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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, 2007

Commission file number 1-8226

GREY WOLF, INC.

(Exact name of registrant as specified in its charter)


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


10370 Richmond Avenue, Suite 600, Houston, Texas		77042
(Address of principal executive offices)		(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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether 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, 2007 based upon the closing price on the American Stock Exchange on that date was approximately $1.5 billion.

At February 18, 2008, 177,747,576 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 2008 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, 2007, 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. We seek to enter each phase of our industry’s cycles in a stronger position through 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;

Equipment and Operations

	•		using term contracts to provide sufficient cash flow to recover, after operating expenses, a majority of the initial capital expended for the purchase of new rigs;

	•		maintaining a premium fleet of equipment with a bias toward deep and horizontal/directional drilling;

	•		enhancing cash flow through our turnkey and trucking operations and use of our top drives;

	•		controlling costs and exercising capital spending discipline;

Growth and Return 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 strategic acquisition candidates.

We also seek to maintain a strong balance sheet, whereby we balance our investments with our previously announced stock repurchase program. We believe this will provide the most in long-term shareholder value. In September 2007, our board of directors authorized a $50.0 million increase in our previously announced common stock repurchase program, which we believe, improves shareholder’s return on their investment. As of February 18, 2008, we have repurchased 19.0 million shares at a total cost of $121.9 million, exclusive of commissions, under the program. We will continue, from time to time, to make purchases of common stock, up to $150.0 million, in open market or in privately negotiated block-trade transactions. The number of shares to be purchased and the timing of purchases will be based on a number of factors: the price of the common stock, general market conditions, available cash and alternate investment opportunities. We may terminate the stock repurchase program prior to completion.

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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 through 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 1,609 rigs working during the fourth quarter of 2006. As of February 22, 2008, there were 1,694 land rigs working. We believe this increase is due to the continued strong commodity prices which our customers are receiving for their production. As of February 18, 2008, the NYMEX 12-month strip price of natural gas was $9.057 per Mmbtu, while the NYMEX 12-month strip price of oil was $94.31 per barrel.

Current Conditions and Outlook

We, and some of our competitors, have purchased newly-built rigs during 2006 and 2007 and will continue taking delivery of additional rigs during 2008. However, we believe the majority of new-build rigs have now been delivered. We believe that most announcements of new rig orders in the U.S. market over the past several months have primarily been for “built-for-purpose rigs”. See “Item 2 — Properties” for a description of these types of rigs. We also believe that the new rigs that have come into the market have generally displaced lower-end equipment as better quality rigs have become more economical for customers to use. With approximately 300 non-working rigs currently available in the market there continues to be pressure on daywork dayrates as well as the amount we are able to charge our customers for moving our rigs. As of February 18, 2008, our leading edge rates range from $14,000 to $20,000 per rig day, without fuel or top drives, compared to a range of $15,000 to $22,000 for the same time a year ago. Leading edge dayrates, although down from a year ago, have been relatively stable over the past several months. We believe the ability to provide equipment that addresses the challenges of deep, directional or multi-well site drilling is critical to meeting our customers’ needs in the most active domestic land drilling markets. Our fleet is well suited to pursue these drilling opportunities given the recent acquisition of new rigs and substantial rig upgrades we have completed over the past three years.

As of December 31, 2007, we had 22,300 rig days contracted under term contracts, as compared with 25,000 rig days under term contract at September 30, 2007, and 31,500 rig days under term contract at December 31, 2006. Our rig days under contract at February 18, 2008 are approximately equivalent to an average of 37 rigs working under term contracts for 2008 and an average of 18 rigs working for 2009. At February 18, 2008 we had 53 rigs working under term contracts, representing 44% of our total rig fleet. These term contracts are expected to provide revenue of approximately $289.7 million in 2008 and $150.9 million in 2009. Since the beginning of 2007, the rate at which we have been able to sign new term contracts has decreased significantly.

We believe the outlook for oil and natural gas prices, as well as the outlook for land drilling contractors, remains positive. The land rig count is still at historically high levels owing to robust oil and natural gas commodity prices. We believe these prices provide our customers with capital resources to pursue oil and natural gas prospects in the areas where we drill. Natural gas production decline rates also provide a strong outlook for the land drilling industry. Decline rates are steeper than ever, and despite record drilling levels during the past several years there has been no meaningful increase in domestic natural gas production. In addition, we believe our premium fleet of rigs is well suited for the increasingly deeper and more complex wells being drilled by our customers and will continue to enable us to adapt to their evolving needs.

Operations

At February 18, 2008 we had a rig fleet of 121 rigs, all of which were marketed.

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

We continually evaluate opportunities to enter foreign markets in which we can enter into term contracts to support such a commitment. Consistent with that strategy, in 2007 we signed three-year term contracts with a major

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oilfield services company for two of our rigs to go to work in Mexico. This decision was made because it enabled us to enter into additional term contracts that provided us better returns than were otherwise available in our domestic markets at the time. These two rigs began operations in Mexico in the third quarter of 2007. See footnote 8 in the Notes to Consolidated Financial Statements for information regarding domestic and foreign segment reporting.

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. In addition, 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 90 rigs, or 74% of the total fleet, capable of drilling to 15,000 feet or deeper and fit well with the trend in the industry.

Below is a summary of the deployment of our rig fleet throughout the geographic market areas in which we operate, the relative amount of daywork versus turnkey work done in these areas in 2007 and the average revenue per rig day we produced in each market area. All rig deployment counts are as of February 18, 2008:

Ark-La-Tex Division. Our Ark-La-Tex division provides drilling services primarily in Northeast Texas, Northern Louisiana, Southern Arkansas, and the Mississippi/Alabama market. We have 29 marketed rigs in this division consisting of 19 diesel electric rigs and 10 mechanical rigs. One of the diesel electric rigs and two of the mechanical rigs are trailer-mounted rigs. We also operate a fleet of 27 trucks in this division which is used to exclusively move our rigs.

We had an average of 25 rigs working in our Ark-La-Tex division during 2007. Daywork contracts generated approximately 96% of the division’s revenues, while turnkey contracts generated the remaining 4%. The average revenue per rig day worked by the division during 2007 was $20,164. Turnkey usually provides a higher revenue per rig day than daywork. See contracts section below.

Gulf Coast Division. Our Gulf Coast division provides drilling services in Southern Louisiana and along the upper Texas Gulf Coast. We have 25 marketed rigs in this division consisting of 20 diesel electric rigs and five mechanical rigs.

We had an average of 23 rigs working in our Gulf Coast division during 2007. Daywork contracts generated approximately 67% of the division’s revenues, while turnkey contracts generated the remaining 33%. The average revenue per rig day worked by the division during 2007 was $27,073.

South Texas Division. We have 31 marketed rigs in this division. These marketed rigs consist of 16 diesel electric rigs and 15 mechanical rigs. Of the mechanical rigs, 10 are trailer-mounted. We also operate a fleet of 34 trucks in this division which is used to exclusively move our rigs.

We had an average of 28 rigs working in our South Texas division during 2007. Daywork contracts generated approximately 71% of the division’s revenues, while turnkey contracts generated the remaining 29%. The average revenue per rig day worked by the division during 2007 was $24,647.

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 have 16 marketed rigs in this division consisting of nine diesel electric rigs and seven mechanical rigs. During 2007, we had an average of 13 rigs working and the average revenue per rig day worked was $17,907, all of which was under daywork contracts.

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 have 18 marketed rigs in this district, including 11 diesel electric rigs and seven mechanical rigs. One of the mechanical rigs is trailer-mounted. During 2007, we had an average of 15 rigs working and the average revenue per rig day worked was $20,708, all of which was under daywork contracts.

Mexico. We began operations of two of our diesel electric rigs in Mexico during the third quarter of 2007. Average revenue per rig day worked was $26,581 during 2007.

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Contracts

Our contracts for drilling oil and natural gas wells are obtained either through competitive bidding or as a result of relationships and 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 or turnkey basis.

Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, and this customer 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 on 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 six months to three years. Most of our term contracts have historically 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. We also have used term contracts to contractually assure that we receive sufficient cash flow to recover a majority of 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 return than would normally be available on daywork 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.

Customers and Marketing

Our customers include independent producers and major oil and natural gas companies. In 2007, 33% of our revenue came from major oil and natural gas companies and large independent producers, while the remaining 67% came from smaller independents. For the year ended December 31, 2007, 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

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neither we, nor the customer, are legally required to honor these commitments, we satisfy such commitments in order to maintain good long-term customer relations.

Competitors

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 drilling capabilities 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;

	•		mobility and efficiency of rigs.

While we must generally be competitive in our pricing, our competitive strategy emphasizes the capabilities and quality of our equipment, the safety record of our rigs and the experience of our rig crews to differentiate us from our competitors. This strategy is less effective during an industry downturn as lower demand for drilling services intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price.

The contract drilling industry historically has been cyclical and has experienced periods of low demand, excess rig supply, and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. Periods of excess rig supply intensify the competition in our industry and often result in rigs being idle. There are numerous competitors in each of the markets in which we compete. In all of those markets, an oversupply of rigs can cause greater price competition. Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services is better 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.

The number of rigs competing for work in the market areas we serve has increased due to the entry into those markets of newly-built or newly-refurbished rigs. We expect that more of these newer rigs will enter our market areas over the next year, although at a slower pace than in previous years. The addition of these rigs in 2008 could intensify price competition, and possibly reduce customer demand for term contracts.

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 18, 2008.

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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

Underlying insurance

Commercial excess liability

$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 for values of less than $5,000,000 and a $250,000 maintenance deductible for values in excess of $5,000,000. In addition, there is a deductible of $1,500,000 in the aggregate over the policy period, exclusive of the maintenance deductible. There is a $75,000 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 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 $3.5 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 $250,000 deductible or $40.0 million, with a $500,000 deductible, depending upon the area in which the well is drilled and its target depth. Each form of coverage provides for a deductible that we must meet, as well as a maximum limit of liability. Each casualty is an occurrence, and there may be more than one such occurrence on a well, each of which would be subject to a separate deductible. In addition, there is a deductible of $1,500,000 in the aggregate over the policy period, exclusive of the maintenance deductible. Except for care, custody and control and total loss, an aggregate deductible of $1,500,000 per annum is to apply to our property and casualty and “control of well” insurance combined, exclusive of maintenance deductibles. There is a combined single limit of $45.0 million on any one occurrence and in the annual aggregate in respect of a named windstorm.

No assurances can be given that we will be able to maintain the above-mentioned insurance types and/or the amounts of coverage that we believe to be adequate. Also, there are no assurances that these types of coverages will be available in the future. Our insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage, damage to the environment, damage to producing formations or other hazards. Any rising cost, changing deductibles, and/or availability of certain types of insurance could have an adverse effect on our financial condition and results of operations. Increases in deductibles could be caused by changes in our claims experience.

Environmental Regulations

Our operations are subject to stringent federal, state and local laws and regulations governing protection of the environment. These laws and regulations may require acquisition of permits before drilling commences and may restrict the types, quantities and concentrations of various substances that can be released into the environment. Planning and implementation of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids, and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are subject to regulatory requirements.

The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, and their state counterparts, are the primary vehicles for imposition of such requirements and for civil, criminal and administrative penalties and other sanctions for violation of their

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requirements. In addition, the federal Comprehensive Environmental Response Compensation and Liability Act and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release of hazardous substances into the environment. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of remedial action as well as damages to natural resources.

Environmental laws and regulations are complex and subject to frequent change that may result in more stringent and costly requirements. Compliance with applicable requirements has not, to date, had a material effect on the cost of our operations, earnings or competitive position. However, compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements, or the discovery of contamination may cause us to incur additional costs or subject us to liabilities that may have a material adverse effect on our results of operations and financial condition.

Our business depends on the demand for services from the oil and natural gas exploration and development industry, and therefore our business can be affected by political developments and changes in laws and regulations that control or curtail drilling for oil and natural gas for economic, environmental or other policy reasons.

Employees

At February 18, 2008, we had approximately 2,800 employees. None of our employees are subject to collective bargaining agreements, and we believe our employee relations are satisfactory.

Item 1A. Risk Factors

Below we describe the risks and uncertainties that we believe were material to our business as of February 18, 2008.

A material or extended decline in expenditures by oil and natural gas exploration and production companies, due to a decline or volatility in oil and natural gas prices, a decrease in demand for oil and natural gas, an increase in rig supply or other factors, would reduce our revenue and income.

As a supplier of land drilling services, our business depends on the level of drilling activity by oil and natural gas exploration and production companies operating in the geographic markets where we operate. The number of wells they choose to drill is strongly influenced by past trends in oil and natural gas prices, current prices and their outlook for future prices. Mild weather conditions and increased supplies of oil and natural gas from other sources could 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. An increase in the supply of land drilling rigs in the U.S. can materially affect us as well, 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 operations 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, our customers 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 impair our ability to enter into term contracts, 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;

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	•		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 drilling capabilities 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;

	•		the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques; and

	•		mobility and efficiency of rigs.

The number of rigs competing for work in the market areas we serve has increased due to the entry into those markets of newly-built or newly-refurbished rigs. We expect that more of these newer rigs will enter our market areas over the next year. The addition of these rigs in 2008 could intensify price competition, and possibly reduce customer demand for term contracts.

We face competition from competitors with greater resources.

Some of our competitors have greater financial and organizational resources than we do. Their greater capabilities in these areas may enable them to:

	•		build new rigs or acquire 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.

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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 also 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 will consider and evaluate acquisitions of, or significant investments in, businesses and assets that are complementary to ours. Any acquisition that we complete could have a material adverse effect 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;

	•		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;

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	•		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 may incur losses in future years resulting from downturns in the land drilling industry

While we have been profitable in our last four fiscal years, the land drilling industry is highly cyclical and we could incur losses in future years. In 2003 and 2002, we incurred a net loss of $30.2 million and $21.5 million, respectively, as a result of the most recent downturn in the industry. 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 years in which we have 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 drilling jobs could adversely affect us.

We have historically derived a significant portion of our revenues from turnkey drilling contracts and we expect that turnkey drilling will continue to represent a significant component of our revenues. The occurrence of operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey 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 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 drilling contracts is substantially greater than for wells drilled on a daywork basis because we must assume most of the risks associated with drilling operations that are generally assumed by our customer under a daywork contract.

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

During times of high demand for land drilling services, the land drilling industry may experience price increases and extended delivery times for newly-built rigs and for important rig components, including engines, mud pumps, top drives and drill pipe that may be needed to refurbish or repair rigs. These price increases and extended delivery times could adversely affect our business and results of operations by increasing our costs for, and delaying:

	•		deployment of newly-built rigs;

	•		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 over the last few years. We believe the demand for qualified rig personnel could 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

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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 3 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”). Accordingly, 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 expect to continue to have a significant amount of indebtedness. On December 31, 2007, our total long-term indebtedness was $275.0 million in principal amount, consisting of $150.0 million in principal amount of our 3.75% Notes and $125.0 million in principal amount of our Floating Rate Notes.

Our 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 which will limit the amount of cash flow we can use 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 than 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 effect on our financial condition and liquidity.

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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 18, 2008, we had the ability to borrow approximately $69.1 million under our credit facility (after reductions for undrawn outstanding standby letters of credit of $30.9 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, 2007 and 2006, 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, 2007, our corporate and unsecured debt ratings were rated Ba3 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, and other commitments, total capitalization and various ratios calculated from these factors. The rating agencies also consider predictability of cash flows, business strategy, industry conditions and contingencies. Lower ratings on our senior unsecured debt could impair our ability to obtain additional financing and will increase the cost of the financing that we do obtain.

Investors in our common stock should not expect to receive dividend income, and will be dependent on the appreciation of our common stock to earn a return on their investment.

The decision to pay a dividend on our common stock rests with our board of directors and will depend on our earnings, available cash, capital requirements and financial condition. We have never declared a cash dividend on our common stock and do not expect to pay cash dividends on our common stock for the foreseeable future. We expect that substantially 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, reduce outstanding indebtedness, and repurchase our common stock. Although our board of directors approved the repurchase of up to $150.0 million of our common stock (and we have repurchased $121.9 million of common stock, exclusive of commissions, through February 18, 2008), no additional repurchases have been authorized. Accordingly, 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

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•

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% of the principal amounts 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 18, 2008, our common stock issued and outstanding was 197.0 million shares and 177.7 million shares, respectively. An additional 3.4 million shares of our common stock were issuable upon exercise of outstanding stock options (of which 2.4 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. See Note 3 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;

	•		projected rig activity;

	•		increases in rig supply and its effects on us;

	•		projected interest expense;

	•		cost of building new rigs, delivery times and deployment destinations of these rigs;

	•		projected dayrates;

	•		the ability to recover the purchase price of rigs from term contracts;

	•		the availability and financial terms of term contracts;

	•		rigs expected to be engaged in turnkey operations;

	•		projected tax rate;

	•		wage rates and retention of employees;

	•		sufficiency of our capital resources and liquidity;

	•		projected depreciation and capital expenditures;

	•		future common stock repurchases by us and our expected dividend policy; and

	•		projected sources and uses of cash.

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

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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.

None.

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 18, 2008, we owned nine direct current diesel electric rigs and 68 SCR diesel electric rigs.

We also owned at February 18, 2008, 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.

In the second and third quarter of 2008, we will take delivery of two built-for-purpose rigs called PaDSRigs. These rigs, which are designed to operate in harsh environments, deliver value to our customers through the implementation of the latest industry technology. They will allow our customers that have multiple well locations to reduce the cycle time on wells and between wells, and provide them with the ability, if they choose, to simultaneously drill and produce their wells.

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 18, 2008, we owned 29 top drives.

We generally deploy our rig fleet among our divisions and district based on the types of rigs preferred by our customers for drilling in the geographic markets served by our divisions and district. The following table summarizes the rigs we own as of February 18, 2008, all of which are currently marketed:

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	Maximum Rated Depth Capacity ⁽¹⁾
	10,000’		15,000’		20,000’
	to 14,999’		to 19,999’		and Deeper		Total
Ark-La-Tex
Diesel Electric		1		12		5		18
Trailer-Mounted		2		1		—		3	⁽²⁾
Mechanical		1		4		3		8
Gulf Coast								—
Diesel Electric		—		4		16		20
Mechanical		1		2		2		5
South Texas								—
Diesel Electric		—		5		11		16
Trailer-Mounted		10		—		—		10
Mechanical		4		—		1		5
Rocky Mountain								—
Diesel Electric		—		6		3		9
Mechanical		7		—		—		7
Mid-Continent								—
Diesel Electric		1		4		6		11
Trailer-Mounted		1		—		—		1
Mechanical		3		3		—		6
Mexico
Diesel Electric		—		—		2		2

Total Rig Fleet ⁽³⁾		31		41		49		121


(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)		We have two new 1,500 hp built-for-purpose rigs on order, expected to be delivered in the second and third quarters of 2008, that will bring the total rig fleet to 123. The maximum depth capacity of each of these rigs is 18,000 feet.

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	Truck Yard
Casper, Wyoming	Owned	Division Office, Rig Yard
Grand Junction, Colorado	Leased	Division Satellite Office
Midland, Texas	Leased	District Office
Villahermosa, Mexico	Leased	Division Office, Rig Yard, Employee Housing

We lease approximately 28,617 square feet of office space in Houston, Texas for our principal corporate offices at a cost of approximately $49,560 per month. We believe all of our facilities are in good operating condition and are adequate for their present uses.

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Item 3. Legal Proceedings

We are involved in litigation incidental to the conduct of our business, none of which we believe is, individually or in the aggregate, material to our consolidated financial condition or results of operations. See Note 6 – Commitments and Contingencies in the Notes to Consolidated Financial Statements.

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

None.

PART II


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

Market Data

Our common stock is listed and traded on the American Stock Exchange (“AMEX”) under the symbol “GW.” As of February 18, 2008, we had 850 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, 2008 to February 18, 2008	$	6.55	$	5.00

Year Ended December 31, 2007
Quarter ended March 31, 2007		7.08		6.38
Quarter ended June 30, 2007		8.60		6.65
Quarter ended September 30, 2007		8.33		6.18
Quarter Ended December 31, 2007		6.63		4.85

Year Ended December 31, 2006
Quarter ended March 31, 2006		8.93		6.50
Quarter ended June 30, 2006		8.85		6.61
Quarter ended September 30, 2006		7.79		6.35
Quarter ended December 31, 2006		7.43		6.10

On February 18, 2008, the last reported sales price of our common stock on the AMEX was $6.09 per share.

We have never declared or paid cash dividends on our common stock and do not expect to pay cash dividends in 2008 or for the foreseeable future. We anticipate substantially all cash flow generated from operations in the foreseeable future will be retained and used to develop or expand our business, pay debt service, reduce outstanding indebtedness, and repurchase our common stock. 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.

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Issuer Purchases of Equity Securities

The following table provides information relating to our repurchase of common shares during the three months ended December 31, 2007 (in thousands, except average price paid per share):


							Approximate
					Total Number		Dollar Value of
					of Shares		Shares that May
					Purchased as		Yet be
	Total Number		Average		Part of Publicly		Purchased
	of Shares		Price Paid		Announced		Under the
Period	Purchased ⁽³⁾		per Share		Program		Program⁽¹⁾⁽²⁾
October 1, 2007 to October 31, 2007		1,137	$	6.16		1,137	$	56,936
November 1, 2007 to November 30, 2007		991	$	5.71		990	$	51,290
December 1, 2007 to December 31, 2007		3,960	$	5.33		3,960	$	30,200


(1)		On May 25, 2006, we announced that our board of directors approved a plan authorizing the repurchase of up to $100.0 million of Grey Wolf common stock in open market or in privately negotiated block-trade transactions. On September 25, 2007, we announced that our board of directors authorized a $50.0 million increase in our common stock repurchase program for a total of $150.0 million. The number of shares to be purchased and the timing of purchases will be based on several factors, including the price of the common stock, general market conditions, available cash and alternate investment opportunities. Our stock repurchase program is subject to termination prior to completion.

(2)		Through February 18, 2008, we repurchased an additional 399,000 shares at an average price of $5.34, exclusive of commissions. Accordingly, at February 18, 2008 the approximate dollar value of shares that may yet be repurchased under our plan was $28.1 million.

(3)		Our employees elected to have shares of stock withheld to cover payroll taxes when shares of restricted stock vest. We then pay the taxes on their behalf and hold the shares withheld as treasury stock. We had approximately 1,000 of such treasury share purchases during the three months ended December 31, 2007. These share repurchases are not covered under a publicly announced program.

Stock Performance Graph

The following graph compares the cumulative total return to shareholders on our common stock, the AMEX Composite and a Peer Group Index. The graph assumes that $100 was invested on December 31, 2002, in our common stock and in each index and that any cash dividends are reinvested. We have not declared any dividends during the periods covered by this graph.

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Comparison of Six Year Cumulative Total Return Among Grey Wolf, Inc., The Amex Composite and a Peer Group



	Years Ended December 31,
	2002		2003		2004		2005		2006		2007
Grey Wolf, Inc.	$	100.00	$	93.73	$	132.08	$	193.73	$	171.93	$	133.58

Amex Composite		100.00		143.18		175.20		215.26		257.04		299.37

Peer Group ⁽¹⁾		100.00		112.50		140.96		234.34		180.07		170.91


(1)		Consists of Nabors Industries, Inc., Parker Drilling Company, Helmerich & Payne, Precision Drilling and Patterson UTI Energy, Inc. All of the members of the Peer Group are providers of contract oil and gas land drilling services.

This graph depicts the past performance of our common stock and in no way should be used to predict future performance. We do not make or endorse any predictions as to future share performance.

Item 6. Selected Financial Data


	Years Ended December 31,
	2007		2006		2005		2004		2003
	(In thousands, except per share amounts)
Revenues	$	906,577	$	945,527	$	696,979	$	424,634	$	285,974
Net income (loss)		169,892		219,951		120,637		8,078		(30,200	)
Net income (loss) per common share
Basic		0.93		1.16		0.63		0.04		(0.17	)
Diluted		0.79		0.98		0.54		0.04		(0.17	)
Total assets		1,207,970		1,086,984		869,035		635,876		532,184
Senior and contingent convertible notes & other long-term debt		275,000		275,000		275,000		275,000		234,898

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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 18, 2008, of 121 rigs, all of which 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 or turnkey 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 services, our success drilling turnkey wells.

New Rig Purchases

In September 2007, we entered into three-year term contracts with two exploration and production companies to deploy two new 1,500 horsepower built-for-purpose rigs. With deliveries expected in the second and third quarters of 2008, these rigs are designed to drill multiple wells from the same location. The expected purchase price per rig is approximately $22.2 million, and these rigs are expected to be deployed in the Rocky Mountain market.

In July 2007, we purchased two 1,500 horsepower rigs from a privately-owned exploration and production company. The purchase price for the two rigs, which were manufactured in 2006, was $28.0 million, or approximately 80% of the current cost to build comparable rigs. Concurrent with the purchase, we signed a term contract totaling 1,095 rig days for each of the rigs purchased to provide drilling services to the seller. We assumed operation of the rigs July 1, 2007 and they are operating in East Texas. Both of the rigs are diesel electric SCR rigs capable of drilling up to 18,000 feet.

We recently constructed a 1,000 horsepower diesel electric SCR rig capable of drilling to 15,000 feet. The rig has been deployed under a two-year term contract and is currently working in the Rocky Mountain market.

During 2006, we entered into agreements to purchase six new 1,500 horsepower rigs for a total of $91.6 million. All of these rigs are currently working, and in 2007 contributed 1,781 rig days. All eight of the recently purchased rigs, the rig recently constructed, the two built-for-purpose rigs expected to be deployed in 2008 and the 17 rig refurbishments completed over the last several years were supported by long-term contracts. We expect to recover substantially all of the cost of the capital expended for these rigs over the duration of their long-term contracts. Our fleet is expected to total 123 rigs by the end of the third quarter 2008.

Rig Activity

The U.S. land rig count at February 22, 2008, per the Baker Hughes rotary rig count, was 1,694 rigs and has remained relatively stable over the past year at historically high levels. However, there is currently some excess capacity in the land drilling market with the addition of new rigs during the last two years. Our average rigs working declined in 2007 because of this excess capacity of rigs in the market. While the number of rig days remaining under our term contracts has decreased, we believe that we are partially protected from declines in the land drilling market by our long-term contract portfolio. For the week ended February 22, 2008, we had an average of 98 rigs working. The table below shows the average number of land rigs working in the United States according to the Baker Hughes rotary rig count and the average number of our rigs working.

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Domestic	2006										2007										2008
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		2/22
Baker Hughes		1,417		1,512		1,603		1,609		1,535		1,626		1,653		1,691		1,705		1,669		1,676
GreyWolf		109		108		107		110		108		110		104		104		103		105		100

Term Contracts

We signed three-year term contracts for each of the two rigs acquired in July 2007 from a customer, signed a two-year term contract for the rig recently constructed, and signed three-year term contracts for each of the two built-for-purpose rigs to be deployed in 2008.

In the first quarter of 2007, we signed three-year term contracts with a major oilfield services company for two of our rigs to go to work in Mexico. This decision was made because it enabled us to enter into additional term contracts that provided us better returns than were otherwise available in our domestic markets at the time. These two rigs began operations in Mexico in the third quarter of 2007. See footnote 8 in the Notes to Consolidated Financial Statements for information regarding segment reporting.

Since the beginning of 2007, the rate at which we have been able to sign new term contracts has decreased significantly. As of December 31, 2007 we had 22,300 rig days contracted for under term contracts, as compared with 25,000 rig days under term contract at September 30, 2007, and 31,500 rig days under term contract at December 31, 2006. Our rig days under contract at February 18, 2008 is approximately equivalent to an average of 37 rigs working under term contracts for 2008 and an average of 18 rigs working for 2009. At February 18, 2008 we had 53 rigs working under term contracts, representing 44% of our total rig fleet. These term contracts are expected to provide revenue of approximately $289.7 million in 2008 and $150.9 million in 2009.

Drilling Contract Rates

As a result of newly-built and refurbished rigs that have come to market, there is currently some excess capacity of land drilling rigs. Since the latter part of 2006, we and some of our competitors have experienced some rigs becoming idle because of this excess rig capacity. Spot market dayrates have weakened in connection with the excess supply of land drilling rigs with the most competitive pressure being on smaller horsepower mechanical rigs. Since the third quarter of 2007, we have experienced moderate pressure on spot market dayrates for larger horsepower rigs as well. In addition, we have had to make concessions in contractual terms relating to amounts we seek to charge customers for “mobilization,” which is when we move our rig to the customer’s location. While we have a number of existing term contracts at fixed dayrates that have partially buffered our exposure to the continued erosion in spot market dayrates and the effects of extra capacity, we expect to continue to experience reductions in our overall dayrates in 2008 as some of our spot and term contracts come up for renewal at lower rates. As of February 18, 2008, our leading edge rates range from $14,000 to $20,000 per rig day, without fuel or top drives, compared to a range of $15,000 to $22,000 for the same time a year ago. Leading edge dayrates, although down from a year ago, have been relatively stable over the past several months. A rig day is defined as a twenty-four hour period in which a rig is under contract and should be earning revenue.

In addition to our fleet of drilling rigs, we owned 29 top drives at February 18, 2008, for which our rates are up to $3,000 per rig day. Rates for our top drives are in addition to the dayrates for our rigs.

Turnkey Contract Activity

Turnkey work is an important part of our business and operating strategy. Our engineering and operating expertise allow us to provide this service to our customers and has historically provided higher revenues and earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”) per rig day worked than under daywork contracts (see discussion under Results of Operations regarding the use of EBITDA and EBITDA per rig day). However, under turnkey contracts 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 2007, our turnkey EBITDA per rig day was $14,058 compared to a daywork EBITDA per rig day of $9,445, and

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our turnkey revenue was $53,825 per rig day compared to $21,121 per rig day for daywork. In 2006, our turnkey EBITDA per rig day was $15,694 compared to a daywork EBITDA per rig day of $10,397, and our turnkey revenue was $53,540 per rig day compared to $20,660 per rig day for daywork. For the year ended December 31, 2007, turnkey work represented 7% of total rig days worked compared to 10% of total rig days worked in 2006.

EBITDA generated on turnkey 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 contracts has historically been lower during periods of overall higher rig demand. Overall industry rig demand has been higher as evidenced by the increase in rig count in the past few years. Demand for our turnkey services has remained strong during this period of higher rig demand; however there has been a slight decline during the past few months.

Stock Repurchase Program

In September 2007, our board of directors authorized a $50.0 million increase in our common stock repurchase program. As of February 18, 2008, we have repurchased 19.0 million shares at a total cost of $121.9 million, exclusive of commissions, under the program. We may from time to time make purchases of common stock up to a cumulative amount of $150.0 million in open market or in privately negotiated block-trade transactions. The number of shares to be purchased and the timing of purchases will be based on a number of factors: the price of the common stock, general market conditions, available cash and alternate investment opportunities. We may terminate the stock repurchase program prior to completion.

First Quarter 2008 Outlook

During the first quarter of 2008, we expect to average 99 to 102 rigs working, with five to seven of these rigs performing turnkey services. In addition, we expect average daywork EBITDA per rig day to decrease by $700 to $800 in relation to the fourth quarter of 2007. Approximately half of this decline is related to an expected increase in daywork operating expenses per rig day as compared to the fourth quarter of 2007. The other half of the decline expected in the first quarter EBITDA per rig day is the result of reduced pricing on contract renewals and lower mobilization recoveries. We also expect depreciation expense of approximately $26.2 million, interest expense of approximately $3.3 million and an effective tax rate of approximately 37% for the first quarter of 2008.

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, 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 estimate the useful lives of our assets are between three and 20 years. We expense our maintenance and repair costs as incurred.

Impairment of Long-Lived Assets. In 2007, 2006 and 2005, no impairment of our long-lived assets was recorded. 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

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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, if any, 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. At December 31, 2007 and 2006, we had no rigs available for refurbishment as all rigs were working or actively marketed.

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 represented customer contracts and related relationships acquired and were 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.” The intangible assets were fully amortized in 2007. No impairment of our goodwill and intangible assets was recorded during 2007, 2006 and 2005.

Revenue Recognition. Revenues are earned under daywork and turnkey contracts. Revenue from daywork contracts is recognized when it is realized or realizable and earned. Revenue under daywork contracts is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum fees for mobilization of equipment. Mobilization fees and the related costs are deferred and amortized over the contract term. 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, 2007, there were five turnkey wells in progress versus three wells at December 31, 2006, with accrued revenue of $8.7 million and $6.9 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,

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2007 and 2006, we had $19.9 million and $16.5 million, respectively, accrued for losses incurred within the deductible amounts for workers’ compensation and general liability claims and for uninsured claims.

The amount accrued for the provision for losses incurred varies depending on the number and nature of the claims outstanding at the balance sheet dates. In addition, the accrual includes management’s estimate of the future cost to settle each claim such as future changes in the severity of the claim and increases in medical costs. We use third parties to assist us in developing our estimate of the ultimate costs to settle each claim, which is based upon historical experience associated with the type of each claim and specific information related to each claim. The specific circumstances of each claim may change over time prior to settlement and as a result, our estimates made as of the balance sheet dates may change.

Income Taxes. 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 and stock-based compensation awards. We routinely evaluate all deferred tax assets to determine the likelihood of their realization.

We adopted the provisions of FASB Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition and was effective for fiscal years beginning after December 15, 2006. We analyzed filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. As a result of adopting FIN 48, we recorded an increase to beginning retained earnings, as prescribed in this interpretation, in the amount of $1.2 million. This increase relates to net tax benefits for positions taken in our income tax returns that meet the recognition criteria in FIN 48. Prior to the adoption of FIN 48, these benefits were not recognized for financial statement purposes. Our policy is to accrue interest and penalties associated with uncertain tax positions in income tax expense. At January 1, 2007, no interest and penalties were accrued in connection with uncertain tax positions. At December 31, 2007, there was $449,000 of interest and penalties accrued in connection with uncertain tax positions. The tax years that remain open to examination by the major taxing jurisdictions to which we are subject range from 1996 to 2006. We have identified our major taxing jurisdictions as the United States, Texas and Louisiana.

At the date of adoption, we had $1.4 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized. As of December 31, 2007, we had $2.1 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized.

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Financial Condition and Liquidity

The following table summarizes our financial position as of December 31, 2007 and December 31, 2006.


	December 31,
	2007				2006
	(Dollars in thousands)
	Amount		%		Amount		%
Working capital	$	338,804		31	$	304,764		32
Property and equipment, net		737,944		67		608,136		65
Goodwill		10,377		1		10,377		1
Other noncurrent assets, net		16,153		1		16,625		2

Total	$	1,103,278		100	$	939,902		100


Long-term debt	$	275,000		25	$	275,000		29
Other long-term liabilities		168,769		15		131,108		14
Shareholders’ equity		659,509		60		533,794		57

Total	$	1,103,278		100	$	939,902		100

Significant Changes in Financial Condition

The significant changes in our financial position from December 31, 2006 to December 31, 2007 are an increase in working capital of $34.0 million, an increase in net property and equipment of $129.8 million, an increase in other long-term liabilities of $37.7 million, and an increase in shareholders’ equity of $125.7 million.

The increase in working capital is primarily the result of higher balances in cash and cash equivalents and a decrease in accounts payable, partially offset by a decrease in accounts receivable. The increase in cash and cash equivalents is due primarily to net income and the timing of accounts receivable collections and income tax payments. The decrease in accounts payable is primarily due to the timing of capital expenditures as well as to reduced operating expenses during the last few months of 2007. The decrease in accounts receivable is due to lower revenue resulting from an overall decrease in contracted rates during 2007 as well as fewer rigs working.

The increase in net property and equipment is due to capital expenditures during 2007, partially offset by 2007 depreciation. Capital expenditures of $220.2 million in 2007 included the costs to purchase four new 1,500 horsepower rigs, the purchase of two 1,500 horsepower rigs from a customer, and the construction of a 1,000 horsepower rig. In addition, capital expenditures in 2007 included costs incurred for drill pipe purchases, betterments and improvements to our rigs, and the purchase of top drives and other capital items. The increase in other long-term liabilities is primarily the result of higher deferred tax liabilities. Deferred tax liabilities are higher due to an increase in temporary book-to-tax depreciation differences as a result of our high levels of capital expenditures since the beginning of 2005 as well as to temporary book-to-tax differences related to interest deductions on the 3.75% Notes and Floating Rate Notes. The increase in shareholders’ equity is primarily due to the net income for the period offset by repurchases of common stock.

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 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, currently 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

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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 3 to our consolidated financial statements.

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

The 3.75% Notes are convertible, at the 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 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 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.

One of the triggering events permitting note holders to convert their 3.75% Notes into shares of our common stock was met at various times during the years ended December 31, 2007, 2006, and 2005. That triggering event is: if, during any calendar quarter, the closing 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 30^th trading day, then the 3.75% Notes become convertible at the note holders’ option. During the periods in which the 3.75% Notes were convertible, none of the note holders exercised their right to convert them into shares of our common stock. For the first quarter of 2008, the 3.75% Notes did not meet any of the conversion criteria.

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 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 on the Floating Rate Notes was 5.28% and 5.07% for the years ended December 31, 2007 and 2006, respectively. The interest rate is 4.68% for the first quarter of 2008. 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 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 of 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 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

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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 and 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.

During the third quarter of 2007, the Floating Rate Notes were convertible into shares of common stock because one of the triggering events permitting note holders to convert their Floating Rate Notes occurred during the second quarter of 2007. The triggering event was that the closing price per share of our common stock exceeded 120% of the conversion price ($7.81 per share) of the Floating Rate Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, 2007. None of the note holders exercised their right to convert the Floating Rate Notes into shares of common stock. For the first quarter of 2008, the Floating Rate Notes did not meet any of the conversion criteria.

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 expires December 31, 2008. The CIT Facility, as amended, 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 0.375% to 0.50% per annum on the unused portion of the CIT Facility. 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 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, 2007, our liquidity as defined above was $316.8 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

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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).

The CIT Facility allows us to repurchase shares of our common stock, pay dividends to our shareholders, and make prepayments on the 3.75% Notes and the Floating Rate Notes. However, all of the following conditions must be met to enable us to make payments for any of the above-mentioned reasons: (i) payments may not exceed $150.0 million in the aggregate, (ii) no Default or Event of Default shall exist at the time of any such payments, (iii) at least $35.0 million of Availability (availability under the CIT Facility plus cash on hand) exists immediately after any such payments, and (iv) we must provide CIT Group/Business Credit, Inc. three Business Days prior written notice of any such payments. Capitalized terms used in the preceding sentence but not defined herein are defined in the CIT Facility.

As of the date of this report, we did not have an outstanding balance under the CIT Facility and had $30.9 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,
	2007			2006			2005
Net cash provided by (used in):
Operating activities	$	295,832		$	288,230		$	221,612
Investing activities		(225,500	)		(170,514	)		(128,250	)
Financing activities		(52,404	)		(61,088	)		8,073

Net increase in cash	$	17,928		$	56,628		$	101,435

Our cash flow from operating activities are affected by a number of factors including the number of rigs working under contract, whether the contracts are daywork or turnkey, the dayrate received for daywork services and the successful completion of turnkey contracts. Cash flow from operating activities was higher by $7.6 million for the year ended December 31, 2007 compared to the same period in 2006. The most significant components resulting in an increase in cash flow provided by operating activities were a decrease in the accounts receivable balance, increase in the current income taxes payable balance and a higher deferred income tax balance. Partially offsetting these increases were a lower accounts payable balance and lower operating income. Accounts receivable decreased as a result of lower activity and dayrates later in 2007, while accounts payable decreased due to the timing of capital expenditures as well as to reduced operating expenses in the last few months of 2007. Operating income was lower in 2007 due to lower turnkey activity and lower dayrates and rig utilization for dayrate work.

Our cash flow generated from operating activities during the year ended December 31, 2006 was $288.2 million compared to $221.6 million for the year ended December 31, 2005. This increase is due primarily to an increase in net income as a result of higher dayrates and rig activity. Our higher activity and dayrates also caused an increase in accounts receivable which partially offset the higher cash flow generated from more net income.

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Cash flow used in investing activities for the year ended December 31, 2007 primarily consisted of $220.2 million of capital expenditures and $9.8 million for deposits on new rig purchases. Capital expenditures in 2007 included costs to purchase four new 1,500 horsepower rigs, the purchase of two 1,500 horsepower rigs from a customer, and the construction of a 1,000 horsepower rig. For the year ended December 31, 2006, cash flow used in investing activities primarily consisted of capital expenditures of $197.2 million, including costs for the reactivation of five rigs, replacement of a rig lost to fire, and the purchase of two new rigs. In addition, we also had $11.0 million in deposits for new rig purchases in 2006. For the year ended December 31, 2005, cash flow used in investing activities consisted of capital expenditures of $131.4 million, including costs for the reactivation of eleven rigs available for refurbishment. In addition to the items discussed above, capital expenditures for 2007, 2006 and 2005 included betterments and improvements to our rigs, the acquisition of drill pipe and drill collars, the purchase of top drives, and other capital items.

Cash flow used in financing activities for the years ended December 31, 2007 and 2006, consisted primarily of $56.0 million and $65.1 million, respectively, in repurchases of our common stock. 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.

Certain Contractual Commitments

The following table summarizes certain of our contractual cash obligations as of December 31, 2007 (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		87,188		5,625		11,250		11,250		59,063
Floating Rate Notes ⁽²⁾
Principal		125,000		—		—		—		125,000
Interest ⁽³⁾		95,063		5,850		11,700		11,700		65,813
New rig purchases		34,532		34,532		—		—		—
Rig equipment		3,421		3,421		—		—		—
Drill pipe and collars		5,521		5,521		—		—		—
Operating leases		2,426		1,014		1,356		56		—

Total contractual cash obligations	$	503,151	$	55,963	$	24,306	$	23,006	$	399,876


(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 2008 of 4.73% minus a spread of 0.05%.

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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 $69.1 million at December 31, 2007. The following table illustrates the undrawn outstanding standby letters of credit at December 31, 2007 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	$	30,916	$	—	$	30,916	$	—	$	—

Total	$	30,916	$	—	$	30,916	$	—	$	—


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

At December 31, 2007, we had $2.1 million of gross unrecognized tax benefits in connection with the adoption of FIN 48 that may result in cash payments being made to certain taxing authorities. We are not able to reasonably estimate in which future periods this amount may ultimately be settled and paid.

Projected Cash Sources and Uses

We expect to use cash generated from operations to cover cash requirements in 2008, including debt service on the 3.75% Notes and Floating Rate Notes, capital expenditures, tax payments, and common stock repurchases. 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. We believe that we will have sufficient cash from operations to meet these requirements. In future periods, we will continue to make interest payments on our Floating Rate Notes and 3.75% Notes through the maturity dates. Since 2004, the Company has generated sufficient earnings to cover debt related fixed charges, including interest, Additionally, we will have capital expenditure requirements to maintain our rig fleet and other assets, and expect to have tax payments. To the extent that we are unable to generate sufficient earnings to cover these requirements, including debt related fixed charges, we would be required to use cash on hand or draw on our CIT Facility.

Capital expenditures for 2008 are projected to be between $150 million and $160 million. We expect to spend approximately $34.5 million, net of $9.8 million of deposits made in 2007, to purchase two new built-for-purpose drilling rigs. These new rigs are expected to be delivered in the second and third quarters of 2008. We have obtained three-year term contracts on both of these rigs which, in the aggregate, are expected to generate revenue of approximately $47.4 million over the term of the contracts.

In addition, our projected capital expenditures for 2008 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 or turnkey basis. Successfully completed turnkey contracts generally result in higher revenues per rig day worked than under daywork contracts. EBITDA per rig day worked on successful turnkey 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 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 and EBITDA per rig day are non-GAAP financial measures under the rules and regulations of the Securities and Exchange Commission (“SEC”). We believe that our disclosure of EBITDA and 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

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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 and EBITDA per rig day may not be indicative of an improvement in our overall profitability. To compensate for the limitations in utilizing EBITDA and EBITDA per rig day as an operating measure, our management also uses GAAP measures of performance including operating income and net income 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 applicable to common shares, which is the nearest comparable GAAP financial measure.


	Years Ended December 31,
	2007			2006			2005
Earnings before interest expense, income taxes, depreciation and amortization	$	376,668		$	431,975		$	265,775
Depreciation and amortization		(97,361	)		(74,010	)		(61,279	)
Interest expense		(13,910	)		(13,614	)		(11,364	)
Total income tax expense		(95,505	)		(124,400	)		(72,495	)

Net income applicable to common shares	$	169,892		$	219,951		$	120,637

The following tables highlight rig days worked, contract drilling revenues and EBITDA for our daywork and turnkey operations for the years ended December 31, 2007, 2006 and 2005.


	Year Ended December 31, 2007
	Daywork			Turnkey
	Operations			Operations			Total
	(Dollars in thousands, except averages per rig day worked)
Rig days worked		35,607			2,871			38,478

Contract drilling revenues	$	752,045		$	154,532		$	906,577
Drilling operations expenses		(400,582	)		(113,265	)		(513,847	)
General and administrative expense		(27,503	)		(1,936	)		(29,439	)
Interest income		12,197			1,005			13,202
Gain on sale of assets		150			25			175

EBITDA	$	336,307		$	40,361		$	376,668


Averages per rig day worked:
Contract drilling revenues	$	21,121		$	53,825		$	23,561

EBITDA	$	9,445		$	14,058		$	9,789


	Year Ended December 31, 2006
	Daywork			Turnkey
	Operations			Operations			Total
	(Dollars in thousands, except averages per rig day worked)
Rig days worked		35,662			3,899			39,561

Contract drilling revenues	$	736,773		$	208,754		$	945,527
Drilling operations expenses		(368,637	)		(148,150	)		(516,787	)
General and administrative expense		(22,025	)		(2,280	)		(24,305	)
Interest income		10,365			1,121			11,486
Gain on sale of assets		10,633			1,262			11,895
Gain on insurance proceeds		3,675			484			4,159

EBITDA	$	370,784		$	61,191		$	431,975


Averages per rig day worked:
Contract drilling revenues	$	20,660		$	53,540		$	23,901

EBITDA	$	10,397		$	15,694		$	10,919

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	Year Ended December 31, 2005
	Daywork			Turnkey
	Operations			Operations			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		(14,750	)		(1,498	)		(16,248	)
Interest income		3,236			337			3,573
Gain on sale of assets		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

Comparison of Fiscal Years ended December 31, 2007 and 2006

Our EBITDA decreased by $55.3 million, or 13%, to $376.7 million for the year ended December 31, 2007 from $432.0 million for the year ended December 31, 2006. The decrease resulted from a $34.5 million decrease in EBITDA from daywork operations and a $20.8 million decrease in EBITDA from turnkey operations. On a per rig day basis, our total EBITDA decreased by $1,130 or 10% to $9,789 in 2007 from $10,919 in 2006. This decrease included a $952 per rig day decrease from daywork operations and a $1,636 per rig day decrease from turnkey operations. Total general and administrative expenses increased by $5.1 million, due primarily to higher costs for stock-based compensation, higher professional fees, and higher payroll costs. Total interest income increased by $1.7 million due primarily to higher cash balances in 2007 compared to 2006. The gain on sale of assets of $11.9 million in 2006 primarily relates to the sale of five rigs in January 2006. The gain on insurance proceeds of $4.2 million in 2006 relates to the proceeds received from the loss of one of our rigs and top drives.

Daywork Operations

The decrease in daywork EBITDA discussed above was due primarily to $31.9 million, or 9%, higher drilling operations expenses for the year ended December 31, 2007 compared to the same period in 2006. Drilling operations expenses were higher overall, and on a per rig day basis, due to several factors, primarily higher maintenance and repair costs and higher labor costs. In addition, 2006 daywork EBITDA included a $10.6 million gain on sale of assets and a $3.7 million gain on insurance proceeds. Partially offsetting the decrease in daywork EBITDA were higher contract drilling revenues for the period. Contract drilling revenues per rig day increased by $461, or 2%, including the effect of a wage increase on May 1, 2006 which was passed on to our customers in the form of higher dayrates.

Turnkey Operations

Turnkey EBITDA was lower for the year ended December 31, 2007 due primarily to a decrease in rig days worked and higher costs on a per rig day basis. Rig days worked decreased by 1,028 days, or 26% for the year ended December 31, 2007 compared to the same period in 2006. Also, differences in the complexity and success of the wells drilled between the two periods contributed to the decreased EBITDA and EBITDA per rig day. During the year ended December 31, 2007, we encountered difficulties on two turnkey contracts, generating losses under the contracts, which contributed to the lower EBITDA.

Other

Depreciation and amortization expense increased by $23.4 million, or 32%, to $97.4 million for the year ended December 31, 2007 compared to the same period in 2006. Depreciation and amortization expense is higher due primarily to capital expenditures made during 2006 and 2007, including the cost for the purchase of new rigs,

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rig refurbishments, betterments and improvements to our rigs, the acquisition of drill pipe and drill collars, the purchase of new top drives and other capital items.

Interest expense increased by $296,000, or 2%, to $13.9 million for the year ended December 31, 2007 from $13.6 million for the same period in 2006. This increase is due primarily to a higher interest rate on our Floating Rate Notes during 2007 as compared to 2006. Our average interest rate was 5.28% for the year ended 2007 as compared to 5.07% for the year ended 2006. There was no change in our debt balance during the year ended December 31, 2007.

Our income taxes decreased by $28.9 million to $95.5 million for the year ended December 31, 2007 from $124.4 million for the same period in 2006. The decrease is due to lower income before taxes, with no significant change in our effective tax rate.

Comparison of Fiscal Years ended December 31, 2006 and 2005

Our EBITDA increased by $166.2 million, or 63%, to $432.0 million for the year ended December 31, 2006 from $265.8 million for the year ended December 31, 2005. The increase resulted from a $152.6 million increase in EBITDA from daywork operations and a $13.6 million increase in EBITDA from turnkey operations. On a per rig day basis, our total EBITDA increased by $3,780, or 53% to $10,919 in 2006 from $7,139 in 2005. This increase included a $3,927 per rig day increase from daywork operations and a $2,126 per rig day increase from turnkey operations. Total general and administrative expenses increased by $8.1 million, due primarily to the expensing of stock options and restricted stock in 2006, as well as to higher payroll and short-term incentive costs, and employee retention plans but as a percentage of annual contract drilling revenues, remained essentially unchanged at 2.6%. Total interest income increased by $7.9 million due to higher cash balances and higher interest rates in 2006 compared to 2005. The gain on sale of assets increased by $11.8 million due mostly to the sale of five rigs held for refurbishment in January 2006. The gain on insurance proceeds of $4.2 million in 2006 relates to the proceeds received from the loss of one of our rigs and top drives.

Daywork Operations

The increase in EBITDA discussed above was due in part to an increase of 6%, or 1,944 rig days worked on daywork contracts during 2006 compared to 2005. This increase in days was due primarily to overall higher demand for our services and deployment of five rigs previously held for refurbishment. Higher dayrates, however, contributed more significantly to the increase in EBITDA with contract drilling revenue per rig day increasing $4,697, or 29%. The increase in dayrates includes the effect of a $540 per rig day wage increase effective May 1, 2006 which 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 increases in labor costs due to the above-mentioned wage increase, general inflationary cost increases on good and services, higher maintenance and repair costs, and the employee retention program implemented in November of 2005 to retain experienced personnel but as a percentage of dayrate contract drilling revenues, dayrate drilling operations expenses decreased to 50.0% in 2006 from 57.4% in 2005. Unlike wage increases, we have not passed the cost of our retention bonus program on to our customers as an increase in dayrates.

Turnkey Operations

Turnkey EBITDA was higher for the year ended December 31, 2006 due to higher revenue in total and on a per rig day basis. Contract drilling revenue per rig day increased $8,331, or 18%, with a small portion of this increase on a per rig day basis resulting from the May 1, 2006 wage increase that was passed on to our customers in the form of higher dayrates. Increasing daywork dayrates are considered in our turnkey bid process and resulted in price increases for our turnkey operations. These price increases resulted in higher revenue. The increase in EBITDA was also impacted by an increase in rig days worked. Rig days worked increased by 388 rig days, or 11%, for the year ended December 31, 2006 compared to the same period in 2005. Also, differences in the complexity and success of the wells drilled are a contributing factor to EBITDA fluctuations. During the third and fourth quarter of 2006, we encountered difficulties on certain turnkey contracts, generating losses, which partially offset the increase in EBITDA for the year ended December 31, 2006.

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Other

Depreciation and amortization expense increased by $12.7 million, or 21% to $74.0 million for the year ended December 31, 2006 compared to the same period in 2005. Depreciation and amortization expense is higher due to capital expenditures made during 2005 and 2006, primarily including the cost for rig refurbishments, betterments and improvements to our rigs, the acquisition of drill pipe and drill collars, the purchase of new top drives and other capital items.

Interest expense increased by $2.3 million, or 20%, to $13.6 million for the year ended December 31, 2006 from $11.4 million for the same period in 2005. This increase is due primarily to a higher interest rate on our Floating Rate Notes during 2006 as compared to 2005. Our average interest rate was 5.07% for the year ended 2006 as compared to 3.27% for the year ended 2005. There was no change in our debt balance during the year ended December 31, 2006.

Our income taxes increased by $51.9 million to $124.4 million for the year ended December 31, 2006 from $72.5 million for the same period in 2005. The increase is due to the higher level of income. We also utilized the majority of our remaining net operating loss carryforwards in 2005 for federal tax purposes which caused a significant increase in current tax expense versus deferred tax expense.

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, 2007. 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 18, 2008 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, 2007.


/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

February 28, 2008

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2007. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule for the years ended December 31, 2007, 2006, and 2005. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, 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.

As discussed in Note 2, the Company adopted the provisions of the Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB No. 109, effective January 1, 2007. As discussed in Note 1, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R), Shared-Based Payment, effective January 1, 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Grey Wolf, Inc.’s internal control over financial reporting as of December 31, 2007, 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 February 28, 2008, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.


	KPMG LLP

Houston, Texas
February 28, 2008

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Shareholders and Board of Directors
of Grey Wolf, Inc.:

We have audited Grey Wolf Inc.’s internal control over financial reporting as of December 31, 2007, 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, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, Grey Wolf, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 28, 2008, expressed an unqualified opinion on those consolidated financial statements.


	KPMG LLP

Houston, Texas
February 28, 2008

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GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Amounts in thousands, except share data)


	December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	247,701		$	229,773
Restricted cash		847			817
Accounts receivable, net of allowance of of $3,169		176,466			206,523
Prepaids and other current assets		13,337			7,817
Deferred tax assets		5,145			6,916

Total current assets		443,496			451,846


Property and equipment:
Land, buildings and improvements		8,534			7,044
Drilling equipment		1,331,401			1,107,457
Furniture and fixtures		5,397			4,839

Total property and equipment		1,345,332			1,119,340
Less: accumulated depreciation		(607,388	)		(511,204	)

Net property and equipment		737,944			608,136

Goodwill		10,377			10,377
Other noncurrent assets, net		16,153			16,625

	$	1,207,970		$	1,086,984

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable-trade	$	52,557		$	85,253
Accrued workers’ compensation		7,608			7,435
Payroll and related employee costs		15,439			15,952
Accrued interest payable		2,553			2,536
Current income taxes payable		14,705			20,641
Other accrued liabilities		11,830			15,265

Total current liabilities		104,692			147,082


Contingent convertible senior notes		275,000			275,000
Other long-term liabilities		18,126			9,877
Deferred income taxes		150,643			121,231

Commitments and contingent liabilities		—			—

Shareholders’ equity:
Series B Junior Participating Preferred stock; $1 par value; 250,000 shares authorized; none outstanding		—			—
Common stock; $0.10 par value; shares authorized: 300,000,000; shares issued: 197,045,996 at December 31, 2007 and 195,228,691 at December 31, 2006; shares outstanding: 178,345,603 at December 31, 2007 and 185,936,440 at December 31, 2006		19,704			19,523
Additional paid-in capital		393,894			383,482
Treasury stock, at cost: 18,700,393 shares at December 31, 2007 and 9,292,251 shares at December 31, 2006		(121,096	)		(65,119	)
Retained earnings		367,007			195,908

Total shareholders’ equity		659,509			533,794

	$	1,207,970		$	1,086,984

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,
	2007			2006			2005
Revenues:
Contract drilling	$	906,577		$	945,527		$	696,979

Costs and expenses:
Drilling operations		513,847			516,787			418,644
Depreciation and amortization		97,361			74,010			61,279
General and administrative		29,439			24,305			16,248
Gain on sale of assets		(175	)		(11,895	)		(115	)
Gain on insurance proceeds		—			(4,159	)		—

Total costs and expenses		640,472			599,048			496,056


Operating income		266,105			346,479			200,923

Other income (expense):
Interest expense		(13,910	)		(13,614	)		(11,364	)
Interest income		13,202			11,486			3,573

Other expense, net		(708	)		(2,128	)		(7,791	)


Income before income taxes		265,397			344,351			193,132

Income tax expense:
Current		75,427			123,114			11,717
Deferred		20,078			1,286			60,778

Total income tax expense		95,505			124,400			72,495


Net income	$	169,892		$	219,951		$	120,637


Net income per common share (Note 1):
Basic	$	0.93		$	1.16		$	0.63

Diluted	$	0.79		$	0.98		$	0.54


Weighted average common shares outstanding:
Basic		182,006			190,088			191,364

Diluted		225,649			233,818			235,412

See accompanying notes to consolidated financial statements

-41-

GREY WOLF, INC. AND SUBSIDIARIES

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


	Series B
	Junior
	Participating		Common Stock								Treasury Stock
	Preferred					Amount,		Additional								Retained
	Stock		Number of			at $0.10		Paid-in			Number		Amount,			Earnings
	$1 par Value		Shares			par value		Capital			of Shares		at cost			(Deficit)			Total
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, net of forfeitures		—		198			20		(20	)		—		—			—			—
Stock-based compensation expense		—		—			—		198			—		—			—			198
Comprehensive net income		—		—			—		—			—		—			120,637			120,637

Balance, December 31, 2005		—		192,626			19,263		374,012			—		—			(24,043	)		369,232
Exercise of stock options		—		905			90		3,062			—		—			—			3,152
Tax effect of share-based payments		—		—			—		1,330			—		—			—			1,330
Issuance of restricted stock, net of forfeitures		—		1,697			170		(170	)		—		—			—			—
Stock-based compensation expense		—		—			—		5,248			—		—			—			5,248
Purchase of treasury stock		—		(9,292	)		—		—			9,292		(65,119	)		—			(65,119	)
Comprehensive net income		—		—			—		—			—		—			219,951			219,951

Balance, December 31, 2006		—		185,936			19,523		383,482			9,292		(65,119	)		195,908			533,794
Adjustment for the adoption of FASB Interpretation No. (FIN) 48		—		—			—		—			—		—			1,207			1,207
Exercise of stock options		—		802			80		2,785			—		—			—			2,865
Tax effect of share-based payments		—		—			—		749			—		—			—			749
Issuance of restricted stock, net of forfeitures		—		1,016			101		(101	)		—		—			—			—
Stock-based compensation expense		—		—			—		6,979			—		—			—			6,979
Purchase of treasury stock		—		(9,408	)		—		—			9,408		(55,977	)		—			(55,977	)
Comprehensive net income		—		—			—		—			—		—			169,892			169,892

Balance, December 31, 2007		—		178,346		$	19,704	$	393,894			18,700	$	(121,096	)	$	367,007		$	659,509

See accompanying notes to consolidated financial statements

-42-

GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows
(Amounts in thousands)


	Years Ended December 31,
	2007			2006			2005
Cash flows from operating activities:
Net income	$	169,892		$	219,951		$	120,637
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		97,361			74,010			61,279
Gain on insurance proceeds		—			(4,159	)		—
Gain on sale of assets		(175	)		(11,895	)		(115	)
Provision for doubtful accounts		—			495			250
Stock-based compensation expense		6,979			5,248			198
Deferred income taxes		20,078			1,286			60,778
Excess tax benefit of stock option exercises		(708	)		(879	)		2,842
Increase in restricted cash		(30	)		(37	)		(22	)
(Increase) decrease in accounts receivable		30,057			(47,580	)		(61,623	)
(Increase) decrease in other current assets		(5,520	)		193			(2,913	)
Increase (decrease) in trade accounts payable		(32,696	)		24,166			18,333
Increase (decrease) in accrued workers’ compensation		3,315			(1,530	)		6,257
Increase (decrease) in other current liabilities		(3,931	)		12,407			8,019
Increase in current taxes payable		7,125			15,830			5,941
Increase in other		4,085			724			1,751

Cash provided by operating activities		295,832			288,230			221,612


Cash flows from investing activities:
Property and equipment additions		(220,191	)		(197,161	)		(131,352	)
Insurance proceeds		—			11,076			—
Deposits for new rig purchases		(9,771	)		(10,979	)		—
Proceeds from sale of assets		4,462			26,550			3,102

Cash used in investing activities		(225,500	)		(170,514	)		(128,250	)


Cash flows from financing activities:
Proceeds from exercise of stock options		2,865			3,152			8,073
Excess tax benefit of stock options		708			879			—
Purchase of treasury stock		(55,977	)		(65,119	)		—

Cash (used in) provided by financing activities		(52,404	)		(61,088	)		8,073


Net increase in cash and cash equivalents		17,928			56,628			101,435
Cash and cash equivalents, beginning of year		229,773			173,145			71,710

Cash and cash equivalents, end of year	$	247,701		$	229,773		$	173,145


Supplemental Cash Flow Disclosure
Cash paid for interest	$	13,033		$	12,373		$	9,862

Cash paid for taxes	$	66,150		$	107,052		$	2,985

See accompanying notes to consolidated financial statements

-43-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Nature of Operations. Grey Wolf, Inc., a Texas corporation formed in 1980, 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, Wyoming and Mexico. The consolidated financial statements include the accounts of Grey Wolf, Inc. and its majority-owned subsidiaries (the “Company” or “Grey Wolf”). All 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, 2007, 2006 and 2005 was $97.1 million, $72.9 million and $60.2 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. For the years ended December 31, 2007, 2006 and 2005, no impairment of our long-lived assests was recorded. 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. For the years ended December 31, 2007, 2006 and 2005, no impairment of our goodwill was recorded. The Company’s intangible assets represent customer contracts and related relationships acquired and have been amortized over the useful life of three years. Amortization expenses related to these intangible assets was $286,000, $1.1 million and $1.1 million, respectively, in the years ended December 31, 2007, 2006, and 2005. As of December 31, 2007, the intangible assets were fully amortized. The net balance of these intangible assets was included in net other noncurrent assets on the consolidated balance sheet in 2006. Accumulated amortization was $2.9 million as of December 31, 2006.

Revenue Recognition. Contract drilling revenues are earned under daywork and turnkey contracts. Revenue from daywork 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. For certain contracts, the Company receives lump-sum fees for mobilization of equipment. Mobilization fees and the related costs are deferred and amortized over the contract terms. Revenue from turnkey drilling contracts is recognized using the percentage-of-completion method based upon costs incurred to date and estimated total contract costs. Anticipated losses, if any, on uncompleted contracts are recorded at the time the estimated costs exceed the contract revenue.

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

-44-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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:


	Years Ended December 31,
	2007		2006		2005
	(In thousands, except per share amounts)
Numerator:
Net income	$	169,892	$	219,951	$	120,637

Add interest expense on Contingent
Convertible Senior Notes, net of related tax effects		8,325		8,117		6,596

Adjusted net income – diluted	$	178,217	$	228,068	$	127,233


Denominator:
Weighted average common shares outstanding – basic		182,006		190,088		191,364

Effect of dilutive securities:
Options – treasury stock method		600		887		1,552
Restricted stock – treasury stock method		586		386		39
Contingent Convertible Senior Notes		42,457		42,457		42,457


Weighted average common shares outstanding – diluted		225,649		233,818		235,412


Earnings per common share:
Basic	$	0.93	$	1.16	$	0.63

Diluted	$	0.79	$	0.98	$	0.54

-45-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A summary of securities excluded from the computation of basic and diluted earnings per share is presented below for the applicable periods (in thousands):


	Years Ended December 31,
	2007		2006		2005
Basic earnings per share:
Unvested restricted stock		2,504		1,896		198


Diluted earnings per share:
Anti-dilutive stock options		1,411		758		—

Anti-dilutive restricted stock		62		—		135


Total anti-dilutive securities excluded from diluted earnings per share		1,473		758		135

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 and foreign subsidiaries file returns in the appropriate jurisdictions.

Share-Based Payment Arrangements. At December 31, 2007, the Company had stock-based compensation plans with employees and directors, which are more fully described in Note 4. Prior to January 1, 2006, the Company accounted for those plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by SFAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, no stock-based compensation expense was recognized, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, the Company adopted the fair value provisions of SFAS No. 123(R), “Share-Based Payment,” using the modified-prospective transition method. Under that transition method, compensation expense recognized for the years ended December 31, 2007 and 2006 includes: (a) compensation expense for all share-based payments granted prior to, but not yet vested, as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123; and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The Company records compensation expense over the requisite service period using the straight-line method.

The fair value of each stock option is estimated on the date of grant using the Black-Scholes-Merton option-valuation model. The key input variables used in valuing the options granted in 2007 and 2006 were: risk-free interest rate based on three-year U.S. Treasury strips of 4.83% in 2007 and 4.89% in 2006; dividend yield of zero for each year; stock price volatility of 36% in 2007 and 39% in 2006 based on historical volatility of the Company’s stock with consideration given to implied volatilities from traded options on the Company’s stock; and expected option lives of three years for each year based on historical stock option exercise data and future expectations.

Prior to the adoption of SFAS No.123(R), the Company presented tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS No. 123(R) requires the cash flows from the tax benefits resulting from tax deductions in excess of the tax benefit associated with compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows.

-46-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A summary of the Company’s stock option activity for the year ended December 31, 2007 is presented below:


						Weighted-
						Average
				Weighted-		Remaining
				Average		Contractual		Aggregate
	Shares			ExercisePrice		Life		IntrinsicValue
	(in thousands)					(in years)		(in thousands)
Outstanding at January 1, 2007		3,619		$	4.23
Granted		578			6.67
Exercised		(802	)		3.57
Forfeited		(12	)		4.56

Outstanding at December 31, 2007		3,383		$	4.80		5.83	$	3,643

Exercisable at December 31, 2007		1,864		$	4.03		4.39	$	2,966

The weighted-average grant-date fair value of options granted during the year ended December 31, 2007, 2006 and 2005 was $2.01, $2.35 and $2.99, respectively. The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005 was $3.3 million, $3.8 million and $8.1 million, respectively.

As of December 31, 2007, there was $1.8 million of total unrecognized compensation cost related to outstanding stock options. That cost is expected to be recognized over a weighted-average period of 1.7 years. The amount of stock option expense for the years ended December 31, 2007, 2006 and 2005 was $1.7 million, $2.1 million and $0, respectively.

A summary of the status of the Company’s shares of restricted stock as of December 31, 2007, and changes during the year then ended is presented below:


				Weighted-Average
				Grant-Date
	Shares			Fair Value
	(in thousands)
Non-vested at January 1, 2007		1,896		$	7.16
Granted		1,067			6.67
Forfeited		(52	)		7.21
Vested		(407	)		7.15

Non-vested at December 31, 2007		2,504		$	6.95

As of December 31, 2007, there was $9.8 million of total unrecognized compensation cost related to shares of restricted stock. That cost is expected to be recognized over a weighted-average period of 1.9 years. The amount of expense related to restricted stock for the years ended December 31, 2007, 2006 and 2005 was $5.3 million, $3.2 million and $198,000, respectively. The weighted-average grant-date fair value per share of restricted stock granted during the year ended December 31, 2007 and 2006 was $6.67 and $7.30, respectively.

-47-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to stock options granted for the year ended December 31, 2005 (in thousands, except per share amounts).


Net income, as reported	$	120,637
Add: Stock-based compensation expense included in reported net income, net of related tax effects		124
Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of related tax effects		(2,322	)

Pro forma net income	$	118,439


Basic earnings per share
As reported	$	0.63
Pro forma	$	0.62
Diluted earnings per share
As reported	$	0.54
Pro forma	$	0.53

For purposes of determining compensation expense using the provisions of SFAS No. 123, the fair value of option grants was determined using the Black-Scholes-Merton option-valuation model. The key input variables used in valuing the options granted in 2005 were: risk-free interest rate based on five-year U.S. Treasury strips of 3.86% to 4.46%; dividend yield of zero; stock price volatility of 53% to 57%; and expected option lives of five years.

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% Notes was $147.4 million and $178.0 million at December 31, 2007 and 2006, respectively versus a face value of $150.0 million. The fair value of the Floating Rate Notes was $132.5 and $159.7 million at December 31, 2007 and 2006, 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. The majority 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.

-48-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2007, the FASB issued SFAS No. 141(R), “Business Combinations”. This pronouncement requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS No. 141(R), all business combinations will be accounted for by applying the acquisition method. The Statement is effective for periods beginning on or after December 15, 2008 and earlier application is prohibited. SFAS No. 141(R) will be applied to business combinations occurring after the effective date.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements- An Amendment of ARB No. 51.” This pronouncement requires noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. SFAS No. 160 becomes effective for the year ended December 31, 2009 and interim periods therein. Management does not believe this pronouncement will be applicable to the Company.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. Management does not believe the requirements of SFAS No. 159 will have a material impact on the consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. In November 2007, the FASB deferred for one year the application of the fair value measurement requirements to nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. Management does not believe the adoption of the provisions of SFAS No. 157 related to financial assets and liabilities measured at fair value on a recurring basis will have a material impact on the consolidated financial statements. Beginning January 1, 2009, the Company will adopt the provisions for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis, which management does not expect to have a material impact on the consolidated financial statements.

Reclassification. Certain prior period balances have been reclassified to conform to the presentations in 2007 and 2006.

(2) Income Taxes

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

-49-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Years Ended December 31,
	2007		2006			2005
Current Federal	$	68,670	$	111,885		$	10,260
Foreign		—		—			107
State		6,757		11,229			1,350

	$	75,427	$	123,114		$	11,717


Deferred
Federal	$	19,605	$	2,933		$	56,937
State		473		(1,647	)		3,841

	$	20,078	$	1,286		$	60,778

The United States and Mexico components of income (loss) before income taxes were as follows (amounts in thousands):


	Years Ended December 31,
	2007			2006		2005
United States	$	268,185		$	344,351	$	193,132
Mexico		(2,788	)		—		—

	$	265,397		$	344,351	$	193,132

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 were as follows (amounts in thousands):


	December 31,
	2007			2006
Deferred tax assets
Workers compensation accruals	$	7,244		$	6,072
Long-term incentive plans		3,240			4,062
Net operating losses		781			—
Other		2,760			3,116

		14,025			13,250
Less: valuation allowance		(781	)		—

		13,244			13,250

Deferred tax liabilities
Depreciation		143,162			127,565
Interest deductions on Contingent Convertible Debt		15,580			—

		158,742			127,565

Net deferred tax liability	$	145,498		$	114,315

The net operating losses (“NOL’s”) relate to the Company’s operations in Mexico. These NOL’s are not expected to be realized due to the level of future taxable income, and as such a valuation allowance has been applied

-50-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to the full amount of the NOL’s. For the remaining deferred tax assets, no valuation allowance was recorded as of December 31, 2007 and 2006, 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.

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


	Years Ended December 31,
	2007			2006			2005
Income tax expense at statutory rate	$	92,889		$	120,523		$	67,596

Increase (decrease) in taxes resulting from:
Permanent differences
Section 199 “Manufacturing Deduction”		(4,537	)		(3,418	)		—
Basis differences in assets that were purchased in capital stock acquisitions		972			972			972
State taxes, net		4,529			5,950			3,131
Valuation allowance on foreign tax assets		781			—			—
Other		871			373			796

Income tax expense	$	95,505		$	124,400		$	72,495

The Company adopted the provisions of FASB Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition and was effective for fiscal years beginning after December 15, 2006. The Company analyzed filing positions in all of the federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in these jurisdictions. As a result of adopting FIN 48, the Company recorded an increase to beginning retained earnings, as prescribed in this interpretation, in the amount of $1.2 million. This increase relates to net tax benefits for positions taken in the Company’s income tax returns that meet the recognition criteria in FIN 48. Prior to the adoption of FIN 48, these benefits were not recognized for financial statement purposes. The Company’s policy is to accrue interest and penalties associated with uncertain tax positions in income tax expense. At January 1, 2007, no interest and penalties were accrued in connection with uncertain tax positions. At December 31, 2007, there was $449,000 of interest and penalties accrued in connection with uncertain tax positions. The tax years that remain open to examination by the major taxing jurisdictions to which the Company is subject range from 1996 to 2006. The Company has identified its major taxing jurisdictions as the United States, Texas and Louisiana.

At the date of adoption, the Company had $1.4 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized. As of December 31, 2007, the Company had $2.1 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized.

-51-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The activity associated with our unrecognized tax benefit during 2007 is as follows (in thousands):


Tax benefits unrecognized at January 1, 2007	$	1,446
Increases from:
Tax positions taken during a prior period		—
Tax positions taken during the current period		733
Decreases from:
Tax positions taken during a prior period		(38	)
Settlements with taxing authorities		—
Lapse of applicable statute of limitations		—

Tax benefits unrecognized at December 31, 2007	$	2,141

(3) Long-Term Debt

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


	December 31,
	2007		2006
Contingent Convertible Senior Notes due May 2023	$	150,000	$	150,000

Floating Rate Contingent Convertible Senior Notes due April 2024		125,000		125,000

	$	275,000	$	275,000
Less current maturities		—		—

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

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 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, currently 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.

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	%

-52-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 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 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.

One of the triggering events permitting note holders to convert their 3.75% Notes into shares of the Company’s common stock was met at various times during the years ended December 31, 2007, 2006, and 2005. That triggering event is: if, during any calendar quarter, 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 30^th trading day, then the 3.75% Notes become convertible at the note holders’ option. During the periods in which the 3.75% Notes were convertible, none of the note holders exercised their right to convert them into shares of the Company’s common stock.

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 on the Floating Rate Notes was 5.28% and 5.07% for the years ended December 31, 2007 and 2006, respectively. The interest rate was 5.18% and 5.32% for the quarters ended December 31, 2007 and 2006, 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 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% Notes. Fees and expenses of

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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.

During the third quarter of 2007, the Floating Rate Notes were convertible into shares of the Company’s common stock because one of the triggering events permitting note holders to convert their Floating Rate Notes occurred during the second quarter of 2007. The triggering event was that the closing price per share of the Company’s common stock exceeded 120% of the conversion price ($7.81 per share) of the Floating Rate Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, 2007. None of the note holders exercised their right to convert the Floating Rate Notes into shares of the Company’s common stock.

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 expires December 31, 2008. The CIT Facility, as amended, 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 0.375% to 0.50% per annum on the unused portion of the CIT Facility. Letters of credit accrue a fee of 1.25% per annum. The Company incurred $801,000, $786,000 and $760,000 for the years ended December 31, 2007, 2006, and 2005, respectively, related to these fees. The letters of credit fees are reflected in interest expense on the consolidated statements of operations.

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

-54-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2007, the Company’s liquidity as defined above was $316.8 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).

The CIT Facility allows the Company to repurchase shares of its common stock, pay dividends to its shareholders, and make prepayments on the 3.75% Notes and the Floating Rate Notes. However, all of the following conditions must be met to enable the Company to make payments for any of the above-mentioned reasons: (i) payments may not exceed $150.0 million in the aggregate, (ii) no Default or Event of Default shall exist at the time of any such payments, (iii) at least $35.0 million of Availability (availability under the CIT Facility plus cash on hand) exists immediately after any such payments, and (iv) the Company must provide CIT Group/Business Credit, Inc. three Business Days prior written notice of any such payments. Capitalized terms used in the preceding sentence but not defined herein are defined in the CIT Facility.

The Company currently has no outstanding balance under the CIT Facility and had $30.9 million of undrawn, standby letters of credit at December 31, 2007. 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.

(4) 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

-55-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 22.0 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, 2007, there were 7.2 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, 2007, these individuals had options outstanding to purchase an aggregate of 700,500 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.

Shares of restricted stock entitle the holder to one vote per share and are only restricted due to vesting conditions. Restricted shares vest in varying increments over three to five-year periods.

(5) 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 2007, 2006 and 2005 were $36.0 million, $41.5 million and $18.2 million, respectively. These affiliates had accounts receivable balances with the Company of $6.1 million and $10.7 million at December 31, 2007 and 2006, respectively. All services performed for these companies were done so at prevailing market rates.

-56-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(6) 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, 2007 are as follows:


Year	Amount
2008	$	1,014,000
2009		701,000
2010		655,000
2011		56,000
2012		—

	$	2,426,000

Lease expense under operating leases for 2007, 2006 and 2005 was approximately $973,000, $846,000 and $931,000, respectively.

New Rig Purchases

The Company has agreed to purchase two new 1,500 horsepower built-for-purpose rigs in 2008 with estimated remaining payments of $34.5 million.

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.

(7) 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 $2.3 million, $1.7 million and $1.4 million for the years ended December 31, 2007, 2006 and 2005, respectively. Upon reaching the service requirements to join the plan, participants immediately vest in employer matching contributions.

(8) Segment Information

Prior to the third quarter of 2007, the Company managed its business as one reportable segment. Although the Company provided onshore contract drilling services in several markets, these operations were 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.

During the third quarter of 2007, the Company began operations in Mexico. The domestic and Mexican operations are considered separate segments as a result of differences in economic characteristics, separate regulatory environments, and different types of customers being served. Domestic operations were 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. Intersegment revenue is eliminated in consolidation.

The following tables set forth certain financial information with respect to the Company’s reportable segments (in thousands):

-57-

GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Years ended December 31,
	2007		2006		2005
Revenue
United States	$	897,484	$	945,527	$	696,979
Mexico		9,093		—		—

Total revenue	$	906,577	$	945,527	$	696,979


Operating Income
United States	$	265,651	$	346,479	$	200,923
Mexico		454		—		—

Total operating income	$	266,105	$	346,479	$	200,923


Capital expenditures
United States⁽¹⁾	$	229,555	$	208,140	$	131,352
Mexico		407		—		—

Total capital expenditures	$	229,962	$	208,140	$	131,352


Assets
United States	$	1,189,620	$	1,086,984	$	869,035
Mexico		18,350		—		—

Total assets	$	1,207,970	$	1,086,984	$	869,035


(1)		Capital expenditures for the United States segment include deposits for new rig purchases. For the years ended December 31, 2007 and 2006, deposits for new rig purchases were $9.8 million and $11.0 million, respectively.

Concentrations

There were no customers representing greater than 10% of the Company’s revenue for the years ended December 31, 2007, 2006 and 2005.

(9) Insurance Recoveries

The Company maintains insurance coverage to protect against certain hazards inherent in contract drilling operations. During 2006, the Company experienced a fire on one of its 2,000 horsepower diesel electric rigs, which was drilling under a daywork contract in South Louisiana. The fire resulted in a total loss of the rig and one of the Company’s top drives which was being used on this rig. The Company filed a claim with its insurance carriers to recoup this loss. The net book value of the rig and top drive was $6.9 million at the time of the loss. The Company recorded a gain of $4.2 million in 2006 resulting from the insurance proceeds.

Also in 2006, the Company encountered difficulties on a well being drilled under a turnkey contract. The cost associated with the difficulties is covered by the Company’s insurance subject to a deductible of $1.4 million. The costs incurred totaled approximately $8.7 million, of which $7.2 million was recovered through the Company’s insurance, after satisfaction of the deductible, in 2007.

In 2007, the Company encountered difficulties on a well being drilled under another turnkey contract. The cost associated with the difficulties is covered by the Company’s insurance, subject to a deductible of $375,000. The costs incurred totaled approximately $2.5 million, of which $1.6 million was recovered through the Company’s insurance after satisfaction of the deductible. As of December 31, 2007, $248,000 of the receivable had not been collected. This balance was collected in January of 2008.

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GREY WOLF, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Insurance recoveries associated with the turnkey contracts discussed above are shown as a reduction to drilling operations expenses on the consolidated statements of operations.

(10) Asset Sales

During 2006, the Company sold five of its rigs formerly held for refurbishment and certain of its spare equipment in separate transactions. The Company received $21.1 million in cash in exchange for the five rigs and spare equipment, which resulted in a gain of $10.8 million during the year ended December 31, 2006. The Company also recorded other gains on sales of vehicles and equipment which are included on the consolidated statements of operations.

(11) Treasury Stock

On May 25, 2006, the Company announced that its Board of Directors approved a plan authorizing the repurchase of up to $100.0 million shares of common stock in open market or in privately negotiated block-trade transactions. On September 25, 2007, the Company announced that its Board of Directors authorized a $50.0 million increase in the common stock repurchase program, bringing the total program to $150.0 million. The number of shares purchased and the timing of purchases is based on several factors, including the price of the common stock, general market conditions, available cash and alternate investment opportunities. The stock repurchase program is subject to termination prior to completion. As of December 31, 2007, the Company repurchased 18.6 million shares at a total price of $120.4 million, inclusive of commissions, under this program.

The Company also had treasury shares that were acquired through the vesting of restricted stock. The Company’s employees elected to have shares withheld to cover required minimum payroll tax withholdings incurred when restricted stock vests. The number of shares withheld is based upon the market price of the common stock at the time of vesting. The Company then pays the taxes on the employees’ behalf and holds the shares withheld as treasury stock. As of December 31, 2007, approximately 111,000 shares were acquired through such treasury share purchases.

(12) Quarterly Financial Data (unaudited)

Summarized quarterly financial data for the years ended December 31, 2007, 2006 and 2005 are set forth below (amounts in thousands, except per share amounts).


	Quarter Ended
	March		June		September		December
	2007		2007		2007		2007
Contract drilling revenues	$	242,013	$	227,520	$	223,999	$	213,045
Operating income		92,300		65,733		55,982		52,090
Income before income taxes		91,967		65,888		55,795		51,747
Net income		58,578		41,708		35,588		34,018
Net income per common share
– basic	$	0.32	$	0.23	$	0.19	$	0.19
– diluted	$	0.27	$	0.19	$	0.17	$	0.16

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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, 2007, 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 37 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.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

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 2008 Annual Meeting of Shareholders.

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 2008 Annual Meeting of Shareholders.

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

The following table provides information as of December 31, 2007 with respect to the number of shares of common stock remaining available for issuance under the 1996 Employee Plan and the 2003 Incentive Plan and other equity compensation plans.

Equity Compensation Plan Information

Number of securities remaining

Weighted average

available for future issuance

Number of securities to

exercise

under equity compensation

be issued upon exercise

price of outstanding

plans

of outstanding options,

options, warrants and

(excluding securities reflected

warrants and rights

rights

in column (a))

Plan Category

(a)

(b)

(c)

Equity compensation plans approved by security holders

2,682,252

5.231

7,213,823

Equity compensation plans not approved by security holders⁽¹⁾

700,500

3.154

—

Total

3,382,752

4.801

7,213,823


(1)		Reflects options granted to non-employee Board members. These options have an exercise price equal to the fair market value of the Common Stock on the date of grant, expire 10 years from the date of grant.

The other information required by this Item is hereby incorporated by reference to our definitive proxy statement for our 2008 Annual Meeting of Shareholders.

Item 13. Certain Relationships and Related Transactions, and Director independence

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 2008 Annual Meeting of Shareholders.

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 2008 Annual Meeting of Shareholders.

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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.

3. 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	—	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).

-64-


Exhibit
No.		Documents

+10.2	—	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).

+10.3	—	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).

+10.4	—	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).

+10.5	—	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, 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).

+10.6	—	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).

+10.7	—	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).

+10.8	—	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).

+10.9	—	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).

+10.10	—	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).

+10.11	—	Employment Agreement effective July 30, 2007 by and between David J. Crowley (incorporated by reference to Exhibit 10.1 of the Grey Wolf, Inc. Current Report on Form 8-K filed July 30, 2007).

+10.12	—	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).

+10.13	—	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).

+10.14	—	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).

+10.15	—	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).

-65-


Exhibit
No.		Documents

+10.16	—	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.)

+10.17	—	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.)

+10.18	—	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.)

+10.19	—	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).

+10.20	—	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).

+10.21	—	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).

+10.22	—	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).

+10.23	—	Anticipated compensation of officers and directors for 2007 (incorporated by reference to Grey Wolf, Inc. Current Report on Form 8-K filed February 16, 2007).

10.24	—	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).

10.25	—	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).

10.26	—	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).

10.27	—	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).

10.28	—	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).

-66-


Exhibit
No.		Documents

10.29	—	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).

10.30	—	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.

-67-

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 28^th day of February, 2008.


		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 Thomas P. Richards, Chairman, President and Chief Executive Officer	February 28, 2008
	(Principal Executive Officer)

By:	/s/ David W. Wehlmann David W. Wehlmann, Executive Vice President and Chief Financial Officer	February 28, 2008

By:	/s/ Kent D. Cauley Kent D. Cauley, Vice President and Controller	February 28, 2008

By:	/s/ William R. Ziegler William R. Ziegler, Director	February 28, 2008

By:	/s/ Frank M. Brown Frank M. Brown, Director	February 28, 2008

By:	/s/ William T. Donovan William T. Donovan, Director	February 28, 2008

By:	/s/ Robert E. Rose Robert E. Rose, Director	February 28, 2008

By:	/s/ Trevor M. Turbidy Trevor M. Turbidy, Director	February 28, 2008

By:	/s/ Steven A. Webster Steven A. Webster, Director	February 28, 2008

-68-

Exhibit Index


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	—	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).

+10.2	—	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).

+10.3	—	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).


Exhibit
No.		Documents

+10.4	—	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).

+10.5	—	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, 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).

+10.6	—	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).

+10.7	—	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).

+10.8	—	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).

+10.9	—	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).

+10.10	—	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).

+10.11	—	Employment Agreement effective July 30, 2007 by and between David J. Crowley (incorporated by reference to Exhibit 10.1 of the Grey Wolf, Inc. Current Report on Form 8-K filed July 30, 2007).

+10.12	—	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).

+10.13	—	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).

+10.14	—	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).

+10.15	—	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).

+10.16	—	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.)


Exhibit
No.		Documents

+10.17	—	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.)

+10.18	—	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.)

+10.19	—	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).

+10.20	—	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).

+10.21	—	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).

+10.22	—	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).

+10.23	—	Anticipated compensation of officers and directors for 2007 (incorporated by reference to Grey Wolf, Inc. Current Report on Form 8-K filed February 16, 2007).

10.24	—	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).

10.25	—	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).

10.26	—	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).

10.27	—	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).

10.28	—	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).


Exhibit
No.		Documents

10.29	—	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).

10.30	—	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		9

Item 1B.	Unresolved Staff Comments		16

Item 2.	Properties		16

Item 3.	Legal Proceedings		18

Item 4.	Submission of Matters to a Vote of Security Holders		18

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		20

Item 7.	Management’s Discussion and Analysis Of Financial Condition and Results Of Operations		21

Item 7A.	Quantitative and Qualitative Disclosure about Market Risk		35

Item 8.	Financial Statements and Supplementary Data		36

Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure		62

Item 9A.	Controls and Procedures		62

Item 9B.	Other Information		62

Part III

Item 10.	Directors, Executive Officers and Corporate Governance		62

Item 11.	Executive Compensation		62

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		63

Item 13.	Certain Relationships and Related Transactions, and Director Independence		63

Item 14.	Principal Accountant Fees and Services		63

Part IV

Item 15.	Exhibits and Financial Statement Schedules		64

	Signatures		68
List of Subsidiaries
Consent of KPMG LLP
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification Pursuant to Section 1350


Management’s Report on Internal Control Over Financial Reporting			37

Report of Independent Registered Public Accounting Firm			38

Consolidated Balance Sheets as of December 31, 2007 and 2006			40

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005			41

Consolidated Statements of Shareholders’ Equity And Comprehensive Income For the Years Ended December 31, 2007, 2006, and 2005			42

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005			43

Notes to Consolidated Financial Statements			44

Financial Statement Schedule:

Schedule II – Valuation and Qualifying Accounts			61


			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, 2005
Allowance for doubtful accounts receivable	$	2,424	$	250	$	—	$	2,674


Year ended December 31, 2006
Allowance for doubtful accounts receivable	$	2,674	$	495	$	—	$	3,169


Year ended December 31, 2007
Allowance for doubtful accounts receivable	$	3,169	$	—	$	—	$	3,169


		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 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, 2007 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: February 28, 2008	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.