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Article by DailyStocks_admin    (08-04-08 10:21 AM)

Filed with the SEC from July 24 to July 30:

Bronco Drilling (BRNC)
Wexford Capital opposes the proposed acquisition of the oil and natural-gas drill-rig supplier by Allis-Chalmers Energy (ALY). Wexford believes the deal isn't in the best interests of Bronco shareholders. Under the terms of the agreement, Bronco stockholders will receive $200 million in cash and 16.85 million shares of Allis-Chalmers common stock. The combined consideration values Bronco's shares at $18.25, based on the closing price of Allis-Chalmers' common on May 30. (Allis-Chalmers provides oil and natural-gas services, as well as equipment.)
Wexford may communicate further with Bronco about the merger and may seek representation on the board. It would like to work with management on strategies to increase shareholder value. Wexford owns 3.37 million shares (12.85% of the total outstanding).
BUSINESS OVERVIEW

Our Company

We provide contract land drilling and workover services to oil and natural gas exploration and production companies. As of February 29, 2008, we owned a fleet of 56 land drilling rigs, of which 45 were marketed and 11 were held in inventory. We also owned a fleet of 59 workover rigs, of which 49 were operating and ten were in the process of being manufactured. As of February 29, 2008, we also owned a fleet of 70 trucks used to transport our rigs.

We commenced operations in 2001 with the purchase of one stacked 650-horsepower drilling rig that we refurbished and deployed. We subsequently made selective acquisitions of both operational and inventoried drilling rigs, as well as ancillary equipment. Our management team has significant experience not only with acquiring rigs, but also with refurbishing and deploying inventoried rigs. We have successfully refurbished and brought into operation 25 inventoried drilling rigs during the period from November 2003 through December 2007. In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to refurbish and repair our rigs and equipment in-house. This facility, which complements our three drilling rig refurbishment yards, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays in our rig refurbishment program.

We currently operate our drilling rigs in Oklahoma, Texas, Colorado, Montana, Utah and Louisiana. Our workover rigs are currently operating in Oklahoma, Texas, Kansas, Colorado and New Mexico. A majority of the wells we have drilled for our customers have been drilled in search of natural gas reserves. Natural gas is often found in deep and complex geologic formations that generally require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 56 rigs includes 36 rigs ranging from 950 to 2,500 horsepower. Accordingly, such rigs can, or in the case of inventoried rigs upon refurbishment, will be able to, reach the depths required to explore for deep natural gas reserves. Our higher horsepower land drilling rigs can also drill horizontal wells, which are increasing as a percentage of total wells drilled in North America. We believe our premium rig fleet, inventory and experienced crews position us to benefit from the natural gas drilling activity in our core operating areas.

On January 23, 2008, we entered into a merger agreement with Allis-Chalmers Energy Inc., which we refer to as Allis-Chalmers, providing for the acquisition of us by Allis-Chalmers. Pursuant to the merger agreement, we and Allis-Chalmers agreed that, subject to the satisfaction of several closing conditions (including approval by each company’s stockholders), Elway Merger Sub, Inc., a wholly-owned subsidiary of Allis-Chalmers, which we refer to as Merger Sub, would merge with and into Bronco, and Bronco would survive the merger as a subsidiary of Allis-Chalmers. The merger agreement was approved by our board of directors and by the respective boards of directors of Allis-Chalmers and Merger Sub.

The merger agreement provides that at the effective time of the merger, our stockholders will receive merger consideration with an aggregate value of approximately $437.8 million, comprised of (1) $280.0 million in cash and (2) Allis-Chalmers common stock valued at approximately $157.8 million. The number of shares of Allis-Chalmers common stock that will be issued for each share of our common stock will be calculated based on an exchange ratio that will be determined by dividing (1) the quotient obtained by dividing $157,836,000 by the average of the closing sale prices of Allis-Chalmers common stock on the NYSE Composite Transactions Tape for each of the ten consecutive trading days ending with the second complete trading day prior to the merger closing date by (2) the aggregate number of shares of our common stock issued and outstanding immediately prior to the effective time of the merger. The affirmative vote of a majority of the votes cast on this matter is required to consummate the merger. For more information regarding the merger, please refer to the joint proxy statement/prospectus of Allis-Chalmers and Bronco that is included in the registration statement on Form S-4 (Registration No. 333-149326) filed by Allis-Chalmers with the Securities and Exchange Commission, or the SEC, on February 20, 2008, and other relevant materials that may be filed by us or Allis-Chalmers with the SEC, including any amendments to such registration statement.

Our Acquisitions

In May 2002, we purchased seven drilling rigs ranging in size from 400 to 950 horsepower, associated spare parts and equipment, drill pipe, haul trucks and vehicles from Bison Drilling L.L.C. and Four Aces Drilling L.L.C. After accepting delivery of the rigs, we spent approximately $97,000 upgrading the rigs before placing six of them into service.

In August 2003, we purchased all of the outstanding stock of Elk Hill Drilling, Inc., or Elk Hill, and certain drilling rig structures and components from U.S. Rig & Equipment, Inc., an affiliate of Elk Hill. In these transactions, we acquired drilling rigs and inventoried structures and components which, with refurbishment and upgrades, could be used to assemble 22 drilling rigs. At the date of its acquisition, Elk Hill was an inactive corporation with no customers, employees, operations or operational drilling rigs. We began refurbishing the acquired rigs and have deployed seventeen of the rigs since November 2003.

In July 2005, we acquired all of the membership interests of Strata Drilling, L.L.C. and Strata Property, L.L.C., or together Strata. Included in the Strata acquisitions were two operating rigs, one rig that was refurbished, related structures, equipment and components and a 16 acre yard in Oklahoma City, Oklahoma used for equipment storage and refurbishment of inventoried rigs.

In September 2005, we acquired 18 trucks and related equipment through our acquisition of Hays Trucking, Inc., or Hays Trucking, for a purchase price consisting of $3.0 million in cash, which included the repayment of $1.9 million of debt owed by Hays Trucking, and 65,368 shares of our common stock.

In October 2005, we purchased 12 land drilling rigs from Eagle Drilling, L.L.C., or Eagle Drilling, for approximately $50.0 million plus approximately $500,000 of related transaction costs, and 13 land drilling rigs from Thomas Drilling Co. for approximately $68.0 million plus approximately $2.6 million of related transaction costs.
In January 2006, we purchased six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling L.L.C., or Big A, for $16.3 million in cash and 72,571 shares of our common stock.

On January 9, 2007, we completed the acquisition of 31 workover rigs, 24 of which were operating, from Eagle Well Service, Inc., or Eagle Well, and related subsidiaries for $2.6 million in cash, 1,070,390 shares of our common stock, and the assumption of certain liabilities. We subsequently deployed the remaining seven rigs periodically during the first nine months of 2007.

General

A drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventors and related equipment.

Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.

Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a drilling line, a traveling block and hook assembly and ancillary equipment that attaches to the rotating system, a mechanism known as the drawworks. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydromatic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.

The rotating equipment from top to bottom consists of a swivel, the kelly bushing, the kelly, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the swivel and the drill bit as the drill stem. The swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.

Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.
There are numerous factors that differentiate drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons.

Our Fleet of Drilling Rigs

Working Drilling Rigs

As of February 29, 2008, we had 45 marketed drilling rigs, ten of which were operating on term contracts ranging from one to two years. Thirty-five of these drilling rigs were operating on a well-to-well basis. Thirty-two of the forty-five drilling rigs have undergone significant refurbishment since October 2003 by us or the parties from which the rigs were purchased.

Drilling Rigs In Inventory

We currently have 11 drilling rigs held in inventory in our rig yards in Oklahoma. We define an inventoried rig as a rig that could be part of a refurbishment plan and assigned a start and delivery date given favorable market conditions. Given sufficient demand, we could refurbish and deploy our remaining rigs held in inventory on a periodic basis.

Other Equipment

As of February 29, 2008, we owned a fleet of 70 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves, downtime between rig moves and general wear and tear on our drilling rigs.

We believe that our operating drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs. Historically, we have relied on various oilfield service companies for major repair work and overhaul of our drilling equipment. In April 2005, we opened a 41,000 square foot machine shop in Oklahoma City, which allows us to refurbish and repair our rigs and equipment in-house. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.

In January 2007, we acquired 31 workover rigs, 24 of which were in service at the time of acquisition, and we subsequently deployed the remaining rigs periodically during the first nine months of 2007. We subsequently purchased 28 additional workover rigs during 2007.

Drilling Contracts

As a provider of contract land drilling services, our business and the profitability of our operations depend on the level of drilling activity by oil and natural gas exploration and production companies operating in the geographic markets where we operate. Our business has generally not been affected by seasonal fluctuations. The oil and natural gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. During periods of lower levels of drilling activity, price competition tends to increase and results in decreases in the profitability of daywork contracts. In this lower level drilling activity and competitive price environment, we may be more inclined to enter into footage contracts that expose us to greater risk of loss without commensurate increases in potential contract profitability.

We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork or footage basis. The contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice, usually on payment of an agreed fee.

Daywork Contracts . Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. 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 the out-of-pocket drilling costs and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.

Footage Contracts . Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. The risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. We manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly, and we maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a negative impact on our profitability.

Turnkey Contracts . Turnkey contracts typically provide for a drilling company to drill a well for a customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. The drilling company would provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. The drilling company may subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, a drilling company would not receive progress payments and would be paid by its customer only after it had performed the terms of the drilling contract in full.

Although we have not historically entered into any turnkey contracts, we may decide to enter into such arrangements in the future. The risks to a drilling company under a turnkey contract are substantially greater than on a well drilled on a daywork basis. This is primarily because under a turnkey contract the drilling company assumes most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel.

Customers and Marketing

We market our rigs to a number of customers. In 2007, we drilled wells for 67 different customers, compared to 80 customers in 2006, and 52 customers in 2005. The following table shows our customers that accounted for more than 5% of our total contract drilling revenue for each of our last three years.

We primarily market our drilling rigs through employee marketing representatives. These marketing representatives use personal contacts and industry periodicals and publications to determine which operators are planning to drill oil and natural gas wells in the near future in our market areas. Once we have been placed on the “bid list” for an operator, we will typically be given the opportunity to bid on most future wells for that operator in the areas in which we operate. Our rigs are typically contracted on a well-by-well basis.

From time to time we also enter into informal, nonbinding commitments with our customers to provide drilling rigs for future periods at specified rates plus fuel and mobilization charges, if applicable, and escalation provisions. This practice is customary in the contract land drilling services business during times of tightening rig supply.

Competition

We encounter substantial competition from other drilling contractors. Our primary market area is highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal competitors are Nabors Industries, Inc., Patterson-UTI Energy, Inc., Unit Corp. and Helmerich & Payne, Inc. We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:





the type and condition of each of the competing drilling rigs;





the mobility and efficiency of the rigs;





the quality of service and experience of the rig crews;





the offering of ancillary services; and





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

While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment and the experience of our rig crews to differentiate us from our competitors. This strategy is less effective as lower demand for drilling services or an oversupply of rigs usually results in increased price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an oversupply of rigs can cause greater price competition.

Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of drilling rigs from other regions could rapidly intensify competition and reduce profitability.

Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:





better withstand industry downturns;





compete more effectively on the basis of price and technology;





better retain skilled rig personnel; and





build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Raw Materials

The materials and supplies we use in our operations include fuels to operate our drilling equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand.

Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

CEO BACKGROUND

Mike Liddell has served as the Chairman of the Board and a director of our company since May 2005. Mr. Liddell has served as a director of Gulfport Energy Corporation, a publicly held oil and natural gas corporation, since July 1997, as its Chairman of the Board since July 1998, as its Chief Executive Officer from April 1998 to December 2005, and as its President from July 2000 to December 2005. Mr. Liddell served as Chief Executive Officer of DLB Oil & Gas, Inc., a publicly held oil and natural gas company, from October 1994 to April 1998, and as a director of DLB Oil & Gas from 1991 through April 1998. From 1991 to 1994, Mr. Liddell was President of DLB Oil & Gas. From 1979 to 1991, he was President and Chief Executive Officer of DLB Energy. Mr. Liddell received a Bachelor of Science degree in Education from Oklahoma State University.

D. Frank Harrison has served as Chief Executive Officer and a director of our company since May 2005 and as President since August 2005. Mr. Harrison served as President of Harding & Shelton, Inc., a privately held oil and natural gas exploration, drilling and development firm, from 1999 to 2002. From 2002 to 2005, Mr. Harrison served as an agent for the purchase and sale of oil and gas properties for entities controlled by Wexford Capital LLC. He graduated from Oklahoma State University with a Bachelor of Science degree in Sociology.

David L. Houston has served as a director of our company since May 2005. Since 1991, Mr. Houston has been the principal financial advisor of Houston Financial, a firm that offers life and disability insurance, compensation and benefits plans and estate planning. He currently serves on the board of directors of Gulfport Energy Corporation and the board of directors and executive committee of Deaconess Hospital, located in Oklahoma City, Oklahoma. Mr. Houston is the former chair of the Oklahoma State Ethics Commission and the Oklahoma League of Savings Institutions. Prior to 1991, Mr. Houston was President and Chief Executive Officer of Equity Bank for Savings, F.A., an Oklahoma-based savings bank. He received a Bachelor of Science degree in Business from Oklahoma State University and a graduate degree in Banking from Louisiana State University.

Gary C. Hill has served as a director of our company since August 2006. Dr. Hill has served as the Chief of Surgery Service and Chief of Staff at Edmond Medical Center. He also has served as the President of the Edmond Medical Center Hospital Board. Dr. Hill served as the Chief of Surgery Service and Chief of Staff at St. Joseph’s Regional Hospital in Ponca City, Oklahoma. Dr. Hill is a graduate of Oklahoma State University, where he received his Bachelor of Arts in Humanities, and the University of Oklahoma Health Sciences Center. He served both his Surgery Internship and Residency in Otolaryngology, Head and Neck Surgery at the University of Texas Health Science Center, Parkland Hospital in Dallas before performing his Plastic and Reconstructive Surgery Residency at the University of Kansas Health Sciences Center in Kansas City. Dr. Hill is a native of Altus, Oklahoma.

William R. Snipes has served as a director of our company since February 2006. Mr. Snipes has served as the owner and President of Snipes Insurance Agency, Inc., an independent insurance agency concentrating in property and liability insurance, since 1991. From 1981 to 1991, Mr. Snipes was the owner and President of William R. Snipes, CPA, Inc., a public accounting firm concentrating in financial accounting and tax services. He received a Bachelor of Science degree and a Masters degree in Accounting from Oklahoma State University and is a licensed Certified Public Accountant.

COMPENSATION

Role of Executive Officers
In 2006, our board of directors made all compensation decisions for our Chief Executive Officer and, after receiving input from the Chief Executive Officer, all other named executive officers of the Company. The board of directors reviewed the performance of our Chief Executive Officer, and following such review, set the compensation of our Chief Executive Officer. The board of directors, together with our Chief Executive Officer, reviewed the performance of our other named executive officers, and our Chief Executive Officer made compensation recommendations to the board of directors with respect to our other named executive officers. No other executive officers were present at the time of such discussions. The board considered such recommendations when making its final compensation decision for all named executive officers other than our Chief Executive Officer. Effective as of March 25, 2007, the Committee became responsible for compensation decisions for our Chief Executive Officer and all other named executive officers.
Base Salary
The base salaries of our named executive officers have been reviewed annually by the board and, with respect to future salary determinations, will be reviewed by the Committee on an annual basis. The board considered various factors, including with regard to the position of the named executive officer, the compensation of executive officers of comparable companies within the oil and natural gas industry, the performance of such executive officer, increases in responsibilities and recommendations of our Chief Executive Officer with respect to base salaries of other named executive officers.
Based on the considerations described above, in August 2006, our board of directors established the annual base salary for our Chief Executive Officer and our Chief Financial Officer at $450,000 and $200,000, respectively, as set forth in their respective employment agreements discussed in more detail below. The annual base salary may be increased, but not decreased, at the discretion of the board of directors or the Committee. Salaries for our other named executive officers in 2006 are set forth in the 2006 Summary Compensation Table and were determined based on the considerations described above.
Bonus
Under the terms of his employment agreement, our Chief Executive Officer is eligible to receive an annual bonus in an amount not less than 66.7% of his annual base salary. Our board of directors determined to pay such bonus to our Chief Executive Officer, so that the aggregate cash component of his compensation, consisting of his base salary and bonus, will be comparable to similarly situated executives of our competitors. In 2006, our other named executive officers were eligible to receive an annual bonus if recommended by the Chief Executive Officer and approved by our board of directors in its discretion. Our Chief Executive Officer, Chief Financial Officer and Senior Vice President of Rig Operations received bonuses of $387,500, $210,000 and $167,565, respectively. These bonuses were awarded by the board of directors and were based on various factors, including our profitability, growth, market share and safety record achieved in 2006. Our Chief Executive Officer and Chief Financial Officer were paid a portion of their bonus in January 2007 $187,500 and $100,000, respectively. Our former Chief Operating Officer received a bonus of $40,000 in 2006 prior to his resignation pursuant to his employment agreement. Further details regarding 2006 bonuses for our Chief Executive Officer and other named executive officers are set forth in the 2006 Summary Compensation Table below.
Long-Term Incentive Compensation
2006 Awards. In 2006, our board of directors made a restricted stock award to our Chief Executive Officer and option awards to other named executive officers, in each instance under our stockholder-approved stock incentive plan described in more detail under the heading “2006 Stock Incentive Plan.” The purpose of these equity incentives is to encourage stock ownership, offer long-term performance incentive and to more closely align the executive’s compensation with the return received by the Company’s stockholders. Our Chief Executive Officer received an award of 66,667 shares of restricted stock in August 2006. The restrictions related to the shares awarded our Chief Executive Officer will lapse in six approximately equal semi-annual installments beginning on the date of grant. The options awarded to our Senior Vice President of Rig Operations, our former Chief Operating Officer and our Chief Financial Officer ranged from 40,000 shares to 100,000 shares and were awarded in March 2006. Stock options have an exercise price equal to 100% of the fair market value of the Company’s Common Stock on the date of grant and vest in 36 equal monthly installments. The stock options awarded to our former Chief Operating Officer were subsequently forfeited following his resignation in August of 2006. For additional information about the material terms of these awards, see the narrative disclosure under the heading “2006 Grants of Plan-Based Awards.”
2007 Awards . In February 2007, the board approved restricted stock awards of 25,000 shares to each of our Chief Financial Officer and Senior Vice President of Rig Operations under our 2006 Stock Incentive Plan described in more detail below. These shares of restricted stock vest in three equal annual installments beginning on January 1, 2008. These awards were made in the discretion of our board of directors to help incentivize these executive officers. Future grants of equity awards to our executive officers will be made in the discretion of the Committee.
Long-Term Incentive Policy. Although in the past, we awarded both options and restricted stock as part of our long-term incentive compensation program, our board of directors and the Committee believe that restricted stock awards are an essential component of our compensation strategy, and we intend to continue offering such awards in the future. Further, we anticipate that any equity awards granted to our executive officers during the remainder of 2007 will be in the form of restricted stock. The Committee may also determine to issue other forms of stock-based awards to our named executive officers or other eligible participants under our 2006 Stock Incentive Plan or other equity incentive plans in effect at that time. Our current equity incentive plans are described below under the headings “2006 Stock Incentive Plan” and “2005 Stock Incentive Plan.”
Offer to Exchange Options for Restricted Stock Awards. As a company, we are committed to director, employee and consultant ownership of our capital stock because it helps us attract and retain highly qualified directors, employees and consultants. In light of the foregoing, our board of directors has authorized, and on April 20, 2007, we commenced, an offer to exchange options granted on or after August 16, 2005 to purchase shares of our common stock that are outstanding under our 2005 Stock Incentive Plan and our 2006 Stock Incentive Plan and held by certain of our directors, employees, including our named executive officers, and consultants for restricted stock awards consisting of the right to receive restricted common stock upon the terms and subject to the conditions of the exchange offer and the related letter to eligible holders. Certain specified directors and employees (William Snipes, Gary Hill, Spence Hummel and Tim Sanders) are not eligible to participate in this particular offer, but each is expected to be afforded the opportunity to make a private exchange of stock options for restricted stock on terms not yet determined. The purpose of the exchange is to provide an incentive to eligible holders, including our directors and named executive officers, for their continued efforts and dedication. Although we are not required to make the exchange offer, we believe that eligible holders’ options no longer provide the incentives originally intended. Many of such holders have stock options with exercise prices significantly above our current and recent trading prices. This exchange program is being offered on a voluntary basis to allow eligible holders, including our directors and named executive officers, to choose whether to keep their eligible options at their current exercise prices, or to exchange those options for restricted stock awards.

Under the terms of the exchange offer, one restricted stock award will be granted for every two shares of common stock underlying the eligible options that are accepted for exchange and cancelled. Each restricted stock award granted will give the holder thereof the right to receive one share of restricted common stock, subject to certain vesting requirements. Until restricted stock awards have vested, they remain subject to restrictions on transfer and to forfeiture if the employment or service, as may be applicable, terminates.
If the exchange offer is consummated, the restricted shares of our common stock underlying the restricted stock awards will vest in equal amounts on January 1, 2008 and January 1, 2009, subject to earlier vesting or forfeiture in certain circumstances. Vesting will only occur, however, if the eligible holder remains a director, employee or consultant of ours or one of our affiliates through the respective vesting dates. Even if the eligible options subject to the exchange offer are partially-vested or fully-vested, the restricted stock awards to be received upon the completion of the exchange offer will not be vested and will be subject to the new vesting period.
If there is a change of control of the Company as defined in our 2006 Stock Incentive Plan following the completion of the exchange offer, the vesting for any restricted shares that have not yet vested will be accelerated to immediately prior to the date of the change of control, provided the eligible holder has remained a director, employee or consultant of ours or one of our affiliates through the date of such change of control.
We have the right to terminate, amend or postpone the exchange offer, or extend the period of time during which such offer is open, in each instance prior to the expiration date of such exchange offer and subject to the rules promulgated under the Exchange Act.
We are not making the offer to, and we will not accept any tender of options from or on behalf of, employees in any jurisdiction in which the offer or the acceptance of any tender of options would not be in compliance with the laws of that jurisdiction. However, we may, at our discretion, take any actions necessary for us to make the offer to employees in any of these jurisdictions.

MANAGEMENT DISCUSSION FROM LATEST 10K

Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Contract Drilling Revenue. For the year ended December 31, 2007, we reported contract drilling revenues of approximately $276.1 million, a 3% decrease from revenues of $285.8 million for 2006. The decrease is primarily due to a decrease in total revenue days partially offset by increases in average dayrates and average number of drilling rigs working for the year ended December 31, 2007 as compared to 2006. Revenue days decreased 6% to 14,245 days for the year ended December 31, 2007 from 15,202 days during 2006. Average dayrates for our drilling services increased $491, or 3%, to $17,876 for the year ended December 31, 2007 from $17,385 in 2006. Our average number of operating drilling rigs increased to 51 from 45, or 13%, for the year ended December 31, 2007, as compared to 2006. The decrease in the number of revenue days for the year ended December 31, 2007 as compared to 2006 is attributable to the decrease in our utilization rate partially offset by the increase in the size of our operating drilling rig fleet. Utilization decreased to 76% from 93% for the year ended December 31, 2007 as compared to 2006. The 18% decrease in utilization was primarily due to a more competitive market resulting from an increase in the supply of drilling rigs.

Well Service Revenue. For the year ended December 31, 2007, we reported well service revenues of approximately $22.9 million, revenue hours of 63,746 and an average hourly rate of $356. Our average number of operating workover rigs was 33 for the year ended December 31, 2007. There were no well service revenues for the year ended December 31, 2006.

Contract Drilling Expense. Contract drilling expense increased $14.2 million to $153.8 million for the year ended December 31, 2007 from $139.6 million in 2006. This 10% increase is primarily due to the increase in the average number of operating drilling rigs in our fleet to 51 for the year ended December 31, 2007 as compared to 45 in 2006 as well as a broad increase in the cost of materials and supplies used to operate our drilling rigs. As a percentage of contract drilling revenue, drilling expense increased to 56% for the year ended December 31, 2007 from 49% in 2006 due primarily to expenses related to the retention of crews of idle drilling rigs.

Well Service Expense. Well service expense was approximately $14.3 million for the year ended December 31, 2007. As a percentage of well service revenue, well service expense was 63% for the year ended December 31, 2007. There were no well service expenses for the year ended December 31, 2006.

Depreciation and Amortization Expense. Depreciation and amortization expense increased $13.9 million to $44.2 million for the year ended December 31, 2007 from $30.3 million in 2006. The increase is primarily due to the 30% increase in fixed assets, including the substantial completion of three additional rigs from our inventory during 2007, the Eagle Well Service acquisition, as well as incremental increases in ancillary equipment.

General and Administrative Expense. General and administrative expense increased $7.0 million, or 44%, to $22.7 million for the year ended December 31, 2007 from $15.7 million in 2006. This primarily resulted from a $4.2 million increase in accounts receivable write-offs, a $1.4 million increase in payroll costs, a $959,000 increase in stock compensation expense, a $502,000 increase in yard expense, and a $388,000 increase in rent expense. These increases were partially offset by a decrease in severance expense of $565,000. The increase in bad debt expense is due to the identification of additional accounts receivable deemed uncollectible.

The increase in payroll costs is due to our increased administrative employee count and related wage increases during 2007. The increase in stock compensation expense is attributed to grants of restricted stock during 2007. The increases in yard and rent expense are due to additional locations added in 2007. The decrease in severance expense of $565,000 is due to one-time payments made to our former Chief Operating Officer, Karl Benzer, upon termination of his employment in 2006.

Interest Expense. Interest expense increased $3.1 million to $4.8 million for the year ended December 31, 2007 from $1.7 million in 2006. The increase is due to an increase in the average debt outstanding for the year and a decrease in the capitalization of interest expense related to our rig refurbishment program. We capitalized $1.7 million of interest for the year ended December 31, 2007 as compared to $3.6 million for the same period in 2006 as part of our rig refurbishment program. We also made an adjustment in the fourth quarter to accrue for use tax liabilities, which included interest expense in the amount of $634.

Income Tax Expense . We recorded an income tax expense of $23.1 million for the year ended December 31, 2007. This compares to an income tax expense of $38.1 million in 2006. This decrease is primarily due to a $37.2 million decrease in pre-tax income to $60.7 million for the year ended December 31, 2007 from $97.9 million in 2006.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Contract Drilling Revenue. For the year ended December 31, 2006, we reported contract drilling revenues of approximately $285.8 million, a 267% increase from revenues of $77.9 million for 2005. The increase is primarily due to increases in dayrates, revenue days and average number of rigs working for the year ended December 31, 2006 as compared to 2005. Average dayrates for our drilling services increased $3,932, or 29%, to $17,385 for the year ended December 31, 2006 from $13,453 in 2005. Revenue days increased 163% to 15,202 days for the year ended December 31, 2006 from 5,781 days during 2005. Our average number of operating rigs increased to 45 from 17, or 165%, for the year ended December 31, 2006 as compared to 2005. The increase in the number of revenue days for the year ended December 31, 2006 as compared to 2005 is attributable to the increase in the size of our operating rig fleet. These increases were partially offset by a slight decrease in utilization to 93% from 95% for the year ended December 31, 2006 as compared to 2005 .

Contract Drilling Expense. Contract drilling expense increased $94.9 million to $139.6 million for the year ended
December 31, 2006 from $44.7 million in 2005. This 212% increase is primarily due to the increases in revenue days and average number of operating rigs in our fleet for the year ended December 31, 2006 as compared to 2005. As a percentage of contract drilling revenue, drilling expense decreased to 49% for the year ended December 31, 2006 from 57% in 2005 due primarily to an escalation in dayrates.

Depreciation and Amortization Expense. Depreciation and amortization expense increased $21.2 million to $30.3 million for the year ended December 31, 2006 from $9.1 million in 2005. The increase is primarily due to the 60% increase in fixed assets, including the substantial completion of 12 additional rigs from our inventory during 2006, the Big A acquisition and a full year of depreciation and amortization expense associated with the Strata, Eagle, and Thomas acquisitions.

General and Administrative Expense. General and administrative expense increased $6.3 million, or 67%, to $15.7 million for the year ended December 31, 2006 from $9.4 million in 2005. This primarily resulted from a $2.2 million increase in stock compensation expense, a $1.6 million increase in yard expense, an increase of $565,000 in severance expense, an increase of $493,000 in professional fees, an increase in franchise taxes of $349,000, a $286,000 increase in rent expense and an increase in filing fees of $148,000. These increases were partially offset by a decrease in payroll costs of $620,000 and a decrease in administrative reimbursement costs of $245,000. The increase in stock compensation expense is attributable to additional grants of options and restricted stock during 2006 and a full year of expense related to grants awarded in 2005. The increases in yard and rent expense are due to additional locations in 2006. The increase in severance expense to $565,000 for the year ended December 31, 2006 from $0 for the year ended December 31, 2005 is due to payments made to our former Chief Operating Officer, Karl Benzer, upon termination of his employment in 2006. The increase in professional fees to $1.1 million for the year ended December 31, 2006 from $619,000 in 2005 is due to an increase in accounting and legal expense. The increase in franchise taxes is due to taxes paid to the state of Delaware where we were incorporated upon completion of our initial public offering. The increase in filing fees is due to costs of being a public company. The decrease in payroll costs to $5.2 million for the year ended December 31, 2006 from $5.8 million in 2005 is primarily due to payments made in 2005 by Bronco Drilling Holdings, L.L.C. to our former President and Chief Operating Officer, Steve Hale, following successful completion of our initial public offering. Although we did not make the payment, we were required to account for these payments as a capital contribution to us in the amount of $4.0 million and compensation expense of $4.0 million. The remaining increase in payroll costs is due to our increased employee count and related wage increases during 2005. The decrease in administrative reimbursement to $54,000 for the year ended December 31, 2006 from $299,000 in 2005 is due to the termination of our administrative services agreement with Gulfport Energy Corporation, or Gulfport, effective April 1, 2006.

Interest Expense. Interest expense increased $300,000 to $1.7 million for the year ended December 31, 2006 from $1.4 million in 2005. The increase is due to an increase in the average debt outstanding for the year, partially offset by the capitalization of interest expense related to our rig refurbishment program. We capitalized $3.6 million of interest for the year ended December 31, 2006 as compared to $1.2 million for the same period in 2005 as part of our rig refurbishment program.

Income Tax Expense . We recorded an income tax expense of $38.1 million for the year ended December 31, 2006. This compares to an income tax expense of $6.5 million in 2005. This increase is primarily due to an increase in pre−tax income of $86.2 million to $97.9 million for the year ended December 31, 2006 from $11.7 million in 2005, an increase in our effective tax rate and our conversion from a limited liability company to a taxable entity in August 2005 in connection with our initial public offering.

Liquidity and Capital Resources

Operating Activities . Net cash provided by operating activities was $82.6 million in 2007, $93.1 million in 2006 and $3.3 million in 2005. The decrease of $10.5 million from 2006 to 2007 was primarily due to a decrease in cash receipts from customers and higher cash payments to employees and suppliers. The increase of $89.8 million from 2005 to 2006 was primarily due to increased cash receipts from customers, partially offset by higher cash payments to employees and suppliers.

Investing Activities . We use a significant portion of our cash flows from operations and financing activities for acquisitions and for the refurbishment of our rigs. We used cash for investing activities of $80.0 million for 2007 as compared to approximately $143.2 million for 2006, and $190.3 million for 2005. In 2007, approximately $2.4 million was used for an acquisition made during 2007 and $82.8 million was used to purchase property and equipment, which amounts were partially offset by $5.1 million from the sale of assets. In 2006, approximately $17.0 million was used for acquisitions made during 2006 and related transaction costs, $130.5 million was used to purchase property and equipment and $416,000 was placed in a restricted account as security for a letter of credit issued to our workers’ compensation insurance carrier, which amounts were partially offset by $4.8 million from the sale of assets. In 2005, approximately $135.2 million was used for acquisitions made during 2005 and related transaction costs, $53.6 million was used to purchase property and equipment and $1.5 million was placed in a restricted account as security for a letter of credit issued to our workers’ compensation insurance carrier.

Financing Activities . Our cash flows used by financing activities were $7.5 million for 2007 as compared to $43.7 million provided by financing activities for 2006 and $202.9 million for 2005. Our net cash used for financing activities for 2007 related to principal payments on borrowings of $17.0 million to Fortis, $5.5 million to Bank of Beaver City and $2.0 million to other finance companies, partially offset by borrowings of $17.0 million under our credit agreement with Fortis. Our net cash provided by financing activities for 2006 related to net proceeds of approximately $36.2 million from our public offering, borrowings of $44.0 million under our credit agreement with Fortis, partially offset by principal payments on borrowings of $34.9 million to Fortis. Our net cash provided by financing activities for 2005 related to net proceeds of approximately $176.0 million from our initial and follow-on public offerings, borrowings of $43.0 million under our credit agreement with Merrill Lynch, borrowings of $68.0 million from Solitair LLC, Theta Investors LLC and Alpha Investors LLC, entities controlled by Wexford Capital LLC, or Wexford, borrowings of $7.5 million from GECC, and borrowings of $1.2 million from International Bank of Commerce, partially offset by principal payments on borrowings of $23.8 million to GECC, $68.0 million to Solitair LLC and Alpha Investors LLC, and capital contributions of $1.5 million from entities controlled by Wexford.

Sources of Liquidity . Our primary sources of liquidity are cash from operations and borrowings under our credit facilities and equity financing.

Debt Financing . On December 26, 2003, we entered into a credit facility with GECC which provided for term loan advances of up to $12.0 million. At September 24, 2004 and April 22, 2005, we amended our credit facility with GECC to increase the maximum amount of the terms loans to $18.0 million and then to $25.5 million, respectively. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0% and were secured by substantially all of our property and assets, including our drilling rigs and associated equipment, and ownership interests in our subsidiaries, but excluding cash and accounts receivable. Draws on the facility were required to be in $2.5 million increments each with a five-year term. Payments of principal and accrued but unpaid interest were due on the first day of each month. This credit facility, which was to mature on October 1, 2010, was repaid in full on August 29, 2005 with a portion of the proceeds from our initial public offering and the credit facility was terminated.

On July 1, 2004, we entered into a revolving line of credit with International Bank of Commerce with a borrowing base of the lesser of $2.0 million or 80% of current receivables. Borrowings under this line bore interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime (effective rate of 7.25% at December 31, 2005). Accrued but unpaid interest was payable monthly. On January 1, 2005, we amended our line of credit with International Bank of Commerce to increase the borrowing base to the lesser of $3.0 million or 80% of current receivables. The line of credit had a maturity date of November 1, 2006. It was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and then terminated.

On February 15, 2005, we entered into a $5.0 million revolving credit facility with Solitair LLC, an entity controlled by Wexford Capital LLC, which we refer to as Wexford. At the time, Wexford was our sole equity sponsor and controlled our company. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0%.

Payment of principal and accrued but unpaid interest were due on the maturity date of the credit facility which was the later of (1) six months after the actual maturity date of our credit facility with GECC and (2) December 1, 2010. We repaid this facility in full on August 22, 2005 with a portion of the proceeds from our initial public offering and the facility was terminated.

In July 2005, we acquired all of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with a $13.0 million loan from Alpha Investors LLC, an entity controlled by Wexford. The outstanding principal balance of the loan plus accrued but unpaid interest was due in full upon the earlier to occur of the completion of our initial public offering and the maturity of the loan on July 1, 2006. We repaid this loan in full on August 22, 2005 with a portion of the proceeds from our initial public offering. Borrowings under our loan with Alpha bore interest at a rate equal to LIBOR plus 5% until September 30, 2005, and thereafter were to bear interest at a rate equal to LIBOR plus 7.5%. The $7.0 million original aggregate principal balance of the promissory notes issued to the sellers was automatically reduced by the amount of any costs and expenses we paid in connection with the refurbishment of one of the rigs we acquired from the sellers. The amount due on these notes, net of costs and expenses paid by us, was $4.5 million at December 31, 2005. The outstanding balance of the loan was paid in full on January 5, 2006 upon completion of the refurbishment of this rig.

On September 19, 2005, we entered into a term loan and security agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. The term loan provided for a term installment loan in an aggregate amount not to exceed $50.0 million and provided for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan could not exceed 60% of the net orderly liquidation value of our operating land drilling rigs. On September 19, 2005, we borrowed $43.0 million under the term loan. A portion of these borrowings, together with proceeds from our initial public offering, were used to fund the Eagle acquisition. The term loan bore interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points (7.1% at December 31, 2005). For the period from September 19, 2005 to January 1, 2006, interest only was payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan were payable in sixty consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. The maturity date was January 1, 2011. Our obligations under the term loan were secured by a first lien and security interest on substantially all of our assets and were guaranteed by each of our principal subsidiaries. The term loan included usual and customary negative covenants and events of default for loan agreements of this type. The term loan also required us to meet certain financial covenants, including maintaining a minimum Fixed Charge Coverage Ratio and a maximum Total Debt to EBITDA Ratio. This term loan was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and the term loan was terminated.

On October 14, 2005, we entered into a loan agreement with Theta Investors, LLC, an entity controlled by Wexford, for purposes of funding a portion of the purchase price for the Thomas acquisition. The Theta loan provided maximum aggregate borrowings of up to $60.0 million, which borrowings bore interest at a rate equal to LIBOR plus 400 basis points until December 15, 2005 and, thereafter, at a rate equal to LIBOR plus 600 basis points. Payment of principal and accrued but unpaid interest was due on October 15, 2006. Our obligations under the Theta loan were guaranteed by each of our principal subsidiaries. We borrowed $50.0 million under this loan on October 14, 2005. We repaid this facility in full on November 3, 2005 with a portion of the proceeds from our follow-on public offering, which closed November 2, 2005.

On January 13, 2006, we entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. The initial aggregate revolving commitment of $150.0 million is automatically and permanently reduced by $10.0 million at the end of each fiscal quarter starting September 30, 2006. The aggregate revolving commitment was $90.0 million as of December 31, 2007. Loans under the revolving credit facility bear interest at LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to “Adjusted EBITDA,” as defined in the credit agreement. Our borrowings under this revolving credit facility were used to fund a portion of the Big A acquisition and to repay in full all outstanding borrowings under our term loan with Merrill Lynch Capital and our revolving line of credit with International Bank of Commerce.

The revolving credit facility also provides for a quarterly commitment fee of 0.5% per annum of the unused portion of the revolving credit facility, and fees for each letter of credit issued under the facility. Commitment fees expense for the years ended December 31, 2007 and 2006 were $257,000 and $445,000, respectively. Our subsidiaries have guaranteed the loans and other obligations under the revolving credit facility. The obligations under the revolving credit facility and the related guarantees are secured by a first priority security interest in substantially all of our assets, as well as the shares of capital stock of our direct and indirect subsidiaries.

The revolving credit facility contains customary covenants for facilities of this type, including among other things, covenants that restrict our ability to make capital expenditures, incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions. The financial covenants are a minimum fixed charge coverage ratio of 1.75 to 1.00 and a maximum total leverage ratio of 2.00 to 1.00. We were in compliance with all covenants at December 31, 2007. The revolving credit facility provides for mandatory prepayments under certain circumstances as more fully discussed in the revolving credit facility. The revolving credit facility contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations, default under certain other agreements, bankruptcy or insolvency, the occurrence of specified ERISA events, entry of enforceable judgments against us in excess of $3.0 million not stayed, and the occurrence of a change of control. If an event of default occurs, all commitments under the revolving credit facility may be terminated and all of our obligations under the revolving credit facility could be accelerated by the lenders, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

We are party to term installment loans for an aggregate principal amount of approximately $6.0 million. These term loans are payable in 96 monthly installments, mature in 2013 and 2015 and have a weighted average annual interest rate of 6.93%. The proceeds from these term loans were used to purchase cranes.

We are party to a term loan agreement with Ameritas Life Insurance Corp. for an aggregate principal amount of approximately $1.6 million related to the acquisition of a building. This term loan is payable in 166 monthly installments, matures in 2021 and has an interest rate of 6%.

Issuances of Equity.

In connection with our acquisitions of Big A in January 2006 and Eagle Well in January 2007, we issued 72,571, and 1,070,390 shares of our common stock, respectively. See “—Capital Expenditures” below.

I n March 2006, we closed a public offering of 3,450,000 shares of our common stock at a price of $22.75 per share. In the offering, a total of 1,700,000 shares were sold by us and 1,750,000 shares were sold by the selling stockholder. The offering resulted in net proceeds to us of approximately $36.2 million, excluding offering expenses of $577,000. We did not receive any proceeds from the sale of shares by the selling stockholder.

Capital Expenditures.

During 2007 we substantially completed the refurbishment of three rigs, ranging from 1,200 to 1,500 horsepower. We incurred aggregate refurbishment costs of $23.5 million, ranging from $7.0 million to $8.5 million per rig, which were funded with borrowings under our revolving credit facility with Fortis Capital Corp. and cash flow from operations.

On January 2, 2007, we purchased an approximately 18,100 square foot building located in Edmond, Oklahoma for cash of $1.4 million and the assumption of existing debt of approximately $1.6 million, less one-half of the principal reduction on the sellers’ loan secured by the property between the effective date and closing. Prior to closing on the building we subleased a total of 9,050 square feet of the building from its current tenants for a monthly rental of $8,341.

On January 9, 2007, we completed the acquisition of 31workover rigs, 24 of which were operating, from Eagle Well and related subsidiaries for $2.6 million in cash, 1,070,390 shares of our common stock and the assumption of debt of $6.5 million, liabilities of $678,000 and additional deferred income taxes of $7.2 million. We subsequently deployed the remaining rigs periodically during the first nine months of 2007.

During 2006, we substantially completed the refurbishment of 12 rigs ranging from 450 to 1,500 horsepower. We incurred aggregate refurbishment costs of $67.7 million, ranging from $544,000 to $7.9 million per rig, which were funded with borrowings under our various credit facilities, public offerings, and cash flows from operations.

In January 2006, the refurbishment of a 1,000-horsepower mechanical rig was completed pursuant to a $7.0 million seller’s note incurred in the Strata acquisition. We designated this Rig No. 43 and repaid the note with proceeds from our November 2005 follow-on offering.

On January 18, 2006, we purchased six operating rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A. The purchase price for the assets consisted of $16.3 million paid in cash and 72,571 shares of our common stock.

In October 2006, we purchased a 1,000-horsepower electric drilling rig, which we designated Rig No. 37. We paid approximately $7.4 million for this rig.

During 2005, we completed the refurbishment of six rigs, ranging from 950 to 2,500 horsepower. We incurred aggregate refurbishment costs of $34.3 million, ranging from $4.5 million to $6.6 million per rig, which were funded with borrowings under our various credit facilities and proceeds from our initial public offering and follow-on offering.

We believe that cash flow from our operations and borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next twelve months. However, additional capital may be required for future rig acquisitions. While we would expect to fund such acquisitions with additional borrowings and the issuance of debt and equity securities, we cannot assure you that such funding will be available or, if available, that it will be on terms acceptable to us .

Contractual and Commercial Commitments

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements.

Recent Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, or SFAS 157, “ Fair Value Measurements .” This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. This Statement is effective for fiscal years beginning after November 15, 2007, however, on February 12, 2008, the FASB issued FSP FAS No. 157-2, Effective Dates of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. We do not expect the adoption of SFAS 157 to have a material impact on our financial position or results of operation and financial condition.

In February 2007, the FASB issued SFAS No. 159, or SFAS 159, “ The Fair Value Option for Financial Assets and Financial Liabilities−−Including an amendment of FASB Statement No. 115 .” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be recognized in earnings at each subsequent reporting date. SFAS No. 159 is effective for fiscal years beginning January 1, 2008. We do not expect the adoption of SFAS 159 to have a material impact on our financial position or results of operations and financial condition.

In December 2007, the FASB issued SFAS 141 (revised 2007) “ Business Combinations ”, or SFAS 141R. SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree. SFAS 141R also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We are currently evaluating the potential impact, if any, of the adoption of SFAS 141R on our consolidated financial statements.

In December 2007, the FASB issued SFAS 160, or SFAS 160, “ Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. ” SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 shall be applied prospectively. We are currently evaluating the potential impact of the adoption of SFAS 160 on our consolidated financial statements.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Contract Drilling Revenue. For the three months ended March 31, 2008, we reported contract drilling revenues of $54.1 million, a 27% decrease from revenues of $74.5 million for the same period in 2007. The decrease is primarily due to a decrease in dayrates, revenue days and average number of rigs working for the three months ended March 31, 2008 as compared to the same period in 2007. Average dayrates for our drilling services decreased $1,648, or 9%, to $17,101 for the three months ended March 31, 2008 from $18,749 in the same period in 2007. Revenue days decreased 22% to 2,848 days for the three months ended March 31, 2008 from 3,631 days during the same period in 2007. Our average number of operating rigs decreased to 45 from 51, or 12%, for the three months ended March 31, 2008 as compared to the same period in 2007. The decrease in the number of revenue days and size of our operating rig fleet for the three months ended March 31, 2008 as compared to the same period in 2007 is primarily due to the sale and contribution of rigs to Challenger.

Well Service Revenue. For the three months ended March 31, 2008, we reported well service revenues of approximately $8.2 million, a 87% increase from revenues of $4.4 million for the same period in 2007. The increase is primarily due to an increase in revenue hours and average number of operating workover rigs for the three months ended March 31, 2008 as compared to the same period in 2007. Revenue hours increased 98% to 23,865 hours for the three months ended March 31, 2008 from 12,047 hours during the same period in 2007. Our average number of operating workover rigs increased to 48 from 24, or 100%, for the three months ended March 31, 2008 as compared to the same period in 2007. The increase in revenue hours and size of our operating workover rig fleet is due to additional workover rigs purchased during 2007.

Contract Drilling Expense. Direct rig cost decreased $7.6 million to $33.2 million for the three months ended March 31, 2008 from $40.8 million for the same period in 2007. This 19% decrease is primarily due to the decrease in revenue days and the decrease in average number of operating rigs in our fleet for the three months ended March 31, 2008 as compared to the same period in 2007. As a percentage of contract drilling revenue, drilling expense increased to 62% for the three-month period ended March 31, 2008 from 55% for the same period in 2007 due primarily to expenses related to the retention of crews on idle or underutilized rigs.

Well Service Expense. Well service expense increased $2.3 million to $4.9 million for the three months ended March 31, 2008 from $2.6 million for the same period in 2007. This 87% increase is primarily due to the increase in revenue hours and the average number of operating workover rigs in our fleet for the three months ended March 31, 2008 as compared to the same period in 2007.

Depreciation Expense. Depreciation expense increased $720,000 to $11.9 million for the three months ended March 31, 2008 from $11.2 million for the same period in 2007. The increase is primarily due to the 4% increase in fixed assets.

General and Administrative Expense . General and administrative expense increased $1.0 million to $5.7 million for the three months ended March 31, 2008 from $4.7 million for the same period in 2007. The increase is the result of an increase in payroll costs of $591,000, an increase in stock compensation expense of $427,000 and an increase in professional fees expense of $93,000. The increase in payroll costs is primarily due to our increased administrative employee count and related wage increases. The increase in stock compensation expense is attributed to grants of restricted stock during 2007 and the three months ended March 31, 2008. These increases were partially offset by a decrease in yard expense of $286,000. The decrease in yard expense is primarily due to decreased activity in the yards as a result of the slowdown of our rig refurbishment program.

Interest Expense . Interest expense decreased $42,000 to $1.2 million for the three months ended March 31, 2008 from $1.3 million for the same period in 2007. The decrease is due to a decrease in the average interest rate on our revolving credit facility, partially offset by a decrease in the capitalization of interest expense related to our rig refurbishment program. We capitalized $382,000 of interest for the three months ended March 31, 2008 as compared to $454,000 for the same period in 2007.

Tax Expense (Benefit) . We recorded a tax expense of $4.6 million for the three months ended March 31, 2008 all of which was deferred tax expense. This compares to a deferred tax expense of $4.4 million for the three months ended March 31, 2007. This increase is due to the deferral of the gain recognized on the rigs contributed to Challenger, partially offset by a decrease in pre-tax income.

Liquidity and Capital Resources

Operating Activities . Net cash provided by operating activities was $14.9 million for the three months ended March 31, 2008 as compared to $15.2 million in 2007. The decrease of $295,000 from 2007 to 2008 was primarily due to a decrease in cash receipts from customers, partially offset by lower cash payments to suppliers.

Investing Activities . We use a significant portion of our cash flows from operations and financing activities for acquisitions and the refurbishment of our rigs. Cash used in investing activities was $20.9 million for the three months ended March 31, 2008 as compared to $17.1 million for the same period in 2007. For the three months ended March 31, 2008, we used $18.5 million to purchase fixed assets and $5.1 million to purchase an equity interest in Challenger. These amounts were partially offset by $2.6 million of proceeds received from the sale of assets. For the three months ended March 31, 2007, we used $ 16.2 million to purchase fixed assets and $2.3 million to purchase Eagle Well Service, Inc, or Well Services. These amounts were partially offset by $1.4 million of proceeds received from the sale of assets.

Financing Activities . Our cash flows provided by financing activities were $3.3 million for the three months ended March 31, 2008 as compared to $6.8 million used in financing activities for the same period in 2007. For the three months ended March 31, 2008, our net cash provided by financing activities related to borrowings of $5.0 million under our credit facility with Fortis Capital Corp., partially offset by principal payments of $1.7 million to various lenders. Our net cash used in 2007 for financing activities related to principal payments of $14.8 million under our credit agreement with Fortis Capital Corp., partially offset by borrowings of $8.0 million under our credit facility with Fortis Capital Corp.

Sources of Liquidity . Our primary sources of liquidity are cash from operations and debt and equity financing.

Debt Financing . On January 13, 2006, we entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. The Company intends to refinance the revolving credit facility during 2008. The initial aggregate revolving commitment of $150.0 million is automatically and permanently reduced by $10.0 million at the end of each fiscal quarter starting September 30, 2006. The aggregate revolving commitment was $80.0 million as of March 31, 2008. Loans under the revolving credit facility bear interest at LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to “Adjusted EBITDA,” as defined in the credit agreement. Our borrowings under this revolving credit facility were used to fund a portion of our acquisition of drilling rigs and other assets from Big A Drilling Company, L.C. and to repay in full all outstanding borrowings under our term loan with Merrill Lynch Capital and our revolving line of credit with International Bank of Commerce.

The revolving credit facility also provides for a quarterly commitment fee of 0.5% per annum of the unused portion of the revolving credit facility, and fees for each letter of credit issued under the facility. Commitment fees expense for the three months ended March 31, 2008 and 2007 were $59,000 and $161,000, respectively. Our subsidiaries have guaranteed the loans and other obligations under the revolving credit facility. The obligations under the revolving credit facility and the related guarantees are secured by a first priority security interest in substantially all of our assets, as well as the shares of capital stock of our direct and indirect subsidiaries.

The revolving credit facility contains customary covenants for facilities of this type, including among other things, covenants that restrict our ability to make capital expenditures, incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions. The financial covenants are a minimum fixed charge coverage ratio of 1.75 to 1.00 and a maximum total leverage ratio of 2.00 to 1.00. We were in compliance with all covenants at March 31, 2008. The revolving credit facility provides for mandatory prepayments under certain circumstances. The revolving credit facility contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations, default under certain other agreements, bankruptcy or insolvency, the occurrence of specified ERISA events, entry of enforceable judgments against us in excess of $3.0 million not stayed, and the occurrence of a change of control. If an event of default occurs, all commitments under the revolving credit facility may be terminated and all of our obligations under the revolving credit facility could be accelerated by the lenders, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

We are party to term installment loans for an aggregate principal amount of approximately $4.5 million. These term loans are payable in 96 monthly installments, mature in 2013 and 2014 and have a weighted average annual interest rate of 6.92%. The proceeds from these term loans were used to purchase cranes.

We are party to a term loan agreement with Ameritas Life Insurance Corp. for an aggregate principal amount of approximately $1.6 million related to the acquisition of a building. This term loan is payable in 166 monthly installments, matures in 2021 and has an interest rate of 6%.

Issuances of Equity.

In connection with our acquisition of Well Services in January 2007, we issued 1,070,390 shares of our common stock.

Capital Expenditures.

We believe that cash flow from our operations and borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next 12 months. The Company intends to refinance its revolving credit facility during 2008 that matures on January 13, 2009. However, additional capital may be required for future acquisitions. While we would expect to fund such acquisitions with additional borrowings and the issuance of debt and equity securities, we cannot assure you that such funding will be available or, if available, that it will be on terms acceptable to us.

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