SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

(Mark One)

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 000-51471

 

Bronco Drilling Company, Inc.

(Exact name of registrant as specified in its charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		20-2902156 (I.R.S. Employer Identification No.)
16217 North May Avenue, Edmond, OK (Address of Registrant’s Principal Executive Offices)		73013 (Zip Code)

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock $0.01 Par Value per Share		The Nasdaq Stock Market LLC

Securities Registered Pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. þ

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

Large Accelerated Filer o		Accelerated Filer þ		Non-Accelerated Filer o		Smaller Reporting Company o

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of the most recently completed second fiscal quarter (based on the closing price on the Nasdaq Stock Market on June 30, 2010) was approximately $89,317,224.

As of February 28, 2011, 28,800,059 shares of common stock were outstanding.

Documents Incorporated By Reference

Certain information called for by Part III is incorporated by reference to either certain sections of the Proxy Statement for the 2011 Annual Meeting of our stockholders or an amendment to this Form 10-K which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 2010.

 

 

BRONCO DRILLING COMPANY, INC.
INDEX

						Form
						10-K
Item						Report
No.						Page
				Cautionary Note Regarding Forward-Looking Statements			3
PART I
1.				Business			3
1A.				Risk Factors			13
1B.				Unresolved Staff Comments			22
2.				Properties			22
3.				Legal Proceedings			22
4.				Reserved			22
PART II
5.				Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			23
6.				Selected Financial Data			24
7.				Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
7A.				Quantitative and Qualitative Disclosures About Market Risk			41
8.				Financial Statements and Supplementary Data			41
9.				Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			41
9A.				Controls and Procedures			41
9B.				Other Information			43
PART III
10.				Directors and Executive Officers and Corporate Governance			44
11.				Executive Compensation			44
12.				Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			44
13.				Certain Relationships and Related Transactions, and Director Independence			44
14.				Principal Accounting Fees and Services			44
PART IV
15.				Exhibits and Financial Statement Schedules			45
Exhibit 21.1
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

Cautionary Note Regarding Forward-Looking Statements

Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking statements give our current expectations and projections relating to our financial condition, results of operations, plans, objectives, future performance and business. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operating or financial performance or other events. All statements other than statements of historical facts included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements.

These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.

Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

PART I

Item 1.		Business

Unless otherwise indicated or the context otherwise requires, all references in this report to “Bronco,” the “Company,” “us,” “our,” or “we,” are to Bronco Drilling Company, Inc., a Delaware corporation, and its consolidated subsidiaries.

Our Company

We provide contract land drilling services to oil and gas exploration and production companies throughout the United States. 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 building, 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 2010. In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to build, refurbish and repair our rigs and equipment in-house. This facility, which complements our two drilling rig refurbishment yards, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays in our rig building and refurbishment programs.

Additionally, we have exposure to the international drilling market through a 20% equity investment in Bronco Drilling MX S.A. de C.V., a company organized under the laws of Mexico, or Bronco MX. Bronco MX provides contract land drilling services and leases land drilling rigs to Petroleos Mexicanos, or PEMEX, and/or companies contracted with PEMEX. We also have a 25% equity investment in Challenger Limited, a company organized under the laws of the Isle of Man, or Challenger. Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with its principal operations in Libya.

We currently conduct our operations through one operating segment: contract land drilling. In June of 2009 we made the decision to suspend operations in our well servicing segment because of deteriorating market conditions resulting from the decrease in oil and natural gas prices that began in the third quarter of 2008, as well as the inability of many customers to obtain financing related to their drilling and workover programs.

Through the second quarter of 2010, we explored alternatives to restructure the well servicing segment. During Q1 and Q2 2010 the market for workover services continued at depressed levels within our primary geographic well servicing market (Oklahoma). Late in Q2 2010, we determined that higher NPV projects were available within our drilling segment and chose to deploy capital in this segment rather than commit the capital required to restructure operations in the well servicing segment.

In late June 2010 we made a decision to market the assets constituting the well servicing segment for sale and redeploy the proceeds to reduce debt and to support our drilling segment. We have presented all well servicing operating results as discontinued operations in our Consolidated Statements of Operations for all periods presented. In September 2010, substantially all of the assets of the well servicing segment were sold at auction to multiple bidders. We used the proceeds to pay down existing indebtedness under our revolving credit facility.

In September and November 2010, we sold at auction in separate lots to multiple bidders two complete mechanical drilling rigs and components comprising six other drilling rigs (rigs 2, 9, 51, 52, 54, 70, 75 and 94), and ancillary equipment. The mechanical drilling rigs and equipment sold at auction were not being utilized currently in our business. In an unrelated transaction on September 23, 2010, we sold two mechanical drilling rigs (rigs 41 and 42) in a private sale to Windsor Permian LLC, an unaffiliated third party. On November 29, 2010, the Company sold two mechanical drilling rigs (rigs 5 and 7) in a private sale to Atlas Drilling, LLC, an unaffiliated third party.

We made the decision in the third quarter to sell an additional mechanical drilling rig (rig 6). We anticipate closing this transaction in the second quarter of 2011. In February 2011, we entered into a contract to sell two drilling rigs (rigs 56 and 62) to Windsor Permian LLC, an unaffiliated third party. The drilling rigs and related equipment sold at auction and held for sale are being sold as part of a broader strategy by management to divest of older drilling rigs and use the proceeds to pay down existing indebtedness. The drilling rigs and related equipment sold at auction and held for sale are being sold as part of our broader strategy to divest of older mechanical drilling rigs and use the proceeds to pay down existing indebtedness and invest in next generation drilling equipment.

The following is a description of our operating segment.

Contract Land Drilling — Our contract land drilling segment provides contract land drilling services. As of February 28, 2011, we owned a fleet of 25 operating land drilling rigs. We currently operate our drilling rigs in Oklahoma, Texas, Pennsylvania, West Virginia and North Dakota. A majority of the wells we drill for our customers are drilled in unconventional basins also known as resource plays. These plays are generally characterized by complex geologic formations that often require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 25 operating drilling rigs range from 650 to 2,000 horsepower. Accordingly, such rigs can reach the depths required and have the capability of drilling horizontal and directional wells, which are increasing as a percentage of total wells drilled in North America and are frequently utilized in unconventional resource plays. We believe our premium rig fleet, inventory and experienced crews position us to benefit from the oil and natural gas drilling activity in our core operating areas.

Our Acquisitions

The following table summarizes completed acquisitions in which we acquired rigs and rig related equipment since June 2001:

						Purchase				Number of Land Drilling
Date				Acquisition		Price				/Workover Rigs
June 2001				Ram Petroleum		$	1,250,000				1
May 2002				Bison Drilling and Four Aces Drilling		$	12,500,000				7
August 2003				Elk Hill Drilling and U.S. Rig & Equipment		$	49,000,000				22
July 2005				Strata Drilling and Strata Property		$	20,000,000				3
October 2005				Eagle Drilling		$	50,000,000				12
October 2005				Thomas Drilling		$	68,000,000				13
January 2006				Big A Drilling		$	18,150,000				6
January 2007				Eagle Well Service		$	32,085,000				31

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.

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 deployed seventeen of the rigs beginning in 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., 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., 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.

Our Equity Investments

On January 4, 2008, we acquired a 25% equity interest in Challenger in exchange for six drilling rigs and $5.0 million in cash. Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with its principal operations in Libya. Five of the contributed drilling rigs were from our existing marketed fleet and one was a newly constructed rig. The general specifications of the contributed rigs are as follows:

						Approximate
						Drilling
Rig		Design				Depth (ft)				Type				Horsepower
3		Cabot 900					10,000			Mechanical					950
18		Gardner Denver 1500E					25,000			Electric					2,000
19		Mid Continent U-1220 EB					25,000			Electric					2,000
38		National 1320					25,000			Electric					2,000
93		National T-32					8,000			Mechanical					500
96		Ideco H-35					8,000			Mechanical					400

In a separate transaction, we sold to Challenger four additional drilling rigs and ancillary equipment for $13.0 million, payable in installments over thirty-six months. During the second quarter of 2009, we agreed to reduce the installment payments and assumed ownership of two drilling rigs originally sold to Challenger. The general specifications of the two sold rigs are as follows:

Approximate

Drilling Depth

Rig

Design

(ft)

Type

Horsepower

91

Ideco H-35

8,000

Mechanical

450

95

Emsco GB800

12,000

Mechanical

1,000

We review our investment in Challenger for impairment based on the guidance of ASC Topic 323, Investments-Equity Method and Joint Venture, which states that a loss in value of an investment which is an other than temporary decline should be recognized. Evidence of a loss in value might include the absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. Due to the volatility and decline in oil and natural gas prices, a deteriorating global economic environment and the anticipated future earnings of Challenger, we deemed it necessary to test the investment for impairment during 2008, 2009 and 2010. Fair value of the investment was estimated using a combination of income, or discounted cash flows approach and the market approach, which utilizes comparable companies’ data. The analysis resulted in a non-cash impairment charge in the amount of $14.4 million in 2008. The analysis resulted in a fair value of $39.8 million related to our investment in Challenger at September 30, 2009, which was below the carrying value of the investment and resulted in a non-cash impairment charge in the amount of $21.2 million. The analysis resulted in no impairment charge at December 31, 2010

In September 2009, Carso Infraestructura y Construcción, S.A.B. de C.V., or CICSA, purchased from us 60% of the outstanding membership interests of Bronco MX for approximately $30.0 million. After giving effect to the transaction, we owned the remaining 40% of the outstanding membership interests of Bronco MX. Immediately prior to the sale of the membership interests to CICSA, we contributed six drilling rigs and the future net profit from rig leases for three additional drilling rigs, which the Company contributed to Bronco MX upon the expiration of the leases for such rigs. The general specifications of the 9 nine contributed rigs are as follows:

						Approximate
						Drilling Depth
Rig		Design				(ft)				Type				Horsepower
43		Gardner Denver 800					15,000			Mechanical					1,000
4		Skytop Brewster N46					14,000			Mechanical					950
53		Skytop Brewster N42					12,000			Mechanical					850
55		Oilwell 660					12,000			Mechanical					1,000
58		National N55					12,000			Mechanical					800
60		Skytop Brewster N46					14,000			Mechanical					850
72		Skytop Brewster N42					10,000			Mechanical					750
76		National N55					12,000			Mechanical					700
78		Seaco 1200					12,000			Mechanical					1,200

In July, 2010, CICSA contributed cash of approximately $45.1 million in exchange for 735,356,219 shares of Bronco MX. The cash contributed was used to purchase five drilling rigs. As a result of the contribution, our membership interest in Bronco MX was decreased to approximately 20%.

Bronco MX is managed by CICSA having four representatives on its board of managers and the Company having one representative on its board of managers. The Company and CICSA, and their respective affiliates, have agreed to conduct all future land drilling and workover rig services, rental, construction, refurbishment, transportation, trucking and mobilization in Mexico and Latin America exclusively through Bronco MX, subject to Bronco MX’s ability to perform.

Overview of Our Operating Segment

Contract Land Drilling

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.

As of February 28, 2011, our drilling rig fleet consisted of 25 operating drilling rigs, 20 of which were operating on term contracts with a term of more than one well or a stated period of time. Eighteen of these drilling rigs have undergone significant refurbishment since October 2003 by us or the parties from which the rigs were purchased. The following table sets forth information regarding utilization for our fleet of marketed drilling rigs:

		Year Ended December 31,
		2010				2009				2008
Average number of operating drilling rigs			33				44				44
Revenue days			7,450				5,699				12,712
Utilization Rates			62	%			36	%			79	%

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. We own 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.

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. 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. For example, as oil and natural gas prices steeply declined and credit markets tightened in late calendar 2008, customers aggressively reduced drilling budgets. As a result, we experienced a decline in rig utilization. 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 of 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. We typically enter into drilling contracts that provide for compensation on a daywork basis. Occasionally we enter into drilling contracts that provide for compensation on a footage basis. We have not historically entered into turnkey contracts; however, we may decided to enter into such contracts in the future. It is also 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 20 of our drilling rigs operating under term contracts, our contracts generally provide for the drilling of a single well and typically permit the customer to terminate on short notice, usually upon payment of an agreed fee. During 2009, we recorded $7.9 million of contract drilling revenue related to terminated contracts. During 2010, we recorded no revenue related to terminated contracts.

The following table presents, by type of contract, information about the total number of wells we completed for our customers during the years ended December 31, 2010, 2009 and 2008.

		Years Ended December 31,
		2010				2009				2008
Daywork Contracts			163				152				378
Footage Contracts			—				—				—
Turnkey Contracts			—				—				—
Total			163				152				378

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. When we enter into footage contracts, we endeavor to manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly, and we typically 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. While we have historically entered into few footage contracts, we may enter into more of such arrangements in the future to the extent warranted by market conditions.

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 to the extent warranted by market conditions. It is also possible that we may acquire such contracts in connection with future acquisitions. 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 drilling rigs to a number of major and independent oil and gas companies that are active in the geographic areas in which we operate. The following table shows our customers that accounted for more than 5% of our total revenue for each of our last three years. In the opinion of management, the loss of any of our customers individually would not have a material adverse effect on our business.

		Total Revenue
Customer		Percentage
2010
Petro-Hunt LLC			11	%
EOG Resources Inc			10	%
Whiting Petroleum			9	%
Antero Resources			8	%
Anschutz Exploration			7	%
Zenergy Inc			7	%
Beusa Energy Inc			7	%
Comstock Oil and Gas			6	%
Hunt Oil Company			5	%
2009
Comstock Oil and Gas			12	%
Whiting Petroleum			9	%
Pemex Exploracion			8	%
Laredo Petroleum			6	%
Antero Resources			6	%
Hunt Oil Company			5	%
JMA Energy Company, LLC			5	%
2008
Antero Resources			11	%
XTO Energy			7	%
JMA Energy Company, LLC			5	%
Pablo Energy II, LLC			5	%

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.

Competition

Contract Land Drilling

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., Union Drilling, Inc., Pioneer Drilling Company, Cactus Drilling Company, L.L.C. and Helmerich & Payne, Inc. There are numerous smaller companies that compete in our service markets as well. 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 drilling operations include fuels to operate our drilling, 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.

Operating Risks and Insurance

Our operations are subject to the many hazards inherent in the contract land drilling and well servicing business, including the risks of:

	•		blowouts;
	•		fires and explosions;

•

loss of well control;

•

collapse of the borehole;

•

lost or stuck drill strings; and

•

damage or loss from natural disasters.

Any of these hazards can result in substantial liabilities or losses to us from, among other things:

•

suspension of drilling operations;

•

damage to, or destruction of, our property and equipment and that of others;

•

personal injury and loss of life;

•

damage to producing or potentially productive oil and natural gas formations through which we drill; and

•

environmental damage.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases have sufficient financial resources or maintain adequate insurance to support their indemnification obligations. We can offer no assurance that our insurance or indemnification arrangements will adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

Our insurance coverage includes property insurance on our rigs, drilling equipment and real property. Our insurance coverage for property damage to our rigs and to our drilling equipment is based on a third party estimate of the appraised value of the rigs and drilling equipment. The policy provides for a $1.0 million deductible on stacked drilling rigs and the greater of 3.0% of total insured value or $500,000 for operating rigs. Our umbrella liability insurance coverage is $25.0 million per occurrence and in the aggregate, with a deductible of $10,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

Employees

As of February 28, 2011, we had 686 employees. Approximately, 100 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees, the majority of whom operate or maintain our drilling rigs. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employees are subject to collective bargaining arrangements.

Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel can occur in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

Governmental Regulation

Our operations are subject to stringent federal, state and local laws and regulations governing the protection of the environment and human health and safety. Several such laws and regulations relate to the handling, storage and disposal of oilfield waste and restrict the types, quantities and concentrations of such regulated substances that can be released into the environment. Several such laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. In addition, our operations are sometimes conducted in or near ecologically sensitive areas, which are subject to special protective measures and which may expose us to additional operating costs and liabilities related to restricted operations, for accidental discharges of oil, natural gas, drilling fluids, contaminated water or other substances or for noncompliance with other aspects of applicable laws and regulations. Historically, we have not been required to obtain environmental or other permits prior to drilling a well. Instead, the operator of the oil and gas property has been obligated to obtain the necessary permits at its own expense.

The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Safe Drinking Water Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes and related regulations are the primary vehicles for imposition of such requirements and for civil, criminal and administrative penalties and other sanctions for violation of their requirements. The OSHA hazard communication standard and related regulations, the Environmental Protection Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also not uncommon for third parties to file claims for personal injury and property damage caused by substances released into the environment.

Environmental laws and regulations are complex and subject to frequent changes. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets that we acquired from others. We believe we are in substantial compliance with applicable environmental laws and regulations and, to date, such compliance has not materially affected our capital expenditures, earnings or competitive position. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current or reasonably anticipated environment control requirements. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of regulatory noncompliance or contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

As we expanded our operations outside of the United States, we must comply with numerous laws and regulations relating to international business operations, including the Foreign Corrupt Practices Act, or FCPA. The creation and implementation of international business practices compliance programs is costly and such programs are difficult to enforce, particularly where reliance on third parties is required.

The FCPA prohibits any U.S. individual or business from paying, offering, or authorizing payment or offering of anything of value, directly or indirectly, to any foreign official, political party or candidate for the purpose of influencing any act or decision of the foreign entity in order to assist the individual or business in obtaining or retaining business. The FCPA also obligates companies whose securities are listed in the United States to comply with certain accounting provisions requiring the company to maintain books and records that accurately and fairly reflect all transactions of the corporation, including international subsidiaries, and to devise and maintain an adequate system of internal accounting controls for international operations. The anti-bribery provisions of the FCPA are enforced primarily by the U.S. Department of Justice. The SEC is involved with enforcement of the books and records provisions of the FCPA.

The failure to comply with laws governing international business practices may result in substantial penalties, including suspension or debarment from government contracting. Violation of the FCPA can result in significant civil and criminal penalties. A failure to satisfy any of our obligations under laws governing international business practices could have a negative impact on our operations and harm our reputation. The SEC also may suspend or bar issuers from trading securities on United States exchanges for violations of the FCPA’s accounting provisions.

In addition, our business depends on the demand for land drilling services from the oil and natural gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and natural gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers or otherwise directly or indirectly affect our operations.

Available Information

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.broncodrill.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Our code of conduct and business ethics is also available on our website. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference in this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

Item 1A.		Risk Factors

You should consider each of the following factors as well as the other information in this Report in evaluating our business. Additional risks and uncertainties not presently known to us or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business and financial results could be harmed. You should refer to the other information set forth in this Report, including our financial statements and the related notes.

Risks Relating to the Oil and Natural Gas Industry

We derive all our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices.

Worldwide political, economic and military events have contributed to oil and natural gas price volatility and are likely to continue to do so in the future. Depending on the market prices of oil and natural gas, oil and natural gas exploration and production companies may cancel or curtail their drilling programs, thereby reducing demand for our services. Oil and natural gas prices have been volatile historically and, we believe, will continue to be so in the future. Many factors beyond our control affect oil and natural gas prices, including:

•

the cost of exploring for, producing and delivering oil and natural gas;

•

the discovery rate of new oil and natural gas reserves;

•

the rate of decline of existing and new oil and natural gas reserves;

•

available pipeline and other oil and natural gas transportation capacity;

•

the ability of oil and natural gas companies to raise capital;

•

actions by OPEC, the Organization of Petroleum Exporting Countries;

•

political instability in the Middle East and other major oil and natural gas producing regions;

•

economic conditions in the United States and elsewhere;

•

governmental regulations, both domestic and foreign;

•

domestic and foreign tax policy;

•

weather conditions in the United States and elsewhere;

•

the pace adopted by foreign governments for the exploration, development and production of their national reserves;

•

the price of foreign imports of oil and natural gas; and

•

the overall supply and demand for oil and natural gas.

Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and natural gas prices or otherwise, can adversely impact us in many ways by negatively affecting:

•

our revenues, cash flows and profitability;

•

our ability to maintain or increase our borrowing capacity;

•

our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital;

•

our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services; and

•

the fair market value of our rig fleet.

As oil and natural gas prices steeply declined and the credit markets tightened in late calendar 2008, customers aggressively reduced drilling budgets. This reduction in demand combined with the reactivation and construction of new land drilling rigs in the United States during the last several years has resulted in excess capacity compared to demand. Tightening credit markets have also reduced our customer’s ability to fund drilling programs. As a result, we experienced a decline in rig utilization and average dayrates. We believe that utilization and average dayrates have stabilized and are now improving. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Continued low market prices for natural gas and economic conditions that have eroded residential and commercial demand for oil and natural gas may result in further decreases in demand for our drilling rigs and adversely affect our operating results.

Risks Relating to Our Business

Global economic conditions may adversely affect our operating results.

Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling and well servicing activities. Oil and natural gas prices steeply declined and the credit markets tightened in late calendar 2008. During this time there was also significant deterioration in the global economic environment. As part of this deterioration, there was significant uncertainty in the capital markets and access to financing has been reduced. As a result of these conditions, customers reduced their drilling and well servicing programs, which is resulted in a significant decrease in demand for our services. We believe that utilization has stabilized and is now improving. Furthermore, these factors could result in certain of our customers experiencing an inability to pay suppliers, including us, if they are not able to access capital to fund their operations. These conditions could have a material adverse effect on our business, financial condition, cash flows and results of operations. The following table depicts the prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX.

		Natural Gas Price
		per Mcf								Oil Price per Bbl
Quarter		High				Low				High				Low
2010:
Fourth		$	4.61			$	3.29			$	91.51			$	79.49
Third		$	4.92			$	3.65			$	82.55			$	71.63
Second		$	5.19			$	3.91			$	86.79			$	68.01
First		$	6.01			$	3.84			$	83.76			$	71.19
2009:
Fourth		$	5.99			$	4.25			$	81.37			$	69.57
Third		$	4.88			$	2.51			$	74.37			$	59.52
Second		$	4.45			$	3.25			$	72.68			$	45.88
First		$	6.07			$	3.63			$	54.34			$	33.98
2008:
Fourth		$	7.73			$	5.29			$	98.53			$	33.87
Third		$	13.58			$	7.22			$	145.29			$	95.71
Second		$	13.35			$	9.32			$	140.21			$	100.98
First		$	10.23			$	7.62			$	110.33			$	86.99

Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

As a component of our business strategy, we have pursued and intend to continue to pursue selected acquisitions of complementary assets and businesses. In May 2002, we purchased seven drilling rigs, associated spare parts and equipment, drill pipe, haul trucks and vehicles. In August 2003, we acquired drilling rigs and inventoried structures and components which, with refurbishment and upgrades, could be used to assemble 22 drilling rigs. In July 2005, we acquired three additional rigs and related inventory, equipment, components and a rig yard. On October 3, 2005, we acquired five operating rigs, seven inventoried rigs and rig equipment and parts. On October 14, 2005, we acquired nine operating rigs, two rigs undergoing refurbishment, two inventoried rigs and rig equipment and parts. On January 18, 2006, we acquired six operating land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment. On January 9, 2007, we acquired 31 workover rigs through our acquisition of Eagle Well. Acquisitions, including those described above, involve numerous risks, including:

•

unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired companies, including but not limited to environmental liabilities;

•

difficulty in integrating the operations and assets of the acquired business and the acquired personnel and distinct cultures;

•

our ability to properly access and maintain an effective internal control environment over an acquired company, in order to comply with public reporting requirements;

•

potential loss of key employees and customers of the acquired companies;

	•		risk of entering markets in which we have limited prior experience; and
	•		an increase in our expenses and working capital requirements.

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded the acquisition of rigs and the refurbishment of our rig fleet through a combination of debt and equity financing and cash flows from operations. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.

Increases in the supply of rigs could decrease revenue rates and utilization rates.

An increase in the supply of land drilling rigs, whether through new construction or refurbishment, could decrease revenue rates and utilization rates, which would adversely affect our revenues and profitability. In addition, such adverse affect on our revenue and profitability caused by such increased competition and lower revenue rates and utilization rates could be further aggravated by any downturn in oil and natural gas prices. There has been a substantial increase in the supply of land drilling rigs in the United States over the past five years which has contributed to a broad decline in revenue rates and utilization industry wide.

Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

As of December 31, 2010, our total borrowings under our credit facility were approximately $9.1 million and we had the ability to incur an additional $54.4 million of debt under our revolving credit facility (net of outstanding letters of credit of $11.5 million).

Our current and future indebtedness could have important consequences, including:

•

impairing our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;

•

limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;

•

making us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow could be required to make principal and interest payments on our indebtedness, making it more difficult to react to changes in our business and in industry and market conditions;

•

limiting our ability to obtain additional financing that may be necessary to operate or expand our business;

•

putting us at a competitive disadvantage to competitors that have less debt; and

•

increasing our vulnerability to rising interest rates.

We anticipate that our cash generated by operations and our ability to borrow under the currently unused portion of our revolving credit facility should allow us to meet our routine financial obligations for the foreseeable future. However, our ability to make payments on our indebtedness, and to fund planned capital expenditures, will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and gas industry, general economic and financial conditions, competition in the markets where we operate, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:

•

refinancing or restructuring our debt;

•

selling assets;

•

reducing or delaying acquisitions or capital investments, such as refurbishments of our rigs and related equipment; or

•

seeking to raise additional capital.

However, we may be unable to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, and any such alternative financing plans might be insufficient to allow us to meet our debt obligations. If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our revolving credit facility or other instruments governing any future indebtedness, we could be in default under the terms of our revolving credit facility or such instruments. In the event of a default, the lender under our revolving credit facility, Banco Inbursa S.A. (“Banco Inbursa”), could elect to declare all the loans made under such facility to be due and payable together with accrued and unpaid interest and terminate its commitments thereunder and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

Our revolving credit facility imposes restrictions on us that may affect our ability to successfully operate our business.

Our revolving credit facility limits our ability to take various actions, such as:

•

limitations on the incurrence of additional indebtedness;

•

restrictions on investments, mergers or consolidations, asset dispositions, acquisitions, transactions with affiliates and other transactions without the lender’s consent; and

•

limitation on dividends and distributions.

In addition, our revolving credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, which may require us to reduce our debt or take some other action in order to comply with them. The failure to comply with any of these financial conditions, such as financial ratios or covenants, would cause an event of default under our revolving credit facility. An event of default, if not waived, could result in acceleration of the outstanding indebtedness under our revolving credit facility, in which case the debt would become immediately due and payable. If this occurs, we may not be able to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our revolving credit facility.

Carlos Slim Helú, members of his family and affiliated entities may exercise significant influence in our affairs and their interests may differ from the interests of our other stockholders.

According to a Schedule 13D/A filed with the SEC by Carlos Slim Helú, certain members of his family and affiliated entities (the “Slim Affiliates”) on March 8 2010, collectively these individuals and entities owned approximately 19.99% of our common stock. Additionally, CICSA (which is also a Slim Affiliate) holds a warrant to purchase up to 5,440,770 shares of our common stock (the “Warrant”) that we originally issued in connection with our revolving credit facility. The Warrant, if exercised by CICSA, would permit the Slim Affiliates to acquire up to 19.99% of our outstanding common stock. As a consequence of the significant ownership of our common stock held by the Slim Affiliates, collectively, they may exercise significant influence over the outcome of matters involving a vote of our stockholders, including the election of our directors, a merger or other business combination or a sale of a substantial amount of our assets.

Banco Inbursa is the lender under our revolving credit facility, and is currently our largest creditor. CICSA owns 80% of the equity of Bronco MX, which is a joint venture in Mexico in which we own the other 20%. Because of the contractual and business relationships we have with the Slim Affiliates, the interests of the Slim Affiliates may differ from the interests of our other stockholders, and the revolving credit facility, the joint venture documentation relating to Bronco MX and the Warrant contain provisions that may tend to increase the influence the Slim Affiliates may exercise in our affairs.

For instance, the joint venture represents a significant investment by us that will be controlled by the Slim Affiliates, who, among other things, will be able to influence the amount and timing of any distributions of cash or property by Bronco MX to its equity holders, including us. Our revolving credit facility contains a variety of customary affirmative and negative covenants that limit our ability to engage in certain actions unless we obtain a waiver or consent from Banco Inbursa. If we are unable to satisfy our obligations to make mandatory payments of principal and/or interest under our revolving credit facility our failure to do so could lead to an event of default under the revolving credit facility, which would permit Banco Inbursa to exercise various contractual remedies under the revolving credit facility, including accelerating the maturity of our obligations and foreclosing upon our assets securing the revolving credit facility. The Warrant includes a covenant that restricts our ability to issue shares of common stock (or rights or warrants or other securities exercisable or convertible into or exchangeable for shares of common stock) at a consideration per share that is less than 95% of the market price of our common stock, subject to certain exceptions. If it became necessary for us to raise capital and we were unable to sell shares of common stock in a manner that complied with the Warrant, we would be required to obtain a waiver of this requirement or risk liability for breach of contract. If we were unable to obtain a waiver, it could have a material adverse affect on our business, financial condition and results of operation.

Our investments in Challenger and Bronco MX are illiquid and may never generate cash.

There currently is no readily available market that would facilitate the disposal of our 25% equity investment in Challenger or our 20% equity investment in Bronco MX. Furthermore, based on these minority equity positions, we may not directly receive cash proceeds resulting from the operations of Challenger or Bronco MX. We cannot assure that the investments will ever yield cash proceeds, absent a liquidating event or the increase in our equity position above a threshold that would constitute control. We have also pledged our equity investment in Challenger to secure the indebtedness under Challenger’s revolving credit facility with Natixis. In the event of default by Challenger under its facility, Natixis could enforce the pledge of our equity investment, which could result in the loss of our rights as an equity holder in Challenger.

Our minority equity investment in Challenger and Bronco MX limits our control of those companies.

Bronco representatives hold two of the eight total board seats on the Challenger board of directors and one of the five total board seats on the Bronco MX board of managers. We also have various rights as a shareholder of these companies, including:

•

preemptive rights;

•

transfer rights;

•

tag-along rights;

•

drag-along rights; and

•

certain voting rights.

Bronco is one of three shareholder groups in Challenger. Any two of the three shareholders can effectuate decisions at the board level. Due to our minority equity interest in Challenger, we cannot accomplish specific objectives or initiatives if we are unable to align our interest with at least one of the remaining shareholders. Bronco is one of two shareholder groups in Bronco MX. Due to our minority equity interest in Bronco MX, we cannot accomplish specific objectives or initiatives if we are unable to align our interests with the other shareholder.

International operations are subject to uncertain political, economic and other risks which could affect our financial results.

We currently have a 20% investment in Bronco MX, a company organized under the laws of Mexico, and a 25% investment in Challenger, an Isle of Man company with its principal operations in Libya. Risks associated with international operations and Challenger and Bronco MX’s operations include:

•

terrorist acts, war and civil disturbances;

•

expropriation or nationalization of assets;

•

renegotiation or nullification of existing contracts;

•

foreign taxation, including changes in law or interpretation of existing law;

•

assaults on property or personnel;

•

changing political conditions;

•

foreign and domestic monetary policies; and

•

travel limitations or operational problems caused by public health threats.

Early in 2010, there began to develop civil and political disturbances in Libya. There continues to be political unrest in Libya and the Middles East. We are unsure what effects the current political instability in Libya north Africa, and the Middle East will have on our investment in Challenger. Such instability could result in the total loss of our investment. Our investment in Challenger was $38.7 million at December 31, 2010.

As we expanded our operations outside of the United States, we must comply with numerous laws and regulations relating to international business operations, including the FCPA. The creation and implementation of international business practices compliance programs is costly and such programs are difficult to enforce, particularly where reliance on third parties is required.

The FCPA prohibits any U.S. individual or business from paying, offering, or authorizing payment or offering of anything of value, directly or indirectly, to any foreign official, political party or candidate for the purpose of influencing any act or decision of the foreign entity in order to assist the individual or business in obtaining or retaining business. The FCPA also obligates companies whose securities are listed in the United States to comply with certain accounting provisions requiring the company to maintain books and records that accurately and fairly reflect all transactions of the corporation, including international subsidiaries, and to devise and maintain an adequate system of internal accounting controls for international operations. The anti-bribery provisions of the FCPA are enforced primarily by the U.S. Department of Justice. The SEC is involved with enforcement of the books and records provisions of the FCPA.

The failure to comply with laws governing international business practices may result in substantial penalties, including suspension or debarment from government contracting. Violation of the FCPA can result in significant civil and criminal penalties. A failure to satisfy any of our obligations under laws governing international business practices could have a negative impact on our operations and harm our reputation. The SEC also may suspend or bar issuers from trading securities on United States exchanges for violations of the FCPA’s accounting provisions.

We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.

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 contracts we compete for are usually awarded on the basis of competitive bids or direct negotiations with customers. We believe pricing and quality of equipment are the primary factors our potential customers consider in determining which service provider 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 experience of our rig crews to differentiate us from our competitors. This strategy is less effective as lower demand for 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 which can, in turn, reduce our profitability.

Service 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 our services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and reduce profitability.

We face competition from competitors with greater resources that may make it more difficult for us to compete, which can reduce our revenue rates and utilization rates.

Some of our competitors have greater financial, technical and other resources than we do that may make it more difficult for us to compete, which can reduce our revenue rates and utilization rates. Their greater capabilities in these areas may enable them to:

•

better withstand industry downturns;

•

compete more effectively on the basis of price and technology;

•

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.

In the event we enter into footage or turnkey contracts, we could be subject to unexpected cost overruns, which could negatively impact our profitability.

For the years ended December 31, 2010, 2009 and 2008, none of our total revenues were derived from 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. The occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a negative impact on our profitability. Similar to our footage contracts, under turnkey contacts drilling companies assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. Although we historically have not entered into turnkey contracts, if we were to enter into a turnkey contract or acquire such a contract in connection with future acquisitions, the occurrence of uninsured or under-insured losses or operating cost overruns on such a job could negatively impact our profitability.

Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.

Our operations are subject to the many hazards inherent in the contract land drilling and well servicing business, including the risks of:

•

blowouts;

•

fires and explosions;

•

loss of well control;

•

collapse of the borehole;

•

lost or stuck drill strings; and

•

damage or loss from natural disasters.

Any of these hazards can result in substantial liabilities or losses to us from, among other things:

•

suspension of operations;

•

damage to, or destruction of, our property and equipment and that of others;

•

personal injury and loss of life;

•

damage to producing or potentially productive oil and natural gas formations through which we drill; and

•

environmental damage.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.

We face increased exposure to operating difficulties because we have historically focused on drilling in unconventional resource plays.

A majority of our drilling contracts are with exploration and production companies in search of oil and natural gas in unconventional resource plays. Drilling on land in resource plays generally occurs at deeper drilling depths than drilling in conventional plays. Although deep-depth drilling exposes us to risks similar to risks encountered in shallow-depth drilling, the magnitude of the risk for deep-depth drilling is greater because of the higher costs and greater complexities involved in drilling deep wells. We generally enter into International Association of Drilling Contractors contracts that contain “daywork” indemnification language that transfers responsibility for down hole exposures such as blowout and fire to the operator, leaving us responsible only for damage to our rig and our personnel. If we do not adequately insure the risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled, our profitability and other results of operation and our financial condition could be adversely affected in the event we encounter blowouts or other significant operating difficulties while drilling at deeper depths. If our primary focus shifts from drilling for customers in unconventional resource plays to drilling for customers in conventional plays, a portion of our rig fleet could be disadvantaged in competing for new conventional drilling projects as compared to competitors that primarily use shallower drilling depth rigs when drilling in conventional plays.

Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.

Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:

•

environmental quality;

•

pollution control;

	•		remediation of contamination;
	•		preservation of natural resources; and

•

worker safety.

Our operations are subject to stringent federal, state and local laws and regulations governing the protection of the environment and human health and safety. Several such laws and regulations relate to the disposal of hazardous oilfield waste and restrict the types, quantities and concentrations of such regulated substances that can be released into the environment. Several such laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In addition, our operations are often conducted in or near ecologically sensitive areas, which are subject to special protective measures and that may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids, contaminated water or other substances or for noncompliance with other aspects of applicable laws and regulations. Historically, we have not been required to obtain environmental or other permits prior to drilling a well. Instead, the operator of the oil and gas property has been obligated to obtain the necessary permits at its own expense.

The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe Drinking Water Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary vehicles for imposition of such requirements and for civil, criminal and administrative penalties and other sanctions for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also not uncommon for third parties to file claims for personal injury and property damage caused by substances released into the environment.

Environmental laws and regulations are complex and subject to frequent changes. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets that we acquired from others. We are in substantial compliance with applicable environmental laws and regulations and, to date, such compliance has not materially affected our capital expenditures, earnings or competitive position. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current or reasonably anticipated environment control requirements. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of regulatory noncompliance or contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers to reduce GHG emissions, as well as GHG emissions regulations enacted by the U.S. Environmental Protection Agency. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

In addition, our business depends on the demand for land drilling services from the oil and natural gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and natural gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers or otherwise directly or indirectly affect our operations.

We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could disrupt our operations resulting in a loss of revenues. Although we have employment agreements with a small number of our employees, as a practical matter such employment agreements will not assure the retention of those employees. In addition, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

We may be unable to attract and retain qualified, skilled employees necessary to operate our business.

Our success depends in large part on our ability to attract and retain skilled and qualified personnel. Our inability to hire, train and retain a sufficient number of qualified employees could impair our ability to manage and maintain our business. We require skilled employees who can perform physically demanding work. Shortages of qualified personnel can occur in our industry. As a result of the volatility of the oil and natural gas industry and the demanding nature of the work, potential employees may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. With a reduced pool of workers, it is possible that we will have to raise wage rates to attract workers from other fields and to retain our current employees. If we are not able to increase our service rates to our customers to compensate for wage-rate increases, our profitability and other results of operations may be adversely affected.

Shortages in equipment and supplies could limit our operations and jeopardize our relations with customers.

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. Shortages in drilling equipment and supplies could limit our drilling operations, limit our ability to build and/or refurbish drilling rigs, and jeopardize our relations with customers. We do not rely on a single source of supply for any of these items. From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. 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 our 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 drilling rigs, which could negatively impact our revenues and profitability.

If the price of our common stock fluctuates significantly, your investment could lose value.

Prior to our initial public offering in August 2005, there had been no public market for our common stock. Although our common stock is now quoted on The Nasdaq Global Select Market, we cannot assure you that an active public market will continue to exist for our common stock or that our common stock will continue to trade in the public market at or above current prices. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock is less liquid than the stock of companies with broader public ownership and, as a result, the trading price of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

•

our quarterly operating results;

•

changes in our earnings estimates;

•

additions or departures of key personnel;

•

changes in the business, earnings estimates or market perceptions of our competitors;

•

changes in general market or economic conditions; and

•

announcements of legislative or regulatory change.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

The market price of our common stock could decline following sales of substantial amounts of our common stock in the public markets.

If a large number of shares of our common stock is sold in the open market, the trading price of our common stock could decrease. As of February 28, 2011, we had an aggregate of 63,912,927 shares of our common stock authorized but unissued and not reserved for specific purposes. In general, we may issue all of these shares without any approval by our stockholders. We may issue shares of our common stock, or securities convertible into shares of our common stock, to, among other things, finance the cost of acquisitions, refinance existing indebtedness, finance capital expenditures and capacity expansion, and/or generate proceeds for general corporate purposes or working capital.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders.

The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

•

provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;

•

limitations on the ability of our stockholders to call a special meeting and act by written consent;

•

the authorization given to our board of directors to issue and set the terms of preferred stock; and

•

limitations on the ability of our stockholders from removing our directors without cause.

We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any payment of cash dividends will depend upon our financial condition, capital requirements, earnings and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

Item 1B.		Unresolved Staff Comments

None.

Item 2.		Property

Our corporate headquarters is located at 16217 North May Avenue, Edmond, Oklahoma in an office building we purchased on January 2, 2007. The approximately 18,100 square foot building was purchased for a total purchase price of $3.0 million, less an amount equal to one-half of the principal reduction on the seller’s loan secured by the property between the effective date of the purchase agreement and the closing. We paid $1.4 million in cash and assumed existing debt of approximately $1.6 million.

Our contract land drilling segment is supported by several offices and yard facilities located throughout this segment’s areas of operations, including Oklahoma, Louisiana, Texas, North Dakota and Pennsylvania.

We own our office and yard in Duncan, Oklahoma and an office and yard in Scenery Hill, Pennsylvania. We lease the remainder of our facilities, and do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to meet our needs.

Item 3.		Legal Proceedings

Various claims and lawsuits, incidental to the ordinary course of business, are pending against the Company. In the opinion of management, all matters are adequately covered by insurance or, if not covered, are not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

Item 4.		Reserved

PART II

Item 5.		Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

Our common stock has been quoted under the symbol “BRNC” on The Nasdaq Global Select Market since January 1, 2009, and on The Nasdaq Global Market from August 16, 2005 to December 31, 2008. The following table sets forth for the indicated periods the high and low sale prices of our common stock as quoted on those markets.

		High				Low
Year Ending December 31, 2009:
First Quarter		$	6.68			$	3.65
Second Quarter		$	6.68			$	4.09
Third Quarter		$	7.54			$	3.34
Fourth Quarter		$	8.64			$	4.60
Year ending December 31, 2010:
First Quarter		$	6.50			$	4.60
Second Quarter		$	5.07			$	3.34
Third Quarter		$	4.22			$	3.40
Fourth Quarter		$	8.07			$	3.95
Year ending December 31, 2011:
First Quarter (through February 28)		$	8.95			$	6.34

On February 28, 2011, the last reported sale price of our common stock on The Nasdaq Global Select Market was $8.95 and we had approximately 34 holders of record of our common stock.

Dividend Policy

We have never declared or paid dividends on our common stock, and we currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any payment of cash dividends will depend upon our financial condition, capital requirements, earnings and other factors deemed relevant by our board of directors. In addition, the terms of our credit facility prohibit us from paying dividends and making other distributions.

Equity Compensation Plan Information

The following table provides information as of December 31, 2010 with respect to shares of our common stock that may be issued under on our equity compensation plan:

Number of securities

remaining available for

Number of securities to be

Weighted-average

future issuance under equity

issued upon exercise of

exercise price per share

compensation plans

outstanding options,

of outstanding options,

(excluding securities

Plan category

warrants and rights

warrants and rights

reflected in column (a))

(a)

(b)

(c)

Equity compensation plans approved by security holders

—

$

—

2,549,878

Equity compensation plans not approved by security holders

—

—

—

Total

—

$

—

2,549,878

Item 6.		Selected Financial Data.

The following table sets forth our selected historical financial data as of and for each of the years indicated. We derived the selected historical financial data as of and for each of the years ended 2010, 2009, 2008, 2007 and 2006 from our historical audited consolidated financial statements. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated historical financial statements and related notes included elsewhere in this Form 10-K.

		Years Ended December 31,
		(in thousands, except per share amounts)
		2010				2009				2008				2007				2006
Consolidated Statements of Operations Information:
Contract drilling revenues		$	124,399			$	102,896			$	233,922			$	257,409			$	270,322
Costs and expenses:
Contract drilling			90,290				70,721				140,935				139,693				128,287
Depreciation and amortization			28,445				36,180				39,194				34,989				27,192
General and administrative			17,108				15,782				29,821				19,604				17,027
Gain on Challenger transactions			—				—				(2,252	)			—				—
Loss on Bronco MX transaction			1,487				23,705				—				—				—
Impairment of goodwill			—				—				21,115				—				—
Impairment of drilling rigs and related equipment			7,900				—				—				—				—
Loss on sale of drilling rigs and related equipment			23,732				—				—				—				—
Total operating costs and expenses			168,962				146,388				228,813				194,286				172,506
Income (loss) from continuing operations			(44,563	)			(43,492	)			5,109				63,123				97,816
Other income (expense):
Interest expense			(4,671	)			(6,933	)			(4,048	)			(5,030	)			(1,499	)
Loss from early extinguishment of debt			—				(2,859	)			(155	)			—				(1,000	)
Interest income			201				273				1,039				1,237				164
Loss on partial sale of investment in Bronco MX			(1,271	)			—				—				—				—
Equity in income (loss) of Challenger			(984	)			(1,914	)			2,186				—				—
Equity in income (loss) of Bronco MX			22				(588	)			—				—				—
Impairment of investment in Challenger			—				(21,247	)			(14,442	)			—				—
Other income (expense)			204				(383	)			(343	)			285				408
Change in fair value of warrant			(1,578	)			1,850				—				—				—
Total other income (expense)			(8,077	)			(31,801	)			(15,763	)			(3,508	)			(1,927	)
Income (loss) from continuing operations before tax			(52,640	)			(75,293	)			(10,654	)			59,615				95,889
Income tax expense (benefit)			(18,135	)			(27,151	)			(5,339	)			22,690				37,194
Income (loss) from continuing operations			(34,505	)			(48,142	)			(5,315	)			36,925				58,695
Income (loss) from discontinued operations			(16,172	)			(9,437	)			(2,928	)			667				1,138
Net income (loss)		$	(50,677	)		$	(57,579	)		$	(8,243	)		$	37,592			$	59,833
Income (loss) per common share-Basic
Continuing Operations		$	(1.27	)		$	(1.81	)		$	(0.20	)		$	1.42			$	2.39
Discontinued Operations		$	(0.60	)		$	(0.35	)		$	(0.11	)		$	0.03			$	0.04
Income (loss) per common share-Basic		$	(1.87	)		$	(2.16	)		$	(0.31	)		$	1.45			$	2.43
Income (loss) per common share-Diluted
Continuing Operations		$	(1.27	)		$	(1.81	)		$	(0.20	)		$	1.41			$	2.38
Discontinued Operations		$	(0.60	)		$	(0.35	)		$	(0.11	)		$	0.03			$	0.05
Income (loss) per common share-Diluted		$	(1.87	)		$	(2.16	)		$	(0.31	)		$	1.44			$	2.43
Weighted average number of shares outstanding-Basic			27,091				26,651				26,293				25,996				24,585
Weighted average number of shares outstanding-Diluted			27,091				26,651				26,293				26,101				24,623
Other Financial Data (Unaudited):
Calculation of Adjusted EBITDA (1):
Net income (loss)		$	(50,677	)		$	(57,579	)		$	(8,243	)		$	37,592			$	59,833
Interest expense			4,671				6,933				4,048				5,030				1,499
Income tax expense (benefit)			(18,135	)			(27,151	)			(5,339	)			22,690				37,194
Depreciation and amortization			28,445				36,180				39,194				34,989				27,192
Other adjustments related to discontinued operations			14,498				3,641				13,465				9,398				4,242
Other and non-recurring expense			40,204				48,905				35,557				—				—
Adjusted EBITDA (1)			19,006				10,929				78,682				109,699				129,960

		As of December 31,
		2010				2009				2008				2007				2006
Consolidated Balance Sheet Information:
Total current assets		$	51,547			$	43,077			$	107,821			$	72,019			$	73,372
Total assets			342,030				445,583				612,354				568,605				482,488
Total debt			6,825				51,903				117,547				68,118				64,727
Total liabilities			48,688				105,312				218,343				172,176				142,503
Total stockholders’/members’ equity			293,342				340,271				394,011				396,429				339,985

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

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Data” and the consolidated financial statements and related notes included elsewhere in this Form 10-K. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Form 10-K.

Overview

We provide contract land drilling services to oil and gas exploration and production companies throughout the United States. 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 building, 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 2010. In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to build, refurbish and repair our rigs and equipment in-house. This facility, which complements our two drilling rig refurbishment yards, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays in our rig building and refurbishment programs.

We have a 20% equity investment in Bronco MX, a company organized under the laws of Mexico. Bronco MX provides contract land drilling services and leases land drilling rigs to PEMEX and/or companies contracted with PEMEX. We also have a 25% equity investment in Challenger Limited, or Challenger, a company organized under the laws of the Isle of Man. Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with its principal operations in Libya.

Operating Segments

We currently conduct our operations through one operating segment: contract land drilling. In June of 2009 we made the decision to suspend operations in our well servicing segment because of deteriorating market conditions resulting from the rapid decrease in oil and natural gas prices which began in the third quarter of 2008, as well as the inability of many customers to obtain financing related to their drilling and workover programs. The following is a description of this operating segment.

Through the second quarter of 2010, we explored alternatives to restructure our well servicing segment. During Q1 and Q2 2010 the market for workover services continued at depressed levels within our primary geographic well servicing market (Oklahoma). Late in Q2 2010, we determined that higher NPV projects were available within our drilling segment and chose to deploy capital in this segment rather than commit the capital required to restructure operations in the well servicing segment.

In late June 2010 we made a decision to market the assets constituting the well servicing segment for sale and redeploy the proceeds to reduce debt and to support the Company’s core drilling business. We have presented all well servicing operating results as discontinued operations in our Consolidated Statements of Operations for all periods presented.

In September 2010, substantially all of the assets of the well servicing segment were sold at auction to multiple bidders. The Company had one workover rig held for sale at December 31, 2010, with a carrying amount of $130.

In September and November 2010, we sold at auction in separate lots to multiple bidders two complete drilling rigs and components comprising six other drilling rigs (rigs 2, 9, 51, 52, 54, 70, 75 and 94), and ancillary equipment. The drilling rigs and equipment sold at auction were not being utilized currently in our business. In an unrelated transaction on September 23, 2010, we sold two drilling rigs (rigs 41 and 42) in a private sale to Windsor Permian LLC, an unaffiliated third party. On November 29, 2010, the Company sold two drilling rigs (rigs 5 and 7) and entered into a contract to sell one drilling rig (rig 6) in a private sale to Atlas Drilling, LLC, an unaffiliated third party.

In February 2011, we entered into a contract to sell two drilling rigs (rigs 56 and 62) to Windsor Permian LLC, an unaffiliated third party. The drilling rigs and related equipment sold at auction and held for sale are being sold as part of a broader strategy by management to divest of older drilling rigs and use the proceeds to pay down existing indebtedness.

Our contract land drilling segment provides contract land drilling services. As of February 28, 2011, we owned a fleet of 25 marketed land drilling rigs. We currently operate our drilling rigs in Oklahoma, Texas, Pennsylvania, West Virginia, and North Dakota. A majority of the wells we drill for our customers are drilled in unconventional basins also known as resource plays. These plays are generally characterized by complex geologic formations that often require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 25 operating drilling rigs range from 650 to 2,000 horsepower. Accordingly, such rigs can, or in the case of inventoried rigs upon refurbishment, will be able to, reach the depths required and have the capability of drilling horizontal and directional wells, which are increasing as a percentage of total wells drilled in North America and are frequently utilized in unconventional resource plays. 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.

We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. We typically enter into drilling contracts that provide for compensation on a daywork basis. Occasionally we enter into drilling contracts that provide for compensation on a footage basis. We have not historically entered into turnkey contracts; however, we may decided to enter into such contracts in the future. It is also 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 20 of our drilling rigs operating under term contracts, 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 that we use to evaluate this segment 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.

For the three months ended December 31, 2010 and 2009 and years ended December 31, 2010, 2009, and 2008, our rig utilization rates, revenue days, and average number of marketed rigs were as follows:

		Three Months Ended
		December 31,								Years Ended December 31,
		2010				2009				2010				2009				2008
Average number of operating rigs			24				37				33				44				44
Revenue days			2,152				1,049				7,450				5,699				12,712
Utilization Rates			96	%			31	%			62	%			36	%			79	%

The increase in the number of revenue days in 2010 is due to the increase in oil and natural gas drilling activity in response to commodity prices and the availability of financing to our customers to fund their drilling programs. The decrease in the number of revenue days in 2009 is primarily attributable to the sharp decrease in oil and natural gas prices beginning in the third quarter of 2008 through 2009 as well as the inability of most customers to obtain financing related to their drilling programs.

Market Conditions in Our Industry

The United States contract land drilling and well servicing 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 revenue rates we can charge for our drilling 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 capital expenditure budgets of exploration and production companies our business depends on.

Our business environment was adversely affected by the decline in oil and natural gas prices and the deteriorating global economic environment beginning in the third quarter of 2008. As a result of this deterioration, there was and continues to be significant uncertainty in the capital markets and access to financing has been adversely impacted. As a result of these conditions, our customers reduced their exploration budgets which resulted in a significant decrease in demand for our services and a reduction in revenue rates and utilization. During 2010, demand for drilling activity improved as certain commodity prices strengthened in the latter half of the year. During 2010 the Company did not record any contract drilling revenue related to terminated contracts. During 2009 the Company recorded $7.9 million of contract drilling revenue related to terminated contracts. Due to the current economic environment, certain customers may not be able to pay suppliers, including us, if they are not able to access capital to fund their business operations.

On February 28, 2011, the closing prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX were $96.97 per barrel and $4.04 per MMbtu, respectively. The Baker Hughes domestic land drilling rig count as of February 28, 2011 was 1,674. 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.

The following table depicts the prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX, as well as the most recent Baker Hughes domestic land rig count, on the dates indicated:

		At December 31,
		2010				2009				2008
Crude oil (Bbl)		$	91.38			$	79.36			$	44.60
Natural gas (Mmbtu)		$	4.41			$	5.57			$	5.62
U.S. Land Rig Count			1,670				1,150				1,653

Increased expenditures for exploration and production activities generally lead to increased demand for our services. Until mid-2008, rising oil and natural gas prices and the corresponding increase in onshore oil and natural gas exploration and production spending led to expanded drilling and well service activity as reflected by the increases in the U.S. land rig counts over the previous several years. Falling commodity prices and the oversupply of rigs, similar to what we began experiencing in the third quarter of 2008, generally leads to lower demand for our services.

The decline in oil and natural gas prices and the deteriorating global economic environment resulted in reductions in our rig utilization and revenue rates in 2009. During 2010, these commodity prices strengthened and the overall demand for drilling activity increased in oil and natural gas resource plays. We expect continued increases in exploration and production spending in 2011, which we expect will result in modest increases in industry rig utilization and revenue rates in 2011, as compared to 2010. Continued fluctuations in the demand for gas and oil, among other factors including supply, could contribute to price volatility which may continue to affect demand for our services and could materially affect our future financial results.

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—Our contract land drilling segment earns revenues by drilling oil and natural gas wells for our customers typically under daywork contracts, which usually provide for the drilling of a single well. We occasionally enter into footage contracts, which also 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. We had no footage contracts in progress at December 31, 2010 and 2009. When we enter into footage contracts, we are more likely to encounter losses on them in years in which revenue rates are lower for all types of contracts.

Revenues and costs during a reporting period could be affected by jobs in progress at the end of a reporting period that have not been completed before our financial statements for that period are released. At December 31, 2010 and 2009, our unbilled receivables totaled $428,000 and $828,000, 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 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 $1.7 million and $3.6 million at December 31, 2010 and 2009, 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 one of our typical contracts, we would need to rely on applicable law to enforce our lien rights, because our 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 applicable law. If we were unable to drill to the agreed on depth in breach of a footage contract, we might also need to rely on equitable remedies to recover the fair value of our work-in-progress under a footage contract.

Asset Impairment and Depreciation— We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360, Accounting for the Impairment or Disposal of Long-Lived Assets. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and workover rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets for these asset grouping levels, then we would recognize an impairment charge. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment.

Goodwill impairment testing is performed at the level of our reporting units under the provisions of ASC Topic 350, Goodwill and Other Intangible Assets. Our reporting units have been determined to be the same as our operating segments, contract land drilling and well servicing. In our testing of possible impairment of goodwill, we compare the fair value of the reporting units with their carrying value. If the fair value exceeds the carrying value, no impairment is indicated. If the carrying value exceeds the fair value, we measure any impairment of goodwill in that reporting unit by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on their respective fair values. Any excess un-allocated fair value would equal the implied fair value of goodwill, and if that amount is below the carrying value of goodwill, an impairment charge is recognized.

In completing the first step of the goodwill impairment analysis during the fourth quarter of 2008, management used a five-year projection of discounted cash flows, plus a terminal value determined using a constant growth method to estimate the fair value of reporting units. In developing these fair value estimates, certain key assumptions included an assumed discount rate of 11.0% and 14.0% for our contract land drilling and well servicing segments, respectively, and an assumed long-term growth rate of 2.0% for both reporting units.

Based on the results of the first step of the goodwill impairment test, impairment was indicated in both reporting units. Management performed the second step of the analysis of its drilling and well servicing reporting units, allocating the estimated fair value to the identifiable tangible and intangible assets and liabilities of these reporting units based on their respective values. This allocation indicated no residual value for goodwill, and accordingly we recorded an impairment charge of $24.3 million in our December 31, 2008 statement of operations. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturn in our industry and decline in our projected cash flows. The Company has no goodwill after this impairment.

In the second quarter of 2010, management decided to sell the property and equipment of our well servicing segment. Management determined that the business was no longer consistent with our long-term strategic objectives. Since the well servicing property and equipment met the held for sale criteria, we were required to present its property and equipment held for sale at the lower of carrying amount or fair value less cost to sell. We evaluated well servicing’s respective assets held for sale for impairment. We engaged a third party independent appraisal company to determine the fair value of the well servicing assets. The analysis as of June 30, 2010 resulted in a $23.4 million impairment charge ($14.3 million after tax). This charge was recorded in the second quarter of 2010 and is reflected as a component of loss from discontinued operations in our Consolidated Statements of Operations.

In the third quarter of 2010, management made the decision to divest of older drilling rigs and use the proceeds to pay down existing indebtedness. Consequently, management decided to sell five drilling rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs met the held for sale criteria, we are required to present these assets held for sale at the lower of carrying amount or fair value less anticipated cost to sell. We evaluated these assets as of September 30, 2010, for impairment. The fair value of the drilling rigs was determined using level 3 inputs. The fair value was determined by the sale price of similar assets sold by us in an auction during the third quarter and negotiated prices with interested parties. The analysis as of September 30, 2010 resulted in a $7.8 million impairment charge. We recognized an additional impairment during the fourth quarter of approximately $139,000 related to assets held for sale.

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, 2010 and 2009, we did not capitalize any interest.

We review our equity investments for impairment based on the guidance of ASC Topic 323, Investments-Equity Method and Joint Venture, which states that a loss in value of an investment which is other than a temporary decline should be recognized. Evidence of a loss in value might include the absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. Due to the volatility and decline in oil and natural gas prices, a deteriorating global economic environment through 2009 and the anticipated future earnings of Challenger, we deemed it necessary to test the investment for impairment during 2008, 2009, and 2010.

Fair value of the investment was estimated using a combination of income, or discounted cash flows approach and the market approach, which utilizes comparable companies’ data. In developing our fair value estimates, certain key assumptions included an assumed discount rate of 14.5% and 16.5%, a control premium of 25.0% and 30.0% and a long-term growth rate of 4.0% and 4.0% for 2009 and 2008, respectively. The analysis resulted in a non-cash impairment charge of $14.4 million in 2008. The analysis resulted in a fair value of $39.8 million related to our investment in Challenger, as of September 30, 2009, which was below the carrying value of the investment and resulted in a non-cash impairment charge in the amount of $21.2 million in the statement of operations ended December 31, 2009.

In developing our fair value estimates, as of December 31, 2010, certain key assumptions included an assumed discount rate of 15.0%, a control premium of 22.1% and a long-term growth rate of 3.0%. The analysis resulted in a fair value of $40.9 million related to our investment in Challenger, which was above the carrying value of the investment and resulted in no impairment.

Recent civil and political disturbances in Libya elsewhere in North Africa, and the Middle East may affect Challenger’s operations. Ongoing political unrest may result in loss of revenue and damage to equipment. Any impact from the political turmoil and protests on Challenger’s operations could negatively impact the Company’s investment in Challenger. The current conditions may trigger additional impairment analysis during 2011 which could result in an impairment of our investment.

Stock Based Compensation—We have adopted ASC Topic 718, Stock Compensation, upon granting our first stock options on August 16, 2005. ASC Topic 718 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 $3.3 million, $3.3 million, and $5.8 million for 2010, 2009, and 2008, respectively.

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. Deferred tax assets are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Equity Method Investments—Investee companies that are not consolidated, but over which we exercise significant influence, are accounted for under the equity method of accounting. Whether or not we exercise significant influence with respect to an Investee depends on an evaluation of several factors including, among others, representation on the Investee company’s board of directors and ownership level, which is generally a 20% to 50% interest in the voting securities of the Investee company. Under the equity method of accounting, an Investee company’s accounts are not reflected within our Consolidated Balance Sheets and Statements of Operations; however, our share of the earnings or losses of the Investee company is reflected in the captions “Equity in income (loss) of Bronco MX” and “Equity in income (loss) of Challenger” in the Consolidated Statements of Operations. Our carrying value in an equity method Investee company is reflected in the captions “Investment in Bronco MX” and “Investment in Challenger” in our Consolidated Balance Sheets.

Other Accounting Estimates—Our other accrued expenses as of December 31, 2010 and December 31, 2009 included accruals of approximately $3.7 million and $2.5 million, respectively, for costs under our workers’ compensation insurance. We have a deductible of $500,000 per covered accident under our workers’ compensation insurance. We maintain letters of credit in the aggregate amount of $11.5 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. 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 in Review Highlights

The following are recent highlights that have impacted our results of operations for the year ended December 31, 2010.

Asset Sales and Held for Sale

On September 21, 2010 through September 23, 2010, we sold at auction in separate lots to multiple bidders two complete drilling rigs and components comprising four other drilling rigs (rigs 2, 9, 52, 70, 75 and 94), and ancillary equipment. The drilling rigs and equipment sold at auction were not being utilized currently in our business. We received net proceeds of approximately $8.3 million, net of selling expenses of $817,000, for the drilling rigs and related equipment. We recorded losses of $19.9 million related to the sale of the drilling rigs and ancillary equipment. The loss was based on net book values of approximately $28.2 million for the drilling rigs and ancillary equipment. We used the entire proceeds to pay down existing indebtedness under our revolving credit facility.

In an unrelated transaction on September 23, 2010, we sold two drilling rigs (rigs 41 and 42) in a private sale to Windsor Permian LLC, an unaffiliated third party, for estimated net proceeds of $7.2 million. We recorded a $1.7 million loss on the sale of these assets based on a net book value of $8.9 million.

The decision was made by management in the third quarter to sell an additional five drilling rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs met the held for sale criteria, we were required to present such assets, comprised of property and equipment, at the lower of carrying amount or fair value less the anticipated costs to sell. We evaluated these assets for impairment as of September 30, 2010, which resulted in recognizing a $7.8 million impairment charge which includes estimated selling expenses of approximately $125,000. At September 30, 2010, the fair value estimate was derived from the sale price of similar assets sold at auction during the third quarter and negotiated prices with interested parties. The drilling rigs and related equipment were presented as part of our land drilling segment.

On November 17, 2010, the Company sold at auction in separate lots to multiple bidders two complete drilling rigs (rigs 51 & 54) and ancillary equipment. The drilling rigs and equipment sold at auction were not being utilized currently in the Company’s business. The Company received net proceeds of approximately $1.7 million, net of selling expenses of $115,000, for the drilling rigs and related equipment. The Company recorded a loss of $2.2 million related to the sale of the drilling rigs and ancillary equipment. The loss was based on net book values of approximately $3.9 million for the drilling rigs and ancillary equipment.

On November 29, 2010, the Company sold two drilling rigs (rigs 5 and 7) in a private sale to Atlas Drilling, LLC, an unaffiliated third party, for estimated net proceeds of $2.7 million. The Company recorded a $14,000 gain on the sale of these assets based on a net book value of $2.7 million.

The Company believes the sale of rig 6 is probable within a year from the date on which we classified the drilling rig as held for sale. Because the drilling rig meets the held for sale criteria, the Company is required to present such assets, comprised of property and equipment, at the lower of carrying amount or fair value less the anticipated costs to sell. The carrying amount of the drilling rig and related equipment after impairment was $1.6 million at December 31, 2010, and is included in Non-current assets held for sale in our Consolidated Balance Sheets. The Company recognized an additional impairment during the fourth quarter of approximately $139,000 related to this rig. At December 31, 2010, the Company’s fair value estimate was derived from the negotiated prices with interested parties. The drilling rig and related equipment were included as part of our land drilling segment.

The drilling rigs and related equipment sold at auction and the drilling rig held for sale are being sold as part of a broader strategy by management to divest of older drilling rigs and use the proceeds to pay down existing indebtedness.

Well Servicing Segment

In June 2009, management made the decision to temporarily suspend operations in the well servicing segment. As previously discussed, market conditions had sharply deteriorated. The dramatic decline in activity was evident as revenue hours decreased 87% from a peak of 25,533 hours in the third quarter of 2008 to 3,374 hours in the second quarter of 2009. This represents a utilization rate of 75% and 10% for the respective quarters. The decrease in activity was coupled with similar erosions in pricing and margin. As such, the segment was unable to generate adequate rates of return on capital in the near future. Because the core drilling business is very capital intensive and was at the same time experiencing a similar slowdown, management felt it prudent to temporarily suspend operations in the well service segment.

Through the second quarter of 2010, Bronco senior management explored alternatives to restructure the well servicing segment. During Q1 and Q2 2010 the market for workover services continued at depressed levels within the primary geographic market of our well servicing assets (Oklahoma). Late in Q2 2010, management determined that higher NPV projects were available within the core drilling segment of the business and chose to deploy capital in this segment rather than commit the capital required to restructure operations in the well servicing segment.

In late June management made a decision to market the assets constituting the well servicing segment for sale and redeploy the proceeds to reduce debt and to support the Company’s core drilling business. Since the well servicing property and equipment met the held for sale criteria, we were required to present its property and equipment held for sale at the lower of carrying amount or fair value less cost to sell. Accordingly, in the second quarter of 2010, we evaluated well servicing’s respective assets held for sale for impairment. We engaged a third party independent appraisal company to determine the fair value of the well servicing assets. The analysis as of June 30, 2010 resulted in $23.4 million impairment charge ($14.3 million after tax). This charge was recorded in the second quarter of 2010 and is reflected as a component of income (loss) from discontinued operations in our Consolidated Statements of Operations.

In September 2010, substantially all of the assets of the well servicing segment were sold at auction to multiple bidders. We received proceeds of $12.4 million, net of selling expenses of $638,000. The sale of the assets of the well servicing segment resulted in a loss of $8.9 million, which is reflected as a component of loss from discontinued operations in our Consolidated Statements of Operations. We used the proceeds to pay down existing indebtedness under our revolving credit facility.

Bronco MX Joint Venture

In September of 2009, CICSA purchased 60% of the outstanding membership interests of Bronco MX from us. Immediately prior to the sale of the membership interests in Bronco MX to CICSA, the Company contributed six drilling rigs (Nos. 4, 43, 53, 58, 60 and 72), and the future net profit from rig leases relating to three additional drilling rigs (Nos. 55, 76 and 78), which the Company contributed to Bronco MX upon the expiration of the leases relating to such rigs.

The Company received $31.7 million from CICSA in exchange for the 60% membership interest in Bronco MX. CICSA also reimbursed the Company for 60% of the value added taxes previously paid by, or on behalf of, Bronco MX as a result of the importation of six drilling rigs that were contributed by the Company to Bronco MX to Mexico.

On July 1, 2010, CICSA contributed cash of approximately $45.1 million in exchange for 735,356,219 shares of Bronco MX. The cash contributed was used to purchase five drilling rigs. As a result of the contribution, our membership interest in Bronco MX was decreased to approximately 20%. We have accounted for the share issuance as if we had sold a proportionate amount of our shares. The Company recorded a loss on the transaction in the amount of $1.3 million, which is included in our consolidated statements of operations.

Bronco MX is jointly managed, with CICSA having four representatives on its board of managers and the Company having one representative on its board of managers. The Company and CICSA, and their respective affiliates, agreed to conduct all future land drilling and workover rig services, rental, construction, refurbishment, transportation, trucking and mobilization in Mexico and Latin America exclusively through Bronco MX, subject to Bronco MX’s ability to perform.

Global Financial Markets

Events, both within the United States and the world, have brought about significant and immediate changes in the global financial markets which in turn have affected the United States economy, our industry and us. In the United States, these events and others have had a significant impact on the prices for oil and natural gas as reflected in the following table:

		Natural Gas Price
		per Mcf								Oil Price per Bbl
Quarter		High				Low				High				Low
2010:
Fourth		$	4.61			$	3.29			$	91.51			$	79.49
Third		$	4.92			$	3.65			$	82.55			$	71.63
Second		$	5.19			$	3.91			$	86.79			$	68.01
First		$	6.01			$	3.84			$	83.76			$	71.19
2009:
Fourth		$	5.99			$	4.25			$	81.37			$	69.57
Third		$	4.88			$	2.51			$	74.37			$	59.52
Second		$	4.45			$	3.25			$	72.68			$	45.88
First		$	6.07			$	3.63			$	54.34			$	33.98
2008:
Fourth		$	7.73			$	5.29			$	98.53			$	33.87
Third		$	13.58			$	7.22			$	145.29			$	95.71
Second		$	13.35			$	9.32			$	140.21			$	100.98
First		$	10.23			$	7.62			$	110.33			$	86.99

As noted in the table, oil and natural gas prices declined significantly in late calendar 2008 and there was a deteriorating national and global economic environment. During 2009, the economic recession, including the decline in oil and natural gas prices and deterioration in the credit markets, had a significant effect on customer spending and drilling activity. When drilling activity and spending decline for any sustained period of time our dayrates and utilization rates also tend to decline. In addition, lower commodity prices for any sustained period of time could impact the liquidity condition of some of our customers, which, in turn, might limit their ability to meet their financial obligations to us.

The impact on our business and financial results as a consequence of the volatility in oil and natural gas prices and the global economic crisis is uncertain in the long term, but in the short term, it has had a number of consequences for us, including the following:

•

In December 2008, we incurred goodwill impairment of our contract land drilling and well servicing segments of $24.3 million due to the fair value of the segments being less than their carrying value;

•

In June 2009, we temporarily suspended operations in our well servicing segment;

•

In September 2009, we incurred an impairment charge to our investment in Challenger of $21.2 million due to the fair value of the investment being less than its carrying value;

•

In June 2010, management made a decision to sell the assets in the well servicing segment. We recorded a $23.4 million impairment charge ($14.3 million after tax).

•

In July 2010, subsequent to the end of our second quarter, we completed the sale of the property and equipment of our trucking assets for $11.3 million in cash, net of selling expenses in the amount of $403,000. Proceeds from this sale were used to repay existing indebtedness under our revolving credit facility with Banco Inbursa.

•

In September 2010, we sold at auction in separate lots to multiple bidders substantially all of the assets of our discontinued well servicing segment, two complete drilling rigs and components comprising four other drilling rigs (rigs 2, 9, 52, 70, 75 and 94), and ancillary equipment. We recorded losses of $8.9 million and $19.9 million from the sale of the assets of our well servicing segment and drilling rigs and related equipment, respectively.

•

In September 2010, we sold two drilling rigs (rigs 41 and 42) in a private sale to Windsor Permian LLC, an unaffiliated third party, for estimated proceeds of $7.2 million. We recorded a loss of $1.7 million on the sale of these assets.

Additionally, in the third quarter of 2010 management made the decision to continue to divest of smaller legacy mechanical rigs and invest the proceeds into new generation drilling rigs and equipment. That decision resulted in the following transactions.

•

In September 2010, management made a decision to sell five drilling rigs (rigs 5, 6, 7, 51 and 54). We recorded a $8 million impairment charge on these rigs.

•

In November 2010, we sold at auction in separate lots to multiple bidders two complete drilling rigs (rigs 51 and 54) and ancillary equipment. We recorded a loss of $2.2 million on the sale of these assets.

•

In November 2010, we sold two drilling rigs (rigs 5 and 7) and entered into a contract to sale one drilling rig (rig 6) in a private sale to Atlas Drilling, LLC, an unaffiliated third party, for estimated net proceeds of $4.5 million. The Company recorded a $14,000 gain on the sale of rigs 5 and 7.

•

In February 2011, we sold two drilling rigs (rigs 56 and 62) in a private sale to Windsor Permian LLC, an unaffiliated third party, for estimated proceeds of $11.5 million.

Results of Operations

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Contract Drilling Revenue. For the year ended December 31, 2010, we reported contract drilling revenues of approximately $124.4 million, a 21% increase from revenues of $102.9 million for 2009. The increase is primarily due to an increase in total revenue days and an increase in average dayrates. Revenue days increased 31% to 7,450 days for the year ended December 31, 2010 from 5,699 days during 2009. Average dayrates for our drilling services increased $455, or 3%, to $16,527 for the year ended December 31, 2010 from $16,072 in 2009. The increase in the number of revenue days for the year ended December 31, 2010 as compared to 2009 is attributable to the increase in our utilization rate. Utilization increased to 62% from 36% for the year ended December 31, 2010 as compared to 2009. The 72% increase in utilization was primarily due to the increase in demand for our services related to an increase in drilling activity as a result of higher oil and natural gas prices. For the year ended December 31, 2010, the Company did not record any contract drilling revenue related to terminated contracts compared to $7.9 million for 2009.

Equity in Income (Loss) of Challenger. Our equity in the loss of Challenger was $984,000 for the year ended December 31, 2010 compared to $1.9 million for the year ended December 31, 2009. The equity in loss of Challenger represents our 25% share of Challenger’s loss for 2010 and 2009. For the year ended December 31, 2010, Challenger had operating revenues of $49.3 million and operating costs of $36.7 million. For the year ended December 31, 2009, Challenger had operating revenues of $56.5 million and operating costs of $35.4 million. We reviewed our investment in Challenger at September 30, 2009 for impairment based on the guidance of ASC Topic 323, Investments-Equity Method and Joint Venture, which states that a loss in value of an investment which is other than temporary decline should be recognized. Due to the volatility and decline in oil and natural gas prices, a deteriorating global economic environment and the anticipated future earnings of Challenger in 2009, we deemed it necessary to test the investment for impairment. Fair value of the investment was estimated using a combination of income, or discounted cash flows approach, and the market approach, which utilizes comparable companies’ data. The analysis resulted in a fair value of $39.8 million for our investment in Challenger, which was below the carrying value of the investment and resulted in a non-cash impairment charge in the amount of $21.2 million for the year ended December 31, 2009. We performed an impairment analysis as of December 31, 2010 and based upon the results, we were not required to record additional impairments during the year ended December 31, 2010. During the first quarter of 2011, political instability and unrest occurred in Libya, which could result in additional impairments of our investment in challenger.

Equity in Income (Loss) of Bronco MX. Equity in income of Bronco MX was $22,000 for the year ended December 31, 2010. Equity in loss of Bronco MX was $588,000 for the period September 18 through December 31, 2009. The equity in income (loss) of Bronco MX represents our proportionate share of Bronco MX’s loss for 2010 and 2009. For the year ended December 31, 2010, Bronco MX had operating revenues of $34.1 million and operating costs of $33.4 million. For the period September 18 through December 31, 2009, Bronco MX had operating revenues of $7.2 million and operating costs of $9.8 million.

Contract Drilling Expense. Contract drilling expense increased $19.6 million to $90.3 million for the year ended December 31, 2010 from $70.7 million in 2009. This 28% increase is primarily due to the increase in the number of revenue days from 5,699 for the year ended December 31, 2009 to 7,450 for 2010. As a percentage of contract drilling revenue, drilling expense increased to 73% for the year ended December 31, 2010 from 69% in 2009 due primarily to revenue related to terminated contracts of $7.9 million for 2009.

Depreciation and Amortization Expense. Depreciation and amortization expense decreased $7.8 million to $28.4 million for the year ended December 31, 2010 from $36.2 million in 2009. The decrease is due to the contribution of nine drilling rigs to Bronco MX in the third quarter of 2009, the sale of our workover rig segment in the third quarter of 2010, and the sale of six complete drilling rigs and components comprising six other drilling rigs during 2010.

General and Administrative Expense. General and administrative expense increased $1.3 million, or 8%, to $17.1 million for the year ended December 31, 2010 from $15.8 million in 2009. This primarily resulted from a $2.0 million increase in accounts receivable write offs and a $309,000 increase in payroll costs. These increases were partially offset by a decrease in consulting fees of $942,000 and a decrease in professional fees of $405,000. The decreases in consulting fees and professional fees is due to expenses incurred during 2009 related to the Bronco MX transaction.

Interest Expense. Interest expense decreased $2.2 million to $4.7 million for the year ended December 31, 2010 from $6.9 million in 2009. The decrease is due to a decrease in the average outstanding balance under our credit facilities.

Income Tax Expense. We recorded an income tax benefit of $18.1 million for the year ended December 31, 2010. This compares to an income tax benefit of $27.2 million in 2009. This decrease is primarily due to a $22.7 million decrease in pre-tax loss to $52.6 million for the year ended December 31, 2010 from $75.3 million in 2009.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Contract Drilling Revenue. For the year ended December 31, 2009, we reported contract drilling revenues of approximately $102.9 million, a 56% decrease from revenues of $233.9 million for 2008. The decrease is primarily due to a decrease in total revenue days and a decrease in average dayrates. Revenue days decreased 55% to 5,699 days for the year ended December 31, 2009 from 12,712 days during 2008. Average dayrates for our drilling services decreased $1,565, or 9%, to $16,072 for the year ended December 31, 2009 from $17,637 in 2008. The decrease in the number of revenue days for the year ended December 31, 2009 as compared to 2008 is attributable to the decrease in our utilization rate. Utilization decreased to 36% from 79% for the year ended December 31, 2009 as compared to 2008. The 54% decrease in utilization was primarily due to decrease in demand for our services related to a decline in drilling activity as a result of lower oil and natural gas prices and a more competitive market resulting from an increase in the supply of drilling rigs. For the year ended December 31, 2009, the Company recorded $7.9 million of contract drilling revenue related to terminated contracts compared to $3.6 million for 2008.

Equity in Income (Loss) of Challenger. Our equity in the loss of Challenger was $1.9 million for the year ended December 31, 2009 compared to Equity in income of $2.2 million for the year ended December 31, 2008. The equity in income (loss) of Challenger represents our 25% share of Challenger’s income (loss) for 2009 and 2008. For the year ended December 31, 2009, Challenger had operating revenues of $56.5 million and operating costs of $35.4 million. For the year ended December 31, 2008, Challenger had operating revenues of $71.8 million and operating costs of $38.5 million. We reviewed our investment in Challenger at September 30, 2009 for impairment based on the guidance of ASC Topic 323, Investments-Equity Method and Joint Venture, which states that a loss in value of an investment which is other than temporary decline should be recognized. Due to the volatility and decline in oil and natural gas prices, a deteriorating global economic environment and the anticipated future earnings of Challenger, we deemed it necessary to test the investment for impairment during 2009. Fair value of the investment was estimated using a combination of income, or discounted cash flows approach, and the market approach, which utilizes comparable companies’ data. The analysis resulted in a fair value of $39.8 million for our investment in Challenger, which was below the carrying value of the investment and resulted in a non-cash impairment charge in the amount of $21.2 million.

Equity in Income (Loss) of Bronco MX. Equity in loss of Bronco MX was $588 for the period September 18 through December 31, 2009. The equity in loss of Bronco MX represents our 40% share of Bronco MX’s loss for 2009. For the period September 18 through December 31, 2009, Bronco MX had operating revenues of $7.2 million and operating costs of $9.2 million.

Contract Drilling Expense. Contract drilling expense decreased $65.0 million to $70.7 million for the year ended December 31, 2009 from $135.7 million in 2008. This 48% decrease is primarily due to the decrease in the number of revenue days from 12,712 for the year ended December 31, 2008 to 5,699 for 2009. As a percentage of contract drilling revenue, drilling expense increased to 69% for the year ended December 31, 2009 from 60% in 2008 due primarily to fixed costs on idle drilling rigs.

Depreciation and Amortization Expense. Depreciation and amortization expense decreased $3.0 million to $36.2 million for the year ended December 31, 2009 from $39.2 million in 2008. The decrease is due to the contribution of nine drilling rigs to Bronco MX in the third quarter of 2009.

General and Administrative Expense. General and administrative expense decreased $14.0 million, or 47%, to $15.8 million for the year ended December 31, 2009 from $29.8 million in 2008. This primarily resulted from a $4.5 million termination fee paid in 2008 related to our terminated merger with Allis-Chalmers Energy, Inc. The remainder of the decrease is due to a $3.3 million decrease in accounts receivable write-offs, $2.5 million decrease in stock compensation expense, a $1.4 million decrease in professional fees, a $1.0 million decrease in payroll costs, and a $564,000 decrease in yard expense. The decrease in stock compensation expense is primarily due to stock grants with higher grant date fair values becoming fully amortized. The other decreases are due to the overall decrease in activity for the company in the current year.

Interest Expense. Interest expense increased $2.9 million to $6.9 million for the year ended December 31, 2009 from $4.0 million in 2008. The increase is due to a decrease in the capitalization of interest expense related to our rig refurbishment program and an increase in the average outstanding balance under our credit facilities. We did not capitalize any interest in 2009 compared to $1.3 million of interest for the year ended December 31, 2008.

Income Tax Expense . We recorded an income tax benefit of $27.2 million for the year ended December 31, 2009. This compares to an income tax benefit of $5.3 million in 2008. This increase is primarily due to a $64.6 million increase in pre-tax loss to $75.3 million for the year ended December 31, 2009 from $10.7 million in 2008.

Liquidity and Capital Resources

Operating Activities. Net cash provided by operating activities was $38.3 million for 2010, $22.2 million for 2009, and $48.4 million in 2008. The increase of $16.1 million from 2009 to 2010 was primarily due to an increase in cash receipts from customers and lower 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. Net cash provided by investing activities was $3.0 million for 2010 and $19.0 million for 2009 compared to cash used of $75.0 million for 2008. In 2010, we received approximately $24.0 million in proceeds from the sale of assets and $911,000 from principal payments on note receivable, which were partially offset by $19.2 million used to purchase property and equipment. In 2009, we received $31.7 million from the sale of 60% of the outstanding membership interests in Bronco MX, proceeds of $635,000 from the sale of assets and principal payments on note receivable of $3.1 million, partially offset by $16.5 million used to purchase property and equipment. In 2008, approximately $5.1 million was used to obtain a 25% interest in Challenger, $76.8 million was used to purchase property and equipment, which amounts were partially offset by $4.0 million received from the sale of assets and $2.9 million received from a restricted cash account.

Financing Activities. We used cash for financing activities of $46.0 million for 2010 and $58.4 million for 2009 as compared to cash provided of $47.5 million for 2008. Our net cash used for financing activities for 2010 related to payments on our revolving credit facility with Banco Inbursa in the amount of $50.9 million, partially offset by borrowings of $5.0 million under our revolving credit facility with Banco Inbursa. Our net cash used for financing activities for 2009 related to us repaying in full our revolving credit facility with Fortis Bank SA/NV on September 18, 2009 in the amount of $111.1 million, and debt issue costs of $2.2 million, partially offset by borrowings of $55.0 million under our revolving credit facility with Banco Inbursa. Our net cash provided by financing for 2008 related to borrowings of $51.1 million under our credit facility with Fortis, partially offset by $3.5 million in debt issuance costs.

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

Debt Financing. On September 18, 2009, we entered into a new senior secured revolving credit facility with Banco Inbursa, as lender and as the issuing bank. We utilized (i) borrowings under the credit facility, (ii) proceeds from the sale of the membership interests of Bronco MX, and (iii) cash-on-hand to repay all amounts outstanding under our prior revolving credit agreement with Fortis Bank SA/NV.

The credit facility initially provided for revolving advances of up to $75.0 million and the borrowing base under the credit facility was initially set at $75.0 million, subject to borrowing base limitations. On February 9, 2011 we amended our credit facility which reduced the commitment to $45.0 million. The credit facility matures on September 17, 2014. Outstanding borrowings under the credit facility bear interest at the Eurodollar rate plus 5.80% per annum, subject to adjustment under certain circumstances.

We will pay a quarterly commitment fee of 0.5% per annum on the unused portion of the credit facility and a fee of 1.50% for each letter of credit issued under the facility. In addition, an upfront fee equal to 1.50% of the aggregate commitments under the credit facility was paid by us at closing. Our domestic subsidiaries have guaranteed the loans and other obligations under the credit facility. The obligations under the credit facility and the related guarantees are secured by a first priority security interest in substantially all of our assets and our domestic subsidiaries, including the equity interests of our direct and indirect subsidiaries. Commitment fees expense was $125,000 and $15,000 for the years ended December 31, 2010 and December 31, 2009, respectively.

The credit facility contains customary representations and warranties and various affirmative and negative covenants, including, but not limited to, 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, and a financial covenant requiring that we maintain a ratio of consolidated debt to consolidated earnings before interest, taxes, depreciation and amortization for any four consecutive fiscal quarters of not more than 3.5 to 1.0. We were in compliance with all covenants at December 31, 2010. A violation of these covenants or any other covenant in the credit facility could result in a default under the credit facility which would permit the lender to restrict our ability to access the credit facility and require the immediate repayment of any outstanding advances under the credit facility. The credit facility also provides for mandatory prepayments in certain circumstances.

In conjunction with our entry into the credit facility, we entered into a Warrant Agreement, pursuant to which we, issued a three-year warrant (the “Warrant”) to Banco Inbursa evidencing the right to purchase up to 5,440,770 shares of our common stock, $0.01 par value per share, subject to the terms and conditions set forth in the Warrant, including the limitations on exercise set forth below, at an exercise price of $6.50 per share of Common Stock from the date of issuance, September 18, 2009, of the Warrant (the “Issue Date”) through the first anniversary of the Issue Date, $7.00 per share following the first anniversary of the Issue Date through the second anniversary of the Issue Date, and $7.50 per share following the second anniversary of the Issue Date through the third anniversary of the Issue Date. The Warrant may be exercised by the payment of the exercise price in cash or through a cashless exercise whereby we withhold shares issuable under the Warrant having a value equal to the aggregate exercise price. Banco Inbursa subsequently transferred the Warrant to CICSA.

In accordance with accounting standards, the proceeds from the revolving credit facility were allocated to the credit facility and Warrant based on their respective fair values. Based on this allocation, $50.3 million and $4.7 million of the net proceeds were allocated to the credit facility and Warrant, respectively. The Warrant has been classified as a liability on the consolidated balance sheet due to our obligation to pay the seller of the Warrant a make-whole payment, in cash, under certain circumstances. The fair value of the Warrant was determined using a pricing model based on a version of the Black Scholes model, which is adjusted to account for the dilution resulting from the additional shares issued for the Warrant. The valuation was determined by computing the value of the Warrant if exercised in Year 1 — 3 with the values weighted by the probability that the Warrant would actually be exercised in that year. Some of the assumptions used in the model were a volatility of 45% and a risk free interest rate that ranged from 0.41% to 1.57%.

The resulting discount to the revolving credit facility will be amortized to interest expense over the term of the revolving credit facility such that, in the absence of any conversions, the carrying value of the revolving credit facility at maturity would be equal to $55.0 million. Accordingly, we will recognize annual interest expense on the debt at an effective interest rate of Eurodollar rate plus 6.25%.

In accordance with accounting standards, we revalued the Warrant as of December 31, 2010 and December 31, 2009 and recorded the change in the fair value of the Warrant on the consolidated statement of operations. The fair value of the Warrant was determined using a pricing model based on a version of the Black Scholes model, which is adjusted to account for the dilution resulting from the additional shares issued for the Warrant. The valuation was determined by computing the value of the Warrant if exercised in Year 1 — 3 with the values weighted by the probability that the warrant would actually be exercised in that year. Some of the assumptions used in the model were volatilities of 50% and 45% and a risk free interest rate that ranged from 0.22% to 0.54% and 0.40% to 1.45% for 2010 and 2009, respectively. The fair value of the Warrant was $4.4 million and $2.8 million at December 31, 2010 and December 31, 2009, respectively. We recorded a change in the fair value of the Warrant on the consolidated statement of operations in the amount of $1.6 million and $1.9 million for the years ended December 31, 2010 and December 31, 2009, respectively.

On January 13, 2006, we entered into our prior $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole book runner, and a syndicate of lenders. On September 29, 2008, we amended and restated this revolving credit facility. This $150.0 million amended and restated credit facility was with Fortis Bank SA/NV, New York Branch, as administrative agent, joint lead arranger and sole bookrunner, and a syndicate of lenders, which included The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., The Prudential Insurance Company of America, Legacy Bank, Natixis and Caterpillar Financial Services Corporation. Loans under the revolving credit facility bore interest at LIBOR plus a 4.0% margin or, at our option, the prime rate plus a 3.0% margin. We incurred $3.5 million in debt issue costs related to the amended and restated credit facility.

This revolving credit facility provided 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 year ended December 31, 2009 was $447,000.

This revolving credit facility was repaid in full on September 18, 2009. We incurred a loss from early extinguishment of debt of approximately $2.9 million.

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 conjunction with our entry into our senior secured revolving credit facility with Banco Inbursa, we issued a three-year warrant to Banco Inbursa evidencing the right to purchase up to 5,440,770 shares of our common stock, $0.01 par value per share, subject to the terms and conditions set forth in the Warrant. Banco Inbursa subsequently transferred the Warrant to CICSA. Pursuant to the terms of the Warrant, we cancelled the Warrant issued to Banco Inbursa and issued a warrant to CICSA evidencing such transfer.

Capital Expenditures.

During 2010, we incurred aggregate refurbishment costs of $7.3 million related to enhancements and refurbishments of rigs for opportunities domestically and incurred $8.0 million for the purchase of top drives to upgrade our fleet.

During 2009, we incurred aggregate refurbishment costs of $13.4 million related to enhancements and refurbishments of rigs related to international expansion in Mexico and new opportunities domestically and incurred $2.7 million for the purchase of top drives to upgrade our rig fleet. We also incurred $859,000 in costs related to the refurbishment of workover rigs.

During 2008, we incurred aggregate refurbishment costs of $54.4 million related to newbuilds, enhancements and refurbishments of rigs related to international expansion in Libya and Mexico and new plays domestically. We also incurred $5.1 million in costs related to the purchase and refurbishment of workover rigs.

Working Capital. Our working capital was $35.7 million at December 31, 2010, compared to $25.3 million at December 31, 2009. Our current ratio, which we calculate by dividing our current assets by our current liabilites, was 3.2 at December 31, 2010 compared to 2.4 at December 31, 2009.

We believe that the liquidity shown on our balance sheet as of December 31, 2010, which includes approximately $35.7 million in working capital (including $11.9 million in cash) and availability under our then $75.0 million credit facility of $54.4 million at December 31, 2010 (net of outstanding letters of credit of $11.5 million), together with cash expected to be generated from operations, provides us with sufficient ability to fund our operations for at least the next twelve months. We believe the reduction in our credit facility to $45.0 million will not materially impact our liquidity. 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. The changes in the components of our working capital were as follows (amounts in thousands):

		December 31,
		2010				2009				Change
Cash and cash equivalents		$	11,854			$	9,497			$	2,357
Restricted cash			2,700				—				2,700
Trade and other receivables			24,656				15,306				9,350
Affiliate receivables			1,508				9,620				(8,112	)
Unbilled receivables			428				828				(400	)
Income tax receivable			5,700				3,800				1,900
Current deferred income taxes			2,765				1,360				1,405
Current maturities of note receivable			1,607				2,000				(393	)
Prepaid expenses			329				666				(337	)
Current assets			51,547				43,077				8,470
Current debt			95				89				6
Accounts Payable			7,945				9,756				(1,811	)
Accrued liabilities and deferred revenues			7,847				7,952				(105	)
Current liabilities			15,887				17,797				(1,910	)
Working capital		$	35,660			$	25,280			$	10,380

The increase in cash and cash equivalents and restricted cash at December 31, 2010 as compared to December 31, 2009 was primarily due the sale of six complete drilling rigs and components comprising six other drilling rigs and our well servicing segment and trucking operations which resulted in net proceeds of $43.6 million as well as the decrease in affiliate receivables of $8.1 million, partially offset by the payments on our revolving credit facility with Banco Inbursa, in the amount of $50.9 million. The increase in cash is also attributable to an overall increase in drilling activity for 2010. Revenue days for the year ended December 31, 2010 were 7,450 compared to 5,699 for 2009.

The increase in trade receivables and other receivables at December 31, 2010 as compared to December 31, 2009 was due to an increase in revenue days and utilization rates during 2010 compared to 2009. Utilization for the year ended December 31, 2010 was 62% compared to 36% for 2009. Revenue days for the year ended December 31, 2010 were 7,450 compared to 5,699 for 2009.

The decrease in affiliate receivables at December 31, 2010 as compared to December 31, 2009 was mainly due to $7.1 million in payments received from Bronco MX.

Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments at December 31, 2010 (in thousands):

		Payments Due by Period
						Less than 1												More than 5
Contractual Obligations		Total				year				1-3 years				4-5 years				years
Short and long-term debt		$	10,373			$	95			$	9,423			$	855			$	—
Interest on long-term debt			2,478				625				1,685				89				79
Operating lease obligations			2,032				770				1,185				77				—
Total		$	14,883			$	1,490			$	12,293			$	1,021			$	79

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements.

Recent Accounting Pronouncements

In December 2010, the FASB issued an accounting standard update that addresses the disclosure of supplementary pro forma information for business combinations. This update clarifies that when public entities are required to disclose pro forma information for business combinations that occurred in the current reporting period, the pro forma information should be presented as if the business combination occurred as of the beginning of the previous fiscal year when comparative financial statements are presented. This update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. The Company is currently evaluating the impact, if any, the adoption will have on our consolidated financial statements.

In January 2010, the FASB issued a new accounting standard which requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established by ASC 820, Fair Value Measurements. Also required will be a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments. Entities will have to provide fair value measurement disclosures for each class of financial assets and liabilities. The guidance will be effective for fiscal years beginning after December 15, 2010. We are currently evaluating the impact, if any, the adoption will have on our consolidated financial statements.

In December 2009, the FASB issued a new accounting standard which updates the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which reporting entity has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (1) the obligation to absorb losses of the entity or (2) the right to receive benefits from the entity. An approach that is expected to be primarily qualitative will be more effective for identifying which reporting entity has a controlling financial interest in a variable interest entity. The amendments in this update also require additional disclosures about an reporting entity’s involvement in variable interest entities, which will enhance the information provided to users of financial statements. This new standard is effective at the start of a reporting entity’s first fiscal year beginning after January 1, 2010. The adoption of this standard did not impact our consolidated financial statements.

In October 2009, the FASB issued a new accounting standard that addresses the accounting for multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately rather than as a combined unit. This new standard addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing accounting standards require a vendor to use objective and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a multiple-deliverable arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be separated in more circumstances than under current requirements. The new standard establishes a hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to multiple deliverables. The selling price used will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific objective evidence nor third-party evidence is available. The new standard must be prospectively applied to all revenue arrangements entered into in fiscal years beginning on or after June 15, 2010 and became effective for us on January 1, 2011. We are currently evaluating the impact, if any, the adoption will have on our consolidated financial statements.

In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this new standard, generally accepted accounting principles required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. This new standard is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. This new standard became effective for us on January 1, 2010. The adoption of this standard did not impact our consolidated financial statements.

Item 7A.		Quantitative and Qualitative Disclosures About Market Risk.

We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. Borrowings under our revolving credit facility bear interest at a floating rate equal to LIBOR plus a margin of 5.80%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $56,000 annually, based on the $9.1 million outstanding in the aggregate under our credit facility as of December 31, 2010.

Item 8.		Financial Statements and Supplementary Data.

Our Financial Statements begin on page 49 of this Form 10-K, Index to Consolidated Financial Statements, and are incorporated herein by this reference.

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

None.

Item 9A.		Controls and Procedures.

Evaluation of Disclosure Control and Procedures.

As of the end of the period covered by this Annual Report on Form 10-K, our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2010 our disclosure controls and procedures are effective.

Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and include controls and procedures designed to ensure that information is accumulated and communicated to our management, and made known to our Chief Executive Officer and Chief Financial Officer, particularly during the period when this Annual Report on Form 10-K was prepared, as appropriate to allow timely decision regarding the required disclosure.

Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:

(i)

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of our company;

(ii)

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and

(iii)

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

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

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, conducted its evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Although there are inherent limitations in the effectiveness of any system of internal controls over financial reporting, based on our evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2010.

The independent registered public accounting firm that audited the Company’s financial statements, Grant Thornton LLP, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting. This report appears below.

Changes in Internal Controls over Financial Reporting.

There were no changes in internal control over financial reporting during the fourth quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Report of Independent Registered Public Accounting Firm

Board of Directors
Bronco Drilling Company, Inc.

We have audited Bronco Drilling Company, Inc.’s (the “Company”) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010 and our report dated March 15, 2011 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 15, 2011