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Article by DailyStocks_admin    (04-16-08 03:31 AM)

Filed with the SEC from Apr 3 to Apr 9:

Bronco Drilling (BRNC)
Third Avenue Management sent a letter to the company stating its opposition to the proposed acquisition of Bronco by Allis-Chalmers Energy (ALY). Third Avenue said the proposed merger with Allis-Chalmers undervalues Bronco's common stock and is not in the best interest of Bronco's shareholders. In January, Allis-Chalmers, agreed to pay $280 million in cash and $158 million in stock for a combined price of $16.33 a share for Bronco Drilling. Third Avenue Management said it believes that Bronco's shareholders will do better continuing to own Bronco as a stand-alone company, particularly in light of the improving fundamentals in the natural gas drilling market in the U.S. Third Avenue holds 6,166451 shares (23.47%).

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



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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;



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compete more effectively on the basis of price and technology;



•

better retain skilled rig personnel; and



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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

Overview

We earn our contract drilling revenues by drilling oil and natural gas wells for our customers. 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. We have not historically entered into turnkey contracts and do not intend to enter into any turnkey contracts, subject to changes in market conditions, although it is possible that we may acquire such contracts in connection with future acquisitions. 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. Although, we currently have ten of our drilling rigs operating under agreements with initial terms ranging from one to two years, our contracts generally provide for the drilling of a single well and typically permit the customer to terminate on short notice.

A significant performance measurement in our industry is operating rig utilization. We compute operating drilling rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the operating rig. Revenue days for each operating rig are days when the rig is earning revenues under a contract, i.e. when the rig begins moving to the drilling location until the rig is released from the contract. On daywork contracts, during the mobilization period we typically receive a fixed amount of revenue based on the mobilization rate stated in the contract. We begin earning our contracted daywork rate and mobilization revenue when we begin drilling the well. Occasionally, in periods of increased demand, we will receive a percentage of the contracted dayrate during the mobilization period. We account for these revenues as mobilization fees.

The decrease in the number of revenue days in 2007 is attributable to the decrease in utilization partially offset by the increase in the size of our operating drilling rig fleet. The annual increase in the number of revenue days in 2006 is attributable to the increase in the size of our operating drilling rig fleet.

We devote substantial resources to maintaining, upgrading and expanding our rig fleet. We substantially completed the refurbishment of three drilling rigs in 2007, 12 drilling rigs in 2006 and six drilling rigs in 2005.

Market Conditions in Our Industry

The United States contract land drilling services industry is highly cyclical. Volatility in oil and natural gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and natural gas prices and the outlook for future oil and natural gas prices strongly influence the number of wells oil and natural gas exploration and production companies decide to drill.

On February 29, 2008, the closing prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX were $101.84 per barrel and $9.37 per MMbtu, respectively. The Baker Hughes domestic land drilling rig count as of February 29, 2008 was 1,704. Baker Hughes is a large oil field services firm that has issued the rotary rig counts as a service to the petroleum industry since 1944.

We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as changes in supply of natural gas. The Energy Information Administration estimated that U.S. consumption of natural gas exceeded domestic production by 16% in 2005 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic production by 24% in 2010. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding ten years that average “initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time.” The report went on to state that “without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year” and predicted that in ten years eighty percent of gas production “will be from wells yet to be drilled.” We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in the U.S. Consequently, these factors may result in higher rig dayrates and rig utilization.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting policies that are described in the notes to our consolidated financial statements. The preparation of the consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate our judgments and estimates in determining our financial condition and operating results. Estimates are based upon information available as of the date of the financial statements and, accordingly, actual results could differ from these estimates, 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 most critical accounting policies and estimates are described below.

Revenue and Cost Recognition —We earn our revenues by drilling oil and natural gas wells for our customers under daywork or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. Mobilization revenues and costs are deferred and recognized over the drilling days of the related drilling contract. Individual contracts are usually completed in less than 120 days. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under this method, drilling revenues and costs related to a well in progress are recognized proportionately over the time it takes to drill the well. Percentage of completion is determined based upon the amount of expenses incurred through the measurement date as compared to total estimated expenses to be incurred drilling the well. Mobilization costs are not included in costs incurred for percentage-of-completion calculations. Mobilization costs on footage contracts and daywork contracts are deferred and recognized over the days of actual drilling. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. When estimates of revenues and expenses indicate a loss on a contract, the total estimated loss is accrued.

Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our footage contracts, which is the predominant practice in the industry. Although our footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed upon depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed upon depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed upon depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.

We are entitled to receive payment under footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since inception, we have completed all our footage contracts. Although our initial cost estimates for footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately adjust our cost estimate for the additional costs to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During 2006 and 2007, we did not experience a loss on the footage jobs we completed. We are more likely to encounter losses on footage contracts in years in which revenue rates are lower for all types of contracts.

Revenues and costs during a reporting period could be affected by contracts in progress at the end of a reporting period that have not been completed before our financial statements for that period are released. We had no footage contracts in progress at December 31, 2007 and 2006. At December 31, 2007 and 2006, our contract drilling in progress totaled $2.1 million and $2.0 million, respectively, all of which relates to the revenue recognized but not yet billed or costs deferred on daywork contracts in progress.

We accrue estimated contract costs on footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance and operating overhead allocations. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period that were not completed prior to the release of our financial statements.

Accounts Receivable —We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, current prices of oil and natural gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 30-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days. We are currently involved in legal actions to collect various overdue accounts receivable. Our allowance for doubtful accounts was $1,834,000 and $400,000 at December 31, 2007 and 2006, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our customer’s current ability to pay its obligation to us and the condition of the general economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables reduce the allowance for doubtful accounts.

If a customer defaults on its payment obligation to us under a footage contract, we would need to rely on applicable law to enforce our lien rights, because our footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we might also need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a footage contract.

Asset Impairment and Depreciation —We review long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. We also evaluate the carrying value of goodwill during the fourth quarter of each year and between annual evaluations if events occur or circumstances change that would more likely than not reduce the fair value below its carrying amount. Factors that we consider important and could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and natural gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs, intangible assets and goodwill indicate that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment, intangible assets and goodwill to its fair market value. A one percent write-down in the cost of our drilling equipment, intangible assets, and goodwill, at December 31, 2007, would have resulted in a corresponding decrease in our net income of approximately $3.0 million.

Our determination of the estimated useful lives of our depreciable assets, directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling rigs, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to fifteen years after the rig was placed into service. We record the same depreciation expense whether an operating rig is idle or working. Depreciation is not recorded on an inventoried rig until placed in service. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our experience in the drilling industry with similar equipment.

We capitalize interest cost as a component of drilling and workover rigs refurbished for our own use. During the years ended December 31, 2007 and 2006, we capitalized approximately $1.7 million and $3.6 million, respectively.

Stock Based Compensation--- We have adopted SFAS No. 123(R), “ Share-Based Payment ” upon granting our first stock options on August 16, 2005. SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the periods during which an employee is required to provide service in exchange for the award. Stock compensation expense was $3.7 million, $2.8 million and $589,000 for 2007, 2006 and 2005, respectively.

The fair value of each option award is estimated on the date of grant using a Black Scholes valuation model that uses various assumptions related to volatility, expected life, forfeitures, exercise patterns, risk free rates and expected dividends. Expected volatilities are based on the historical volatility of a selected peer and other factors. The majority of our options were granted to employees that made up one group with similar expected exercise behavior for valuation purposes. The expected term of options granted was estimated based on an average of the vesting period and the contractual period. The risk-free rate for periods within the contractual life of the option was based on the U.S. Treasury yield curve in effect at the time of the grant.

We have not declared dividends since we became a public company and do not intend to do so in the foreseeable future, and thus did not use a dividend yield. Expected life has been determined using the permitted short cut method.

Under our 2005 Stock Incentive Plan, employee stock options become exercisable in equal monthly installments over a three-year period, and all options generally expire ten years after the date of grant. The 2005 Plan provides that all options must have an exercise price not less than the fair market value of our common stock on the date of the grant.

On April 20, 2007, we filed a Tender Offer Statement on Schedule TO relating to our offer to eligible directors, officers, employees and consultants to exchange certain outstanding options to purchase shares of our common stock for restricted stock awards consisting of the right to receive restricted shares of our common stock, which we refer to as the “restricted stock awards.” The offer expired on May 21, 2007. Pursuant to the offer, we accepted for cancellation eligible options to purchase 729,000 shares of our common stock tendered by directors, officers, employees and consultants eligible to participate in the offer. Subject to the terms and conditions of the offer, on May 21, 2007 we granted one restricted stock award in exchange for every two shares of common stock underlying the eligible options tendered. Half of the restricted stock awards vested on January 1, 2008 and the balance vest on January 1, 2009, subject to earlier vesting or forfeiture in certain circumstances. We granted the restricted stock awards under our 2006 Stock Incentive Plan, effective as of April 20, 2006.

An incremental cost was computed in accordance with SFAS No. 123(R) upon the conversion of options to restricted stock. The incremental cost was measured as the excess of the fair value of the modified award over the fair value to the original award immediately preceding conversion, measured based on the share price and other pertinent factors at that date. The incremental cost to be recognized over the vesting period of the modified award is $387,000.

Deferred Income Taxes —We provide deferred income taxes for the basis difference in our property and equipment, stock compensation expense and other items between financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock in an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over fifteen years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Other Accounting Estimates —Our other accrued expenses as of December 31, 2007 and December 31, 2006 included accruals of approximately $3.0 million and $1.9 million, respectively, for costs under our workers’ compensation insurance. We have a deductible of $1.0 million per covered accident under our workers’ compensation insurance. We maintain letters of credit in the aggregate amount of $4.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts. The letters of credit are typically renewed annually. No amounts have been drawn under the letters of credit. At December 31, 2007 and 2006, we had deposits of $2.7 million and $2.6 million, respectively, with an insurance company collateralizing a letter of credit. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims. We also have a self-insurance program for major medical, hospitalization and dental coverage for employees and their dependents. We recognize both reported and incurred but not reported costs related to the self-insurance portion of our health insurance. Since the accrual is based on estimates of expenses for claims, the ultimate amount paid may differ from accrued amounts.

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.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

Contract Drilling Revenue. For the three months ended September 30, 2007, we reported contract drilling revenues of $70.4 million, a 12% decrease from revenues of $79.8 million for the same period in 2006. The decrease is primarily due to a decrease in dayrates and revenue days for the three months ended September 30, 2007 as compared to the same period in 2006. Average dayrates for our drilling services decreased $1,177, or 6%, to $17,256 for the three months ended September 30, 2007 from $18,433 in the same period in 2006. Revenue days decreased to 3,739 days for the three months ended September 30, 2007 from 4,039 days during the same period in 2006. Our average number of operating rigs increased to 53 from 47, or 13%, for the three months ended September 30, 2007 as compared to the same period in 2006. The decrease in the number of revenue days for the three months ended September 30, 2007 as compared to the same period in 2006 is attributable to a decrease in our rig utilization rate to 76% for the three months ended September 30, 2007 from 94% for the three months ended September 30, 2006 offset by the increase in the size of our operating rig fleet due to refurbishments. The 19% decrease in utilization was primarily due to a more competitive market resulting from an increase in the supply of drilling rigs.

Contract Drilling Expense. Direct rig cost increased $549,000 to $39.1 million for the three months ended September 30, 2007 from $38.6 million for the same period in 2006. This 1% increase is primarily due to the increase in available days as the result of the increase in average number of operating rigs in our fleet for the three months ended September 30, 2007 as compared to the same period in 2006. As a percentage of contract drilling revenue, drilling expense increased to 56% for the three-month period ended September 30, 2007 from 48% for the same period in 2006 due primarily to expenses related to the retention of crews of idle rigs.

Depreciation Expense. Depreciation expense increased $1.1 million to $9.2 million for the three months ended September 30, 2007 from $8.1 million for the same period in 2006. The increase is primarily due to the 32% increase in fixed assets, including the deployment of seven additional rigs from our inventory and the Eagle acquisition, as well as incremental increases in ancillary equipment, all of which occurred after the 2006 period. The increase was partially offset by an entry to credit depreciation expense for $2.1 million related to the use of an incorrect depreciable life of certain rig components that moved between working rigs and the yard.

General and Administrative Expense . General and administrative expense increased $662,000 to $5.4 million for the three months ended September 30, 2007 from $4.7 million for the same period in 2006. The increase is the result of an increase in bad debt expense of $583,000, an increase in stock compensation expense of $271,000, an increase in payroll costs of $77,000, an increase in rent expense of $75,000, and an increase in public relations expense of $75,000. The increase in bad debt expense is due to the specific identification of additional accounts receivable deemed uncollectible. The increase in stock compensation expense is attributable to additional grants of restricted stock during 2007. The increase in payroll is primarily due to our increased employee count due both to organic growth and acquisitions as well as selected wage increases. These increases were partially offset by a decrease in severance expense of $607,000 related to a payment made to our former Chief Operating Officer.

Interest Expense . Interest expense increased $483,000 to $1.0 million for the three months ended September 30, 2007 from $526,000 for the same period in 2006. The increase is due to a decrease in the capitalization of interest expense related to our rig refurbishment program. We capitalized $366,000 of interest for the three months ended September 30, 2007 as compared to $855,000 for the same period in 2006 as part of our rig refurbishment program.

Income Tax Expense . We recorded income tax expense of $7.0 million for the three months ended September 30, 2007, of which $7.5 million is deferred tax expense, partially offset by a current tax benefit of $447,000. This compares to a deferred tax expense of $10.5 million for the three months ended September 30, 2006. This decrease is due to a decrease in pre-tax income.

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