000 principal amount for the five day trading period ending on the third day immediately preceding the first day of the applicable six-month period equals $1,200 or more. The 3.75% Notes are general unsecured senior obligations of the Company and are fully and unconditionally guaranteed, on a joint and several basis, by all domestic wholly-owned subsidiaries of the Company. Non-guarantor subsidiaries are immaterial. The 3.75% Notes and the guarantees rank equally with all of the Company’s other senior unsecured debt, including the Floating Rate Notes. Fees and expenses of $4.0 million incurred at the time of issuance are being amortized through May 2013, the first date the holders may require the Company to repurchase the 3.75% Notes.

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company may redeem some or all of the 3.75% Notes at any time on or after May 14, 2008, at a redemption price shown below, payable in cash, plus accrued but unpaid interest, including contingent interest, if any, to the date of redemption:


	Redemption
Period	Price
May 14, 2008 through May 6, 2009		101.88	%
May 7, 2009 through May 6, 2010		101.50	%
May 7, 2010 through May 6, 2011		101.13	%
May 7, 2011 through May 6, 2012		100.75	%
May 7, 2012 through May 6, 2013		100.38	%
May 7, 2013 and thereafter		100.00	%

Holders may require the Company to repurchase all or a portion of the 3.75% Notes on May 7, 2013 or May 7, 2018, and upon a change of control, as defined in the indenture governing the 3.75% Notes, at 100% of the principal amount of the 3.75% Notes, plus accrued but unpaid interest, including contingent interest, if any, to the date of repurchase, payable in cash.

The 3.75% Notes are convertible, at the holders’ option, prior to the maturity date into shares of the Company’s common stock under the following circumstances:

	•		during any calendar quarter, if the closing sale price per share of the Company’s common stock for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the calendar quarter preceding the quarter in which the conversion occurs, is more than 110% of the conversion price per share ($7.10 per share) on that 30th trading day;

	•		if the Company has called the 3.75% Notes for redemption;

	•		during any period that the credit ratings assigned to the 3.75% Notes by both Moody’s 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 the Company’s common stock on that day multiplied by the number of shares of common stock issuable upon conversion of $1,000 principal amount of the 3.75% Notes; or

	•		upon the occurrence of specified corporate transactions, including a change of control.

As of October 1, 2005, and through the first quarter of 2006, the 3.75% Notes were convertible into shares of the Company’s common stock because one of the triggering events permitting note holders to convert their 3.75% Notes occurred during the third and fourth quarters of 2005. The triggering event was that the closing price per share of the Company’s common stock exceeded 110% of the conversion price ($7.10 per share) of the 3.75% Notes for at least 20 trading days in the period of 30 consecutive trading days ended on both December 31, 2005 and September 30, 2005. As of December 31, 2005, none of the note holders had exercised their right to convert the 3.75% Notes into shares of the Company’s common stock.

The 3.75% Notes will cease to be convertible after March 31, 2006, unless this triggering event is again met during the first quarter of 2006. The 3.75% Notes may also become convertible (or remain convertible) after the first quarter of 2006 if any of the other events that entitle note holders to covert the 3.75% Notes occur.

8⁷/⁸% Senior Notes due 2007

On March 31, 2004, $90.0 million of the net proceeds received from the issuance of the Floating Rate Notes was irrevocably deposited with the trustee for the 8⁷/⁸% Senior Notes due 2007 (the “8⁷/⁸% Notes”) to redeem all outstanding notes at 102.9580%, plus accrued interest. On April 30, 2004, the cash deposited with the trustee was used to redeem the $85.0 million aggregate principal amount of the 8⁷/⁸% Notes. The redemption premium of

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$2.5 million is included in interest expense during the quarter ended March 31, 2004 and the remaining $1.1 million of deferred financing costs associated with the 8⁷/⁸% Notes was accelerated and amortized through the redemption date of April 30, 2004.

CIT Facility

The Company’s subsidiary Grey Wolf Drilling Company L.P. has a $100.0 million credit facility with the CIT Group/Business Credit, Inc. (the “CIT Facility”) which was amended in December 2004 and expires December 31, 2008. The CIT Facility provides the Company 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 is a revolving facility with automatic renewals after expiration unless terminated by the lender on any subsequent anniversary date and then only upon 60 days prior notice. Periodic interest payments are due at a floating rate based upon the Company’s debt service coverage ratio within a range of either LIBOR plus 1.75% to 3.50% or prime plus 0.25% to 1.50%. The CIT Facility provides up to $50.0 million available for letters of credit. The Company is required to pay a quarterly commitment fee of 0.50% per annum on the unused portion of the CIT Facility and letters of credit accrue a fee of 1.25% per annum. The Company incurred $760,000, $610,000, and $480,000 for the years ended December 31, 2005, 2004, and 2003, respectively, related to these fees.

The CIT Facility contains affirmative and negative covenants and the Company is in compliance with these covenants. Substantially all of the Company’s assets, including its drilling equipment, are pledged as collateral under the CIT Facility which is also guaranteed by the Company and certain of the Company’s wholly-owned subsidiaries. The Company, however, retains the option, subject to a minimum appraisal value, under the CIT Facility to extract $75.0 million of the equipment out of the collateral pool in connection with the sale or exchange of such collateral or relocation of equipment outside the contiguous 48 states of the United States of America.

Among the various covenants that the Company must satisfy under the CIT Facility are the following two covenants (as defined in the CIT Facility) which apply whenever the Company’s liquidity, defined as the sum of cash, cash equivalents and availability under the CIT Facility, falls below $35.0 million:

	•		1 to 1 EBITDA coverage of debt service, tested monthly on a trailing 12 month basis; and

	•		minimum tangible net worth (as defined in the CIT Facility) at the end of each quarter will be at least the prior year tangible net worth less non-cash write-downs since the prior year-end and less fixed amounts for each quarter end for which the test is calculated.

At December 31, 2005, the Company’s liquidity as defined above was $249.2 million. Additionally, if the total amount outstanding under the CIT Facility (including outstanding letters of credit) exceeds 50% of the Orderly Liquidation Value of the Company’s domestic rigs, the Company is 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 the Company ceases to own 100% of its two principal subsidiaries, some person or group that has either acquired beneficial ownership of 30% or more of the Company or obtained the power to elect a majority of the Company’s board of directors, or the Company’s board of directors ceases to consist of a majority of “continuing directors” (as defined by the CIT Facility).

-50-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company currently has no outstanding balance under the CIT Facility and had $23.9 million of undrawn, standby letters of credit at December 31, 2005. These standby letters of credit are for the benefit of various insurance companies as collateral for premiums and losses which may become payable under the terms of the underlying insurance contracts. Outstanding letters of credit reduce the amount available for borrowing under the CIT Facility.

Non-Cash Activities

During 2004, the Company issued 4.6 million shares related to the Patriot acquisition (see Note 2). The non-cash amount excluded from the cash flow statement for this common stock issuance was $20.6 million.

(5)

Capital Stock and Stock Option Plans

On September 21, 1998, the Company adopted a Shareholder Rights Plan (the “Plan”) in which rights to purchase shares of Junior Preferred stock will be distributed as a dividend at the rate of one Right for each share of common stock.

Each Right will entitle holders of the Company’s common stock to buy one-one thousandth of a share of Grey Wolf’s Series B Junior Participating Preferred stock at an exercise price of $11. The Rights will be exercisable only if a person or group acquires beneficial ownership of 15% or more of Grey Wolf’s common stock or announces a tender or exchange offer upon consummation of which such person or group would beneficially own 15% or more of Grey Wolf’s common stock. Furthermore, if any person becomes the beneficial owner of 15% or more of Grey Wolf’s common stock, each Right not owned by such person or related parties will enable its holder to purchase, at the Right’s then-current exercise price, shares of common stock of the Company having a value of twice the Right’s exercise price. The Company will generally be entitled to redeem the Rights at $.001 per Right at any time until the 10th day following public announcement that a 15% position has been acquired.

The 2003 Incentive Plan (the “2003 Plan”) was approved by shareholders in May 2003. The 2003 Plan authorizes the grant of the following equity-based awards:

	•		incentive stock options;

	•		non-statutory stock options;

	•		restricted shares; and

	•		other stock-based and cash awards.

The 2003 Plan replaced the Company’s 1996 Employee Stock Option Plan (the “1996 Plan”); but all outstanding options previously granted will continue to be exercisable subject to the terms and conditions of such grants. The 1996 Plan allowed for grants of non-statutory options to purchase shares of the Company’s common stock, but no further grants of common stock will be made under the 1996 Plan. The 2003 Plan reserves a maximum of 17.0 million shares of the Company’s common stock underlying all equity-based awards, but is reduced by the number of shares subject to previous grants under the 1996 Plan. At December 31, 2005, there were 5.8 million shares of common stock available for grant under the 2003 Plan until March 2013. Prior to 2003, the Company also granted options under stock option agreements with its directors that are outside of the 1996 Plan and the 2003 Plan. At December 31, 2005, these individuals had options outstanding to purchase an aggregate of 851,000 shares of common stock.

The exercise price of stock options approximates the fair market value of the stock at the time the option is granted. A portion of the outstanding options became exercisable upon issuance and the remaining become exercisable in varying increments over three to five-year periods. The options expire on the tenth anniversary of the date of grant.

-51-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock option activity for all stock options issued as of December 31, 2005, 2004 and 2003 was as follows (number of shares in thousands):


	2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
	No. of			Exercise		No. of			Exercise		No. of			Exercise
	Shares			Price		Shares			Price		Shares			Price
Outstanding – beginning of the year		6,494		$	3.60		10,209		$	3.09		8,721		$	2.85
Granted		472			5.67		1,224			3.92		2,161			3.91
Exercised		(2,291	)		3.52		(4,243	)		2.39		(246	)		1.50
Cancelled		(422	)		4.08		(696	)		3.97		(427	)		3.43

Outstanding – end of year		4,253		$	3.83		6,494		$	3.60		10,209		$	3.09

At December 31, 2005 the Company had 1.7 million in stock options exercisable with a range of exercise prices from $0.94 to $6.37. At December 31, 2004 and 2003, there were 2.7 million stock options exercisable, with a range of exercise prices from $0.69 to $6.37, and 5.4 million stock options exercisable from $0.69 to $6.37, respectively.

The following table summarizes information about stock options outstanding at December 31, 2005:


			Weighted
			Average		Weighted
			Remaining		Average
	Number		Contractual		Exercise
Range of Exercise Prices	Outstanding		Life⁽¹⁾		Price
$0.94 to $1.63		271		1.78	$	1.47
$2.54 to $4.26		3,124		6.53		3.43
$4.50 to $7.57		858		7.14		6.00

		4,253		6.35	$	3.83


(1)		Represents weighted average remaining contractual life in years.

During 2005, 218,950 shares of restricted stock, with a weighted average grant-date fair value of $5.73 per share, were issued under the 2003 Plan, of which 197,750 of these shares were outstanding at December 31, 2005. These shares vest over a five year service period and are only restricted as to their vesting conditions. For the year ended December 31, 2005, $198,000 in compensation expense was recognized and $937,000 remains as unearned restricted stock awards within shareholders’ equity at December 31, 2005. The Company did not grant shares of restricted stock prior to 2005.

(6)

Segment Information

The Company manages its business as one reportable segment. Although the Company provides contract drilling services in several markets, these operations have been aggregated into one reportable segment based on the similarity of economic characteristics among all markets including the nature of the services provided and the type of customers of such services.

(7)

Related-Party Transactions

The Company performed contract drilling services for affiliates of one of the Company’s directors. Total revenues recognized from these affiliates during 2005, 2004 and 2003 were $18.2 million, $4.7 million and $4.1 million, respectively. These affiliates had accounts receivable balances with the Company of $6.3 million and $1.9 million at December 31, 2005 and 2004, respectively.

-52-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(8) Commitments and Contingencies

Operating Leases

The Company occupies various facilities and leases certain equipment under various lease agreements. The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2005 are as follows (in thousands).


Year	Amount
2006	$	757,000
2007		698,000
2008		556,000
2009		542,000
2010		566,000
Thereafter		47,000

	$	3,166,000

Lease expense under operating leases for 2005, 2004 and 2003 were approximately $930,904, $774,000, and $718,000, respectively.

Contingencies

The Company is involved in litigation incidental to the conduct of its business, none of which management believes is, individually or in the aggregate, material to the Company’s consolidated financial condition or results of operations.

(9)

Employee Benefit Plan

The Company has a defined contribution employee benefit plan covering substantially all of its employees. The Company matches 100% of the first 3% of individual employee contributions and 50% of the next 3% of individual employee contributions. Employer matching contributions under the plan totaled $1.4 million, $1.1 million and $873,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Upon reaching the service requirements to join the plan, participants immediately vest in employer matching contributions.

(10)

Concentrations

There were no customers representing greater than 10% of the Company’s revenue for the years ended December 31, 2005, 2004 and 2003, respectively.

(11)

Subsequent Event

On December 30, 2005, the Company entered into a purchase and sale agreement with a private company, whereby the Company agreed to sell five of its rigs available for refurbishment. The sale of the rigs was completed on January 3, 2006. The Company received $15.3 million in cash in exchange for the five rigs, which resulted in a pretax gain of $9.4 million to be recognized in the first quarter of 2006.

-53-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(12)

Quarterly Financial Data (unaudited)

Summarized quarterly financial data for years ended December 31, 2005, 2004 and 2003 are set forth below (amounts in thousands, except per share amounts).


	Quarter Ended
	March		June		September		December
	2005		2005		2005		2005
Contract drilling revenues	$	149,992	$	161,315	$	181,523	$	204,149
Operating income		38,851		46,150		52,541		63,381
Income before income taxes		36,684		44,053		50,661		61,734
Net income		23,044		27,633		31,779		38,181
Net income per common share
- basic	$	0.12	$	0.14	$	0.17	$	0.20
- diluted	$	0.10	$	0.12	$	0.14	$	0.17


	Quarter Ended
	March			June			September		December
	2004			2004			2004		2004
Contract drilling revenues	$	75,200		$	103,750		$	116,290	$	129,394
Operating income (loss)		(3,438	)		1,990			11,199		18,485
Income (loss) before income taxes		(9,438	)		(1,748	)		9,173		16,267
Net income (loss)		(6,431	)		(1,482	)		5,462		10,529
Net income (loss) per common share
- basic	$	(0.04	)	$	(0.01	)	$	0.03	$	0.06
- diluted	$	(0.04	)	$	(0.01	)	$	0.03	$	0.05


	Quarter Ended
	March			June			September			December
	2003			2003			2003			2003
Contract drilling revenues	$	62,387		$	66,949		$	72,383		$	84,255
Operating income (loss)		(8,414	)		(7,820	)		(7,681	)		3,196
Loss before income taxes		(14,148	)		(21,921	)		(11,183	)		(331	)
Net income (loss)		(9,621	)		(14,185	)		(6,950	)		556
Net income (loss) per common share
- basic	$	(0.05	)	$	(0.08	)	$	(0.04	)	$	0.00
- diluted	$	(0.05	)	$	(0.08	)	$	(0.04	)	$	0.00

-54-

Schedule II

GREY WOLF, INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

(In thousands)


			Additions		Deductions
	Balance at		Charged to		From			Balance at
	Beginning		Bad Debt		Bad Debt			End
	of Period		Allowance		Allowance			of Period
Year Ended December 31, 2003
Allowance for doubtful accounts receivable	$	2,500	$	—	$	(57	)	$	2,443


Year Ended December 31, 2004
Allowance for doubtful accounts receivable	$	2,443	$	—	$	(19	)	$	2,424


Year Ended December 31, 2005
Allowance for doubtful accounts receivable	$	2,424	$	250	$	—		$	2,674

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2005, under the supervision and with participation of management, including the Chief Executive Officer and Chief Financial Officer. Our disclosure controls and procedures are designed to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act is accumulated and communicates to the issuer’s management including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective.

Management’s Report on Internal Control Over Financial Reporting

This report is included in Item 8 on page 34 of this report and is incorporated herein by reference.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

-55-

Item 9B. Other Information

None.

PART III

Item 10. Directors and Executive Officers of the Registrant

The information required by this item as to our directors and executive officers is hereby incorporated by reference to such information appearing under the captions “Directors” and “Executive Officers” in our definitive proxy statement for our 2006 Annual Meeting of Shareholders and is to be filed with the Securities and Exchange Commission (the “Commission”) pursuant to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal year on December 31, 2005.

Item 11. Executive Compensation

The information required by this item as to the compensation of our management is hereby incorporated by reference to such information appearing under the caption “Executive Compensation” in our definitive proxy statement for our 2006 Annual Meeting of Shareholders and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal year on December 31, 2005.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholders’ Matters

The information required by this item as to the ownership by our management and others of our securities is hereby incorporated by reference to such information appearing under the caption “Nominees for Director”, “Ownership by Management and Certain Shareholders” and “Executive Compensation Plans” in our definitive proxy statement for our 2006 Annual Meeting of Shareholders and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal year on December 31, 2005.

Item 13. Certain Relationships and Related Transactions

The information required by this item as to certain business relationships and transactions with our management and other parties related to us is hereby incorporated by reference to such information appearing under the caption “Certain Transactions” in our definitive proxy statement for our 2006 Annual Meeting of Shareholders and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal year on December 31, 2005.

Item 14. Principal Accountant Fees and Services

The information required by this item as to accounting fees and services is hereby incorporated by reference to such information appearing under the caption “Registered Public Accountants” in our definitive proxy statement for our 2006 Annual Meeting of Shareholders and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal year on December 31, 2005.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)

The following documents are filed as part of this report:

1. and 2. Financial Statements and Schedule

The consolidated financial statements and supplemental schedule of Grey Wolf, Inc. and Subsidiaries are included in Part II, Item 8 and are listed in the Index to Consolidated Financial Statements and Financial Statement Schedule therein.

Exhibits


Exhibit
No.		Documents
2.1	—	Agreement and Plan of Merger between Grey Wolf, Inc. and New Patriot Drilling Corp. dated March 5, 2004 (incorporated by reference to Exhibit 99 to Grey Wolf’s Form 8-K dated March 8, 2004.

3.1	—	Articles of Incorporation of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 3.1 to Form 10-Q dated May 12, 1999).

3.2	—	By-Laws of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 99.1 to Form 8-K dated March 23, 1999).

4.1	—	Rights Agreement dated as of September 21, 1998 by and between the Company and American Stock Transfer and Trust Company as Rights Agent (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed September 22, 1998).

4.2	—	Indenture, dated as of May 7, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).

4.3	—	Supplemental Indenture, dated as of May 22, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).

4.4	—	Indenture, dated as of March 31, 2004, relating to the Floating Rate Contingent Convertible Senior Notes Due 2024 between the Company, the Guarantors, and J.P. Morgan Chase Bank, a New York banking corporation, as Trustee (incorporated by reference to Exhibit 4.1 to Form 10-Q dated May 5, 2004).

4.5	—	Registration Rights Agreement as of March 31, 2004 by and between Grey Wolf, Inc., the Guarantors, and the Initial Purchasers of the Floating Rate Contingent Convertible Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q filed May 5, 2004).

4.6	—	Second Supplemental Indenture, dated as of March 31, 2004, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JP Morgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q filed May 5, 2004).

+10.1	—	Form of Non-Qualified Stock Option Agreement dated September 3, 1996, by and between the Company and Thomas P. Richards (incorporated herein by reference to Exhibit 10.2 to Registration Statement on Form S-3 No. 333-14783 filed October 24, 1996).

-57-


Exhibit
No.		Documents
+10.2	—	DI Industries, Inc. 1996 Employee Stock Option Plan (incorporated herein by reference to Grey Wolf, Inc. 1996 Annual Meeting of Shareholders definitive proxy materials filed August 2, 1996).

+10.3	—	Grey Wolf Inc. Amendment to 1996 Employee Stock Option Plan (incorporated herein by reference to Exhibit 4.3 to Grey Wolf, Inc.’s Registration Statement on Form S-8 No. 333-41334 filed July 13, 2000).

+10.4	—	Grey Wolf, Inc. Second Amendment to 1996 Employee Stock Option Plan dated May 14, 2002 (incorporated herein by reference to Exhibit 4.6 to Grey Wolf, Inc. Registration Statement on Form S-8 No. 333-90888 filed June 21, 2002).

+10.5	—	Form of Non-Qualified Stock Option Agreement dated February 10, 1998, by and between the Company and David W. Wehlmann (incorporated herein by reference to Exhibit 10.35 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 1997, filed March 30, 1998).

+10.6	—	Non-Qualified Stock Option Agreement dated January 16, 1999, by and between the Company and Edward S. Jacob, III. (incorporated herein by reference to Exhibit 10.33 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 1999, filed March 7, 2000).

+10.7	—	Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the Company and Thomas P. Richards (incorporated herein by reference to Exhibit 10.13 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.8	—	Form of Amendment to Non-Qualified Stock Option Agreement dated November 13, 2001, by and among the Company (f.k.a. DI Industries, Inc.), Thomas P. Richards and Richards Brothers Interests, L.P (incorporated herein by reference to Exhibit 10.14 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.9	—	Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the Company and each of David W. Wehlmann, Edward S. Jacob III, Gary D. Lee, Ronnie E. McBride, Kent D. Cauley, and Donald J. Guedry, Jr. (incorporated herein by reference Exhibit 10.15 to the to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.10	—	Grey Wolf, Inc. Executive Severance Plan effective November 15, 2001 (incorporated herein by reference to Exhibit 10.16 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.11	—	Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Thomas P. Richards (incorporated herein by reference to Exhibit 10.17 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.12	—	Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and David W. Wehlmann (incorporated herein by reference to Exhibit 10.18 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.13	—	Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Edward S. Jacob III (incorporated herein by reference to Exhibit 10.19 of the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.14	—	Employment Agreement effective December 28, 2005 by and between Robert J. Proffit (incorporated by reference to Exhibit 10.1 of the Grey Wolf, Inc. Current Report on Form 8-K filed December 28, 2005).

-58-


Exhibit
No.		Documents
+10.15	—	Form of Non-Qualified Stock Option Agreement dated as of February 13, 2002, by and between the Company and each of Frank M. Brown, William T. Donovan, James K.B. Nelson, Robert E. Rose, Steven A. Webster, and William R. Ziegler (incorporated herein by reference to Exhibit 10.22 of the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.16	—	Grey Wolf, Inc. 2003 Incentive Plan (incorporated herein by reference to Appendix A to the Grey Wolf, Inc. 2003 Annual Meeting of Shareholders definitive proxy materials filed March 28, 2003).

+10.17	—	Anticipated compensation of officers and directors for 2005 (incorporated by reference to Grey Wolf, Inc. Current Report on Form 8-K filed February 22, 2005).

+10.18	—	Form of Non-Qualified Stock Option Agreement under the Grey Wolf, Inc. 2003 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Grey Wolf, Inc. Current Report on Form 8-K filed February 22, 2005).

+10.19	—	Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to the Grey Wolf, Inc. current Report on Form 8-K filed February 22, 2005).

+10.20	—	Anticipated compensation of officers and directors for 2006 (incorporated by reference to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.21	—	Form of Stock Option Agreement under the 2003 Incentive Plan for Thomas P. Richards (incorporated by reference to Exhibit 10.1 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006.)

+10.22	—	Form of Restricted Stock Agreement under the 2003 Incentive Plan for Thomas P. Richards (incorporated by reference to Exhibit 10.2 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006.)

+10.23	—	Form of Stock Option Agreement under the 2003 Incentive Plan for the other executive officers (incorporated by reference to Exhibit 10.3 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006.)

+10.24	—	Form of Restricted Stock Agreement under the 2003 Incentive Plan for other executive officers (incorporated by reference to Exhibit 10.4 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.25	—	Form of Restricted Stock Agreement for Thomas P. Richards under the Retention Plan (incorporated by reference to Exhibit 10.5 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.26	—	Form of Restricted Stock Agreement for other executive officers under the Retention Plan (incorporated by reference to Exhibit 10.6 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.27	—	Form of Restricted Stock Agreement for non-employee directors (incorporated by reference to Exhibit 10.7 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

10.28	—	Revolving Credit Agreement dated as of January 14, 1999 among Grey Wolf Drilling Company LP (as borrower), Grey Wolf, Inc. (as guarantor), The CIT Group/Business Credit, Inc. (as agent) and various financial institutions (as lenders) (incorporated herein by reference to Exhibit 10.1 to Grey Wolf, Inc. current report on Form 8-K dated January 26, 1999).

10.29	—	First Amendment to Loan Agreement dated as of December 20, 2001, by and among Grey Wolf Drilling Company, LP (as borrower) and Grey Wolf, Inc. (as guarantor) and the CIT Group/Business Credit, Inc. (as agent) and various financial institutions (as lenders) (incorporated herein by reference to Exhibit 10.11 to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 14, 2002).

-59-


Exhibit
No.		Documents
10.30	—	Second Amendment to Loan Agreement dated as of February 7, 2003 by and among Grey Wolf Drilling Company L.P. (as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit, Inc. and various financial institutions (as lenders) (incorporated herein by reference to Exhibit 10.24 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2002, filed March 16, 2003).

10.31	—	Third Amendment to Loan Agreement as of May 1, 2003, by and among Grey Wolf Drilling Company, L.P. (as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit, Inc. and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed May 5, 2004).

10.32	—	Fourth Amendment to Loan Agreement as of March 31, 2004, by and among Grey Wolf Drilling Company L.P. (as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit, Inc. and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed May 5, 2004).

10.33	—	Fifth Amendment to the Loan Agreement dated December 31, 2004 by and among Grey Wolf Drilling Company, L.P. (as borrower,) Grey Wolf, Inc and various subsidiaries (as guarantor) and the CIT Business Credit, Inc. (as agent) and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.6 of the Grey Wolf, Inc. Current Report on Form 8-K filed January 5, 2005).

10.34	—	Sixth Amendment to the Loan Agreement dated September 13, 2005 by and between Grey Wolf Drilling Company, L.P. (as borrower,) Grey Wolf Inc. and various subsidiaries (as guarantor) and the CIT Business Credit, inc. (as agent) and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.7 of the Grey Wolf, Inc. Current Report on Form 8-K filed September 14, 2005).

*21.1	—	List of Subsidiaries of Grey Wolf, Inc.

*23.1	—	Consent of Independent Registered Public Accounting Firm, KPMG LLP

*31.1	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a).

*31.2	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a).

**32.1	—	Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Thomas P. Richards, Chairman, President and Chief Executive Officer and David W. Wehlmann, Executive Vice President and Chief Financial Officer.


+		Management contract, compensation plan or arrangement

*		Filed herewith

**		Furnished, not filed, pursuant to Item 101(b) (32) of Regulation S-K.

-60-

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, this 1st day of March, 2006.


		Grey Wolf, Inc.

		By:		/s/ David W. Wehlmann

				David W. Wehlmann, Executive Vice President and
				Chief Financial Officer

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


Signatures and Capacities		Date

By:	/s/ Thomas P. Richards	March 1, 2006

	Thomas P. Richards, Chairman, President and Chief Executive Officer
	(Principal Executive Officer)

By:	/s/ David W. Wehlmann	March 1, 2006

	David W. Wehlmann, Executive Vice President and Chief Financial Officer

By:	/s/ Kent D. Cauley	March 1, 2006

	Kent D. Cauley, Vice President and Controller

By:	/s/ William R. Ziegler	March 1, 2006

	William R. Ziegler, Director

By:	/s/ Frank M. Brown	March 1, 2006

	Frank M. Brown, Director

By:	/s/ William T. Donovan	March 1, 2006

	William T. Donovan, Director

By:	/s/ Robert E. Rose	March 1, 2006

	Robert E. Rose, Director

By:	/s/ Trevor M. Turbidy	March 1, 2006

	Trevor M. Turbidy, Director

By:	/s/ Steven A. Webster	March 1, 2006

	Steven A. Webster, Director

-61-

Index to Exhibits


Exhibit
No.		Documents
2.1	—	Agreement and Plan of Merger between Grey Wolf, Inc. and New Patriot Drilling Corp. dated March 5, 2004 (incorporated by reference to Exhibit 99 to Grey Wolf’s Form 8-K dated March 8, 2004.

3.1	—	Articles of Incorporation of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 3.1 to Form 10-Q dated May 12, 1999).

3.2	—	By-Laws of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 99.1 to Form 8-K dated March 23, 1999).

4.1	—	Rights Agreement dated as of September 21, 1998 by and between the Company and American Stock Transfer and Trust Company as Rights Agent (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed September 22, 1998).

4.2	—	Indenture, dated as of May 7, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).

4.3	—	Supplemental Indenture, dated as of May 22, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).

4.4	—	Indenture, dated as of March 31, 2004, relating to the Floating Rate Contingent Convertible Senior Notes Due 2024 between the Company, the Guarantors, and J.P. Morgan Chase Bank, a New York banking corporation, as Trustee (incorporated by reference to Exhibit 4.1 to Form 10-Q dated May 5, 2004).

4.5	—	Registration Rights Agreement as of March 31, 2004 by and between Grey Wolf, Inc., the Guarantors, and the Initial Purchasers of the Floating Rate Contingent Convertible Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q filed May 5, 2004).

4.6	—	Second Supplemental Indenture, dated as of March 31, 2004, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JP Morgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q filed May 5, 2004).

+10.1	—	Form of Non-Qualified Stock Option Agreement dated September 3, 1996, by and between the Company and Thomas P. Richards (incorporated herein by reference to Exhibit 10.2 to Registration Statement on Form S-3 No. 333-14783 filed October 24, 1996).


Exhibit
No.		Documents
+10.2	—	DI Industries, Inc. 1996 Employee Stock Option Plan (incorporated herein by reference to Grey Wolf, Inc. 1996 Annual Meeting of Shareholders definitive proxy materials filed August 2, 1996).

+10.3	—	Grey Wolf Inc. Amendment to 1996 Employee Stock Option Plan (incorporated herein by reference to Exhibit 4.3 to Grey Wolf, Inc.’s Registration Statement on Form S-8 No. 333-41334 filed July 13, 2000).

+10.4	—	Grey Wolf, Inc. Second Amendment to 1996 Employee Stock Option Plan dated May 14, 2002 (incorporated herein by reference to Exhibit 4.6 to Grey Wolf, Inc. Registration Statement on Form S-8 No. 333-90888 filed June 21, 2002).

+10.5	—	Form of Non-Qualified Stock Option Agreement dated February 10, 1998, by and between the Company and David W. Wehlmann (incorporated herein by reference to Exhibit 10.35 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 1997, filed March 30, 1998).

+10.6	—	Non-Qualified Stock Option Agreement dated January 16, 1999, by and between the Company and Edward S. Jacob, III. (incorporated herein by reference to Exhibit 10.33 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 1999, filed March 7, 2000).

+10.7	—	Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the Company and Thomas P. Richards (incorporated herein by reference to Exhibit 10.13 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.8	—	Form of Amendment to Non-Qualified Stock Option Agreement dated November 13, 2001, by and among the Company (f.k.a. DI Industries, Inc.), Thomas P. Richards and Richards Brothers Interests, L.P (incorporated herein by reference to Exhibit 10.14 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.9	—	Form of Amendment to Non-Qualified Stock Option Agreements dated November 13, 2001, by and between the Company and each of David W. Wehlmann, Edward S. Jacob III, Gary D. Lee, Ronnie E. McBride, Kent D. Cauley, and Donald J. Guedry, Jr. (incorporated herein by reference Exhibit 10.15 to the to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.10	—	Grey Wolf, Inc. Executive Severance Plan effective November 15, 2001 (incorporated herein by reference to Exhibit 10.16 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.11	—	Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Thomas P. Richards (incorporated herein by reference to Exhibit 10.17 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.12	—	Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and David W. Wehlmann (incorporated herein by reference to Exhibit 10.18 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.13	—	Amended and Restated Employment Agreement dated November 13, 2001, by and between the Company and Edward S. Jacob III (incorporated herein by reference to Exhibit 10.19 of the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.14	—	Employment Agreement effective December 28, 2005 by and between Robert J. Proffit (incorporated by reference to Exhibit 10.1 of the Grey Wolf, Inc. Current Report on Form 8-K filed December 28, 2005).


Exhibit
No.		Documents
+10.15	—	Form of Non-Qualified Stock Option Agreement dated as of February 13, 2002, by and between the Company and each of Frank M. Brown, William T. Donovan, James K.B. Nelson, Robert E. Rose, Steven A. Webster, and William R. Ziegler (incorporated herein by reference to Exhibit 10.22 of the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 15, 2002).

+10.16	—	Grey Wolf, Inc. 2003 Incentive Plan (incorporated herein by reference to Appendix A to the Grey Wolf, Inc. 2003 Annual Meeting of Shareholders definitive proxy materials filed March 28, 2003).

+10.17	—	Anticipated compensation of officers and directors for 2005 (incorporated by reference to Grey Wolf, Inc. Current Report on Form 8-K filed February 22, 2005).

+10.18	—	Form of Non-Qualified Stock Option Agreement under the Grey Wolf, Inc. 2003 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Grey Wolf, Inc. Current Report on Form 8-K filed February 22, 2005).

+10.19	—	Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to the Grey Wolf, Inc. current Report on Form 8-K filed February 22, 2005).

+10.20	—	Anticipated compensation of officers and directors for 2006 (incorporated by reference to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.21	—	Form of Stock Option Agreement under the 2003 Incentive Plan for Thomas P. Richards (incorporated by reference to Exhibit 10.1 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006.)

+10.22	—	Form of Restricted Stock Agreement under the 2003 Incentive Plan for Thomas P. Richards (incorporated by reference to Exhibit 10.2 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006.)

+10.23	—	Form of Stock Option Agreement under the 2003 Incentive Plan for the other executive officers (incorporated by reference to Exhibit 10.3 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006.)

+10.24	—	Form of Restricted Stock Agreement under the 2003 Incentive Plan for other executive officers (incorporated by reference to Exhibit 10.4 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.25	—	Form of Restricted Stock Agreement for Thomas P. Richards under the Retention Plan (incorporated by reference to Exhibit 10.5 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.26	—	Form of Restricted Stock Agreement for other executive officers under the Retention Plan (incorporated by reference to Exhibit 10.6 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

+10.27	—	Form of Restricted Stock Agreement for non-employee directors (incorporated by reference to Exhibit 10.7 to Grey Wolf, Inc. Current Report on Form 8-K filed February 21, 2006).

10.28	—	Revolving Credit Agreement dated as of January 14, 1999 among Grey Wolf Drilling Company LP (as borrower), Grey Wolf, Inc. (as guarantor), The CIT Group/Business Credit, Inc. (as agent) and various financial institutions (as lenders) (incorporated herein by reference to Exhibit 10.1 to Grey Wolf, Inc. current report on Form 8-K dated January 26, 1999).

10.29	—	First Amendment to Loan Agreement dated as of December 20, 2001, by and among Grey Wolf Drilling Company, LP (as borrower) and Grey Wolf, Inc. (as guarantor) and the CIT Group/Business Credit, Inc. (as agent) and various financial institutions (as lenders) (incorporated herein by reference to Exhibit 10.11 to Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2001, filed March 14, 2002).


Exhibit
No.		Documents
10.30	—	Second Amendment to Loan Agreement dated as of February 7, 2003 by and among Grey Wolf Drilling Company L.P. (as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit, Inc. and various financial institutions (as lenders) (incorporated herein by reference to Exhibit 10.24 to the Grey Wolf, Inc. Annual Report on Form 10-K for the year ended December 31, 2002, filed March 16, 2003).

10.31	—	Third Amendment to Loan Agreement as of May 1, 2003, by and among Grey Wolf Drilling Company, L.P. (as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit, Inc. and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed May 5, 2004).

10.32	—	Fourth Amendment to Loan Agreement as of March 31, 2004, by and among Grey Wolf Drilling Company L.P. (as borrower), Grey Wolf, Inc. and various subsidiaries (as guarantors) and the CIT Group/Business Credit, Inc. and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed May 5, 2004).

10.33	—	Fifth Amendment to the Loan Agreement dated December 31, 2004 by and among Grey Wolf Drilling Company, L.P. (as borrower,) Grey Wolf, Inc and various subsidiaries (as guarantor) and the CIT Business Credit, Inc. (as agent) and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.6 of the Grey Wolf, Inc. Current Report on Form 8-K filed January 5, 2005).

10.34	—	Sixth Amendment to the Loan Agreement dated September 13, 2005 by and between Grey Wolf Drilling Company, L.P. (as borrower,) Grey Wolf Inc. and various subsidiaries (as guarantor) and the CIT Business Credit, inc. (as agent) and various financial institutions (as lenders) (incorporated by reference to Exhibit 10.7 of the Grey Wolf, Inc. Current Report on Form 8-K filed September 14, 2005).

*21.1	—	List of Subsidiaries of Grey Wolf, Inc.

*23.1	—	Consent of Independent Registered Public Accounting Firm, KPMG LLP

*31.1	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a).

*31.2	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a).

**32.1	—	Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Thomas P. Richards, Chairman, President and Chief Executive Officer and David W. Wehlmann, Executive Vice President and Chief Financial Officer.


+		Management contract, compensation plan or arrangement

*		Filed herewith

**		Furnished, not filed, pursuant to Item 101(b) (32) of Regulation S-K.


		Page
Part I

Item 1.	Business	3

Item 1A.	Risk Factors	8

Item 1B.	Unresolved Staff Comments	15

Item 2.	Properties	15

Item 3.	Legal Proceedings	17

Item 4.	Submission of Matters to a Vote of Security Holders	17

Part II

Item 5.	Market for Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities	18

Item 6.	Selected Financial Data	18

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	32

Item 8.	Financial Statements and Supplementary Data	33

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55

Item 9A.	Controls and Procedures	55

Item 9B.	Other Information	56

Part III

Item 10.	Directors and Executive Officers of the Registrant	56

Item 11.	Executive Compensation	56

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholders’ Matters	56

Item 13.	Certain Relationships and Related Transactions	56

Item 14.	Principal Accountant Fees and Services	56

Part IV

Item 15.	Exhibits and Financial Statement Schedules	57

	Signatures	61
List of Subsidiaries
Consent of Independent Registered Public Accounting Firm, KPMG LLP
Certification of CEO pursuant to Rule 13a-14a
Certification of CFO pursuant to Rule 13a-14a
Certification pursuant to Section 1350


Management’s Report on Internal Control over Financial Reporting			34

Reports of Independent Registered Public Accounting Firm			35

Consolidated Balance Sheets as of December 31, 2005 and 2004			37

Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004, and 2003			38

Consolidated Statements of Shareholders’ Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004, and 2003			39

Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003			40

Notes to Consolidated Financial Statements			41

Financial Statement Schedule:
Schedule II — Valuation and Qualifying Accounts			55


		State or Jurisdiction of Formation
Grey Wolf Drilling Company L.P.		Texas
Grey Wolf LLC		Louisiana
Grey Wolf Holdings Company		Nevada
Murco Drilling Corp.		Delaware
Grey Wolf International, Inc.		Texas
Grey Wolf Drilling International, Ltd.		Cayman Islands
Grey Wolf Drilling de Venezuela		Venezuela
Drillers Inc., DI de Venezuela		Venezuela
Grey Wolf Drilling de Mexico, S. de R.L. de C.V.		Mexico
Grey Wolf Mexico Holdings LLC		Nevada
Grey Wolf International de Mexico, S. de R.L. de C.V.		Mexico
Servicios Grey Wolf, S. de R.L. de C.V.		Mexico
DI/Perfensa, Inc.		Texas
Perforaciones Andinas, S.A.		Panama
DI Energy, Inc.		Texas

1.		I have reviewed this annual report on Form 10-K of Grey Wolf, Inc;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	(a)		designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

	(c)		evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	(a)		all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: March 1, 2006	By:	/s/ Thomas P. Richards
		Thomas P. Richards
		Chairman, President and Chief Executive Officer

	1.		The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

	2.		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.