Filed Pursuant to Rule 424(b)(4)
Registration No. 333-128861
Registration No. 333-129285

PROSPECTUS

3,500,000 Shares

Bronco Drilling Company, Inc.

Common Stock

We are offering 3,500,000 shares of our common stock.

Our common stock is quoted on The Nasdaq National Market under the symbol “BRNC.” On October 27, 2005, the last sale price of our common stock as reported on The Nasdaq National Market was $23.26 per share.

Investing in our common stock involves risks. See “ Risk Factors” beginning on page 11.

	Public Offering Price	Underwriting Discount	Proceeds to Bronco (Before Expenses)
Per Share	$23.00	$1.265	$21.735
Total	$80,500,000	$4,427,500	$76,072,500

We have granted to the underwriters a 30-day option to purchase up to 525,000 shares of our common stock to cover any overallotments.

Delivery of the shares of common stock will be made on or about November 2, 2005.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Johnson Rice & Company L.L.C. Jefferies & Company, Inc.

Friedman Billings Ramsey Raymond James

The date of this prospectus is October 28, 2005.

[Photo of rig in Oklahoma]

TABLE OF CONTENTS

Prospectus Summary	1
Risk Factors	11
Cautionary Note Regarding Forward-Looking Statements	23
Use of Proceeds	24
Price Range of Common Stock	25
Dividend Policy	25
Capitalization	26
Dilution	28
Selected Historical Financial Data	29
Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Business	44
Management	64
Certain Relationships and Related Party Transactions	69
Principal Stockholders	71
Description of Capital Stock	73
Securities Eligible for Future Sale	76
Underwriting	77
Legal Matters	79
Experts	79
Where You Can Find More Information	79
Index to Unaudited Pro Forma Combined Financial Statements	P-1
Index to Consolidated Financial Statements	F-1

You may rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with additional information or information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer to sell is not permitted. The information appearing in this prospectus is current, accurate and complete in all material respects as of the date on the front cover of this prospectus, but our business, financial condition, results of operations and prospects may have changed since that date.

i

PROSPECTUS SUMMARY

This summary highlights certain information contained elsewhere in this prospectus. This summary does not contain all of the information you should consider before investing in our common stock. You should carefully read the entire prospectus, including “Risk Factors” and our consolidated financial statements and related notes included elsewhere in this prospectus, before you decide whether to invest in our common stock. Unless otherwise indicated in this prospectus or the context otherwise requires, all references in this prospectus to “Bronco,” the “Company,” “us,” “our” or “we” are to Bronco Drilling Company, Inc. and our predecessor company, Bronco Drilling Company, L.L.C., and their respective subsidiaries.

BRONCO DRILLING COMPANY

Overview

We provide contract land drilling services to oil and natural gas exploration and production companies. We currently own a fleet of 58 land drilling rigs, of which 30 are currently operating, six are in the process of being refurbished and 22 are held in inventory. We expect to put four of the rigs currently being refurbished into service by the end of 2005 and the other two into service by the end of the first quarter of 2006. In addition we plan on refurbishing eight additional rigs from our current inventory during 2006, at estimated costs (including drill pipe) ranging from $4.1 million to $6.8 million per rig. Initially, we intend to focus our refurbishment program on our more powerful rigs, with 1,000 to 2,000 horsepower, which are capable of drilling to depths between 15,000 and 25,000 feet. We also own a fleet of 41 trucks used to transport our rigs.

We commenced operations in 2001 with the purchase of one stacked 650-horsepower rig that we refurbished and deployed. We subsequently made selective acquisitions of both operational and inventoried rigs, as well as ancillary equipment. Our most recent acquisitions were completed in October 2005, when we purchased 12 land drilling rigs from Eagle Drilling, L.L.C. for approximately $50.0 million and 13 land drilling rigs from Thomas Drilling Co. for approximately $68.0 million. These transactions not only increased the size of our rig fleet, but also expanded our operations to the Barnett Shale trend in North Texas. See “—Recent Developments” below for additional information regarding these acquisitions. In July 2005, we completed a transaction with Strata Drilling, L.L.C. and Strata Property, L.L.C. in which we acquired, among other assets, three land drilling rigs and a 16 acre storage and refurbishment yard for $20.0 million.

Our management team has significant experience not only with acquiring rigs, but also with refurbishing and deploying inventoried rigs. We have successfully refurbished and brought into operation eight of the 22 inventoried drilling rigs we acquired in August 2003. These rigs were refurbished on schedule and for a total cost that was within ten percent of the amount budgeted. Upon completion of refurbishment, the rigs either met or exceeded our operating expectations. In addition, we have recently opened a 41,000 square foot machine shop in Oklahoma City which allows us to refurbish and repair our rigs and equipment in-house. This facility, which complements our existing rig yard in Oklahoma City, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays.

We currently operate in Oklahoma, the Barnett Shale trend in North Texas and the Piceance Basin in Colorado. A majority of the wells we have drilled for our customers have been drilled in search of natural gas reserves. Natural gas is often found in deep and complex geologic formations that generally require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 58 rigs includes 30 rigs ranging from 950 to 2,500 horsepower. Accordingly, such rigs can, or in the case of inventoried rigs upon refurbishment will be able to, reach the depths required to explore for deep natural gas reserves. Our higher horsepower rigs can also drill horizontal wells, which are increasing as a percentage of total wells drilled in North America. We believe our premium rig fleet, rig inventory and experienced crews position us to benefit from the strong natural gas drilling activity in our core operating area.

1

Recent Developments

We recently completed two acquisitions that have further expanded our fleet of land drilling rigs.

• The Eagle Acquisition.  On October 3, 2005, we purchased 12 rigs from Eagle Drilling, L.L.C. and two of its affiliates. This acquisition involved five operating rigs, seven inventoried rigs and rig equipment and parts for a purchase price of approximately $50.0 million. We intend to refurbish two rigs from inventory by the end of 2006 for a total cost of approximately $11.9 million. We estimate that our costs to refurbish the remaining five inventoried rigs will range from $900,000 to $6.0 million per rig.

• The Thomas Acquisition.  On October 14, 2005, we purchased 13 rigs from Thomas Drilling Co. The transaction included nine operating rigs, two rigs currently being refurbished, two inventoried rigs and rig equipment and parts for a purchase price of approximately $68.0 million. In connection with this acquisition, we leased an additional rig refurbishment yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000. We intend to use the Thomas yard to complete the refurbishment of two Thomas rigs in 2006. We estimate our total cost to complete the refurbishment of these rigs will be approximately $4.6 million. We estimate that our costs to refurbish the remaining rigs will be approximately $1.7 million per rig.

Upon completion of the Eagle and Thomas acquisitions, our rig fleet increased to 58 rigs, 30 of which are operating rigs and 28 of which are either in the refurbishment process or held in inventory. Seven of the rigs included in the Eagle and Thomas acquisitions are operating in Texas, including six in the Barnett Shale trend in North Texas, with the balance of the operating rigs drilling in Oklahoma. For additional information regarding these transactions, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Business—General” and “—Our Fleet of Drilling Rigs.”

The following table presents information regarding our rig fleet (a) as of September 30, 2005 prior to the Eagle and Thomas acquisitions and (b) upon completion of the Eagle and Thomas acquisitions in October 2005.

	Rig Fleet
	Operating	In Refurbishment Process	In Inventory	Total
As of September 30, 2005	16	4	13	33
Eagle Drilling acquisition	5	0	7	12
Thomas Drilling acquisition	9	2	2	13
Total	30	6	22	58

2

Our Industry

We believe that the following trends in our industry should benefit our operations:

• Need for increased natural gas drilling activity as U.S. demand growth outpaces U.S. supply growth.  From 1994 to 2003, demand for natural gas in the United States grew at an annual rate of 0.6% while the U.S. domestic supply grew at an annual rate of 0.2%. The Energy Information Administration, or EIA, recently estimated that U.S. domestic consumption of natural gas exceeded domestic production by 17% in 2004, a gap that the EIA forecasts will expand to 24% in 2010.

Source:  EIA.

• Increased decline rates in natural gas basins in the U.S.  As the chart above shows, even though the number of U.S. natural gas wells drilled has increased significantly, a corresponding increase in production has not been realized. We believe that a significant reason for the limited supply response, even as drilling activities have increased, is the accelerating decline rates of production from new natural gas wells drilled. A study published by the National Petroleum Council in September 2003 concluded, from analysis of production data over the preceding ten years, that as a result of domestic natural gas decline rates of 25% to 30% per year, 80% of natural gas production in ten years will be from wells that have not yet been drilled. We believe that this tends to support a sustained higher natural gas price environment, which should create incentives for oil and natural gas exploration and production companies to increase drilling activities in the U.S.

3

• Trend towards drilling and developing unconventional natural gas resources.  As a result of improvements in extraction technologies along with general increases in natural gas prices, oil and natural gas companies increasingly are exploring for and developing “unconventional” natural gas resources, such as natural gas from tight sands, shales and coalbed methane. This type of drilling activity is frequently done on tighter acreage spacing and requires that more wells be drilled. It also requires higher horsepower rigs for techniques such as horizontal drilling.

• High natural gas prices.  While U.S. natural gas prices are volatile, year to date 2005 marks the third consecutive year of increases in the yearly average NYMEX near month natural gas contract prices, as shown on the chart below. We believe that high natural gas prices in the U.S., if sustained, should result in more exploration and development drilling activity, and thus higher utilization and dayrates for drilling companies like us.

Source:  Bloomberg.

• Increases in dayrates and operating margins for land drilling.  The increase in the price of natural gas, coupled with accelerating decline rates and an increase in the number of natural gas wells being drilled, have resulted in increases in rig utilization, and consequently improved dayrates and cash margins.

4

Our Strengths

Our competitive strengths include:

• Premium rig fleet.  We currently operate a fleet of 30 rigs, eleven of which have been refurbished since August 2003. Natural gas reserves are often found in deep and complex geological formations that require higher horsepower or premium rigs to drill. In addition, the recovery of unconventional natural gas resources often involves horizontal drilling techniques that also require premium rigs with approximately 1,000 or more horsepower. We believe that our operating history and high-quality rig fleet position us to benefit from this type of drilling activity.

• Inventory of drilling rigs and ancillary equipment.  In addition to our six rigs currently being refurbished, our 22 drilling rigs held in inventory for refurbishment will allow us to add capacity in response to the currently strong land drilling market. We also have an inventory of excess drawworks, hooks, blow-out preventors and other rig-related equipment. Our inventoried rigs as well as many of the parts we have in inventory would have long delivery lead times if ordered new.

• Ability to refurbish inventoried rigs.  Our management team has demonstrated the ability to refurbish rigs from our inventory. Since our acquisition of 22 inventoried drilling rigs in August 2003, we have successfully refurbished and placed into service eight of the rigs at costs ranging from $2.2 million to $6.6 million per rig. Through the efforts of our management team and experienced yard labor crews, these rigs were refurbished on schedule and for a total cost that was within ten percent of the amount budgeted. We are currently refurbishing six additional rigs, five of which range from 1,000 to 1,700 horsepower. We expect four of these rigs to be ready for deployment by the end of 2005 and the other two of these rigs to be ready for deployment by the end of the first quarter of 2006. In connection with the Thomas acquisition, we leased the use of an additional refurbishment yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000.

• Ability to attract and retain qualified rig crews.  We believe that our premium rig fleet and experienced management team allow us to successfully attract and retain qualified rig crews relative to some larger, more diversified land drilling companies. As a result, we believe we have been able to refurbish rigs from our inventory and put them into operation without sacrificing our operating quality.

Our Challenges

We face a number of challenges in capitalizing on our strengths and implementing our strategies. For example:

• 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.

• A material reduction in the levels of exploration and development activities or an increase in the number of rigs mobilized to our market areas could decrease our dayrates and utilization rates.

• Our revenues and profitability could be negatively impacted if we are unable to successfully complete the refurbishment of our inventoried rigs on schedule and within budget and use those and the other rigs in our fleet at profitable levels.

5

• We operate in a highly competitive, fragmented industry in which price competition is intense.

For further discussion of these and other challenges we face, see “Risk Factors” beginning on page 11.

Our Strategy

Our strategy is to continue to expand our contract land drilling services. Specifically, we intend to:

• Refurbish and deploy rigs from our inventory.  We intend to continue the refurbishment and deployment of our inventoried rigs. We plan on completing the refurbishment of four rigs that are currently being refurbished by the end of 2005 and two by the end of the first quarter of 2006. We also intend to refurbish eight more rigs from our current inventory during 2006 at estimated costs ranging from $4.1 million to $6.8 million per rig. Initially, we intend to focus our refurbishment program on our higher horsepower rigs. As a result of the Thomas acquisition, we added the use of an additional rig refurbishment yard. We have recently hired additional experienced refurbishing crews, which we believe will complement the experienced crews we currently have in place. Our five rig-up supervisors have an average of 31 years of experience in the drilling industry.

• Expand our rig fleet and geographic focus.  We intend to continue to expand our rig fleet and geographic areas of operation by making selected acquisitions and mobilizing rigs to other regions. We are currently operating in Oklahoma, the Barnett Shale trend in North Texas and the Piceance Basin in Colorado. We began operations in the Barnett Shale with seven rigs through our recent Eagle and Thomas acquisitions. In addition, we are evaluating additional expansion opportunities in the Rocky Mountains and the Cotton Valley trend in Central and East Texas. We also regularly evaluate other potential acquisitions of rigs and ancillary operations.

• Maintain a balanced portfolio of spot and term contracts.  We plan on managing our rig fleet as a portfolio, committing some of our rigs to longer-term contracts that meet our targeted returns on invested capital, and leveraging spot market rates with other rigs. As we expand our geographic focus, we initially plan on favoring longer-term contracts in our new markets until we gain operating maturity in those markets.

• Maintain a conservative capital structure and disciplined approach to capital spending.  We believe that our post-offering balance sheet will allow us to pursue opportunities to grow our business. We will continue to evaluate investment opportunities, including potential acquisitions and additional rig refurbishments, that meet our targeted returns on invested capital.

Our Equity Sponsor

We were formed by affiliates of Wexford Capital LLC (“Wexford”) in June 2001. Wexford is a Greenwich, Connecticut based SEC registered investment advisor with approximately $3.0 billion under management as of June 30, 2005. Wexford has made private equity investments in many different sectors with particular expertise in the energy and natural resources sector. Prior to this offering, Wexford beneficially owned approximately 68% of our outstanding common stock through Bronco Drilling Holdings, L.L.C., an entity controlled by Wexford. Upon completion of the offering, Wexford will beneficially own approximately 58% of our common stock (approximately 57% if the overallotment option is exercised in full) through Bronco Drilling Holdings.

Our Offices

Our principal executive offices are located at 14313 North May Avenue, Oklahoma City, Oklahoma 73134, and our telephone number is (405) 242-4444. Our website address is www.broncodrill.com. Information contained on our website does not constitute part of this prospectus.

6

The Offering

Common stock offered by Bronco 3,500,000 shares

Common stock to be outstanding after this offering 22,640,368 shares

Use of proceeds We intend to use a portion of the net proceeds from the sale of shares of our common stock in this offering to repay approximately $50.0 million in borrowings incurred in connection with our Thomas acquisition under a loan we entered into with Theta Investors LLC, an entity controlled by Wexford. We intend to use the balance of the net proceeds, together with cash from operations, to refurbish rigs in our inventory and for general corporate purposes, which may include the purchase of additional rigs. Pending the use of the remaining net proceeds for refurbishment and general corporate purposes, we may repay a portion of our borrowings under our Merrill Lynch term installment loan. For additional information regarding our borrowings, see “Use of Proceeds.”

Dividend policy 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.

The Nasdaq National Market symbol “BRNC”

Risk factors We are subject to a number of risks that you should carefully consider before deciding to invest in our common stock. These risks are discussed more fully in “Risk Factors.”

Except as otherwise indicated, all information contained in this prospectus:

• assumes the underwriters do not exercise their overallotment option; and

• excludes 500,000 shares of our common stock issuable upon the exercise of outstanding options, at a weighted average exercise price of $17.92 per share.

7

Summary Historical and Pro Forma Financial Data

The following table sets forth our summary historical and pro forma financial data as of and for each of the years and interim periods indicated. The summary historical financial data are derived from our historical audited consolidated financial statements for the years indicated and from our historical unaudited consolidated financial statements for the interim periods indicated. The interim unaudited information was prepared on a basis consistent with that used in preparing our audited consolidated financial statements and includes all adjustments, consisting of normal and recurring items, that we consider necessary for a fair presentation of the financial position and results of operations for the unaudited periods. Operating results for the six months ended June 30, 2005 are not necessarily indicative of results that may be expected for the entire year 2005. The summary unaudited pro forma financial data for the year ended December 31, 2004 and the six months ended June 30, 2005 give effect to certain events identified in the Bronco Drilling Company, Inc. Unaudited Pro Forma Combined Consolidated Financial Statements appearing elsewhere in this prospectus, including our acquisition of Strata Drilling, L.L.C. and Strata Property, L.L.C. in July 2005, and our acquisition of Thomas Drilling Co. in October 2005 as if such acquisitions had occurred on January 1, 2004, but not our recently completed acquisitions of Hays Trucking, Inc., which was not a financially significant acquisition, or Eagle Drilling, L.L.C. and its affiliates, for which audited financial statements are not currently available. The summary unaudited pro forma financial data are based on certain assumptions and adjustments and do not purport to reflect what our actual results of operations would have been had such acquisitions in fact occurred on January 1, 2004, nor are they necessarily indicative of the results of operations that we may achieve in the future. You should review this information together with the Bronco Drilling Company, Inc. Unaudited Pro Forma Combined Consolidated Financial Statements, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated historical financial statements and related notes included elsewhere in this prospectus.

8

	Pro Forma Six Months Ended June 30,			Six Months Ended June 30,						Pro Forma Year Ended December 31,			Year Ended December 31,
	2005			2005			2004			2004			2004			2003			2002
				(Unaudited)
	(In thousands, except per share amounts)
Consolidated Statements of Operations Information:
Contract drilling revenues	$	38,170		$	20,269		$	7,758		$	46,932		$	21,873		$	12,533		$	3,115
Costs and expenses:
Contract drilling		20,426			12,870			6,937			28,355			18,670			10,537			3,239
Depreciation		5,114			2,851			1,534			8,222			3,695			1,985			1,122
General and administrative		7,864			1,123			686			12,198			1,714			1,226			676
Total operating costs and expenses		33,404			16,844			9,157			48,775			24,079			13,748			5,037
Income (loss) from operations		4,766			3,425			(1,399	)		(1,843	)		(2,206	)		(1,215	)		(1,922	)
Other income (expense):
Interest expense		(423	)		(309	)		(48	)		(622	)		(285	)		(21	)		—
Interest income		33			12			5			29			10			3			5
Other income		561			—			—			155			—			—			—
Gain on sale of assets		—			—			—			251			—			—			—
Total other income (expense)		171			(297	)		(43	)		(187	)		(275	)		(18	)		5
Income (loss) before income taxes		4,937			3,128			(1,442	)		(2,030	)		(2,481	)		(1,233	)		(1,917	)
Deferred tax expense (benefit)		1,861			(231	)		(85	)		(765	)		285			317			—
Net income (loss)	$	3,076		$	3,359		$	(1,357	)	$	(1,265	)	$	(2,766	)	$	(1,550	)	$	(1,917	)
Pro Forma C Corporation Data: (1)
Historical income (loss) from operations before income taxes				$	3,128		$	(1,442	)				$	(2,481	)	$	(1,233	)	$	(1,917	)
Pro forma provision (benefit) for income taxes attributable to operations					1,181			(544	)					(936	)		(465	)		(723	)
Pro forma income (loss) from operations				$	1,947		$	(898	)				$	(1,545	)	$	(768	)	$	(1,194	)
Pro forma income (loss) per common share—basic and diluted	$	0.16		$	0.15		$	(0.07	)	$	(0.07	)	$	(0.12	)	$	(0.06	)	$	(0.09	)
Weighted average pro forma shares outstanding—basic and diluted		18,764			13,360			13,360			18,483			13,360			13,360			13,360
Other Financial Data:
Calculation of EBITDA:
Net income (loss)	$	3,076		$	3,359		$	(1,357	)	$	(1,265	)	$	(2,766	)	$	(1,550	)	$	(1,917	)
Interest expense		423			309			48			622			285			21			—
Deferred tax expense (benefit)		1,861			(231	)		(85	)		(765	)		285			317			—
Depreciation		5,114			2,851			1,534			8,222			3,695			1,985			1,122
EBITDA (2)	$	10,474		$	6,288		$	140		$	6,814		$	1,499		$	773		$	(795	)

	Six Months Ended June 30,						Year Ended December 31,
	2005			2004			2004			2003			2002
	(Unaudited)
	(In thousands)
Consolidated Cash Flow Information:
Net cash provided (used) by:
Operating activities	$	2,897		$	2,320		$	2,364		$	(1,914	)	$	(890	)
Investing activities (3)		(13,685	)		(10,736	)		(19,511	)		(4,846	)		(12,879	)
Financing activities		23,272			8,250			16,623			7,798			14,103

9

	Pro Forma Six Months Ended June 30,		At June 30,				At December 31,
	2005		2005		2004		2004		2003		2002
	(Unaudited)
	(In thousands)
Consolidated Balance Sheet Information:
Total current assets	$	89,701	$	23,495	$	6,551	$	8,118	$	5,682	$	1,495
Total assets		273,112		118,906		81,902		90,143		71,920		15,629
Total debt (4)		29,000		40,000		12,550		18,100		4,300		—
Total liabilities		56,541		63,229		32,557		39,340		21,218		620
Total equity		216,571		55,677		49,345		50,803		50,702		15,009

(1) Prior to the completion of our initial public offering in August 2005, we merged with Bronco Drilling Company, L.L.C., our predecessor company. Bronco Drilling Company, L.L.C. was a limited liability company treated as a partnership for federal income tax purposes. As a result, essentially all of its taxable earnings and losses were passed through to its members, and it did not pay federal income taxes at the entity level. Historical income taxes consist mainly of deferred income taxes on a taxable subsidiary, Elk Hill Drilling, Inc. Since we are a C corporation, for comparative purposes we have included a pro forma provision (benefit) for income taxes assuming we had been taxed as a C corporation in all periods prior to the merger.

(2) EBITDA is a non-generally accepted accounting principles (“GAAP”) financial measure equal to net income (loss), the most directly comparable GAAP financial measure, plus interest expense, deferred tax expense (benefit) and depreciation. We have presented EBITDA because we use EBITDA as an integral part of our internal reporting to measure our performance and to evaluate the performance of our senior management. We consider EBITDA to be an important indicator of the operational strength of our business. EBITDA eliminates the uneven effect of considerable amounts of non-cash depreciation and amortization. A limitation of this measure, however, is that it does not reflect the periodic costs of certain capitalized tangible and intangible assets used in generating revenues in our business. Management evaluates the costs of such tangible and intangible assets and the impact of related impairments through other financial measures, such as capital expenditures, investment spending and return on capital. Therefore, we believe that EBITDA provides useful information to our investors regarding our performance and overall results of operations. EBITDA is not intended to be a performance measure that should be regarded as an alternative to, or more meaningful than, either net income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition, EBITDA is not intended to represent funds available for dividends, reinvestment or other discretionary uses, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. The EBITDA measure presented in this prospectus may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in our various agreements.

(3) In August 2003, we acquired 22 drilling rigs and drilling rig structures and components for an aggregate of $49.0 million. These transactions were funded directly by our equity holders. Accordingly, they have been accounted for as acquisitions by our equity holders followed by their contribution to us of the acquired assets. As a result, net cash used in investing activities for 2003 does not include the $33.5 million cash portion of the acquisition cost. See Note B to our consolidated financial statements appearing elsewhere in this prospectus.

(4) In July 2005, we acquired all of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million was paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with proceeds from a $13.0 million loan made to us on June 30, 2005 by Alpha Investors LLC, an entity controlled by Wexford. This $13.0 million loan, which is included in this table for our historical balance sheet as of June 30, 2005, was repaid in full with a portion of the proceeds from our initial public offering. The $7.0 million promissory notes to the sellers were not issued until after June 30, 2005 and are not included in this table for our historical balance sheet as of June 30, 2005. For our pro forma balance sheet as of June 30, 2005, the $13.0 million loan is assumed to be repaid in full from offering proceeds and the $7.0 million promissory notes are assumed to be issued and are reflected as outstanding. The $7.0 million promissory notes remain outstanding.

10

RISK FACTORS

Investing in our common stock involves a high degree of risk. You should carefully consider the following risks and all other information contained in this prospectus before deciding to invest in our common stock. Our business, financial condition or results of operations could be materially and adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

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.

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. 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.

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;

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• 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.

Risks Relating to Our Business

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, can be used to assemble 22 drilling rigs. In July 2005, we acquired three additional rigs and related inventory, equipment, components and 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 that are currently being refurbished, two inventoried rigs and rig equipment and parts. 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 the recently adopted 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

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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. 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 dayrates and utilization rates.

Any increase in the supply of land rigs, whether through new construction or refurbishment, could decrease dayrates 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 dayrates and utilization rates could be further aggravated by any downturn in oil and natural gas prices.

A material reduction in the levels of exploration and development activities in Oklahoma or an increase in the number of rigs mobilized to Oklahoma could negatively impact our dayrates and utilization rates.

We currently conduct a substantial portion of our operations in Oklahoma. A material reduction in the levels of exploration and development activities in Oklahoma due to a variety of oil and natural gas industry risks described above or an increase in the number of rigs mobilized to Oklahoma could negatively impact our dayrates and utilization rates, which could adversely affect our revenues and profitability.

Our revenues and profitability could be negatively impacted if we are unable to successfully complete the refurbishment of our inventoried rigs on schedule and within budget and use those and the other rigs in our fleet at profitable levels.

We plan on completing the refurbishment of four additional inventoried rigs during the balance of 2005 and refurbishing ten inventoried rigs during 2006 at estimated costs ranging from $2.0 million to $6.8 million per rig. Our revenues and profitability could be negatively impacted if we are unable to successfully complete the refurbishment of our inventoried rigs on schedule and within budget and operate those and the other rigs in our fleet at profitable levels. Our refurbishment projects are subject to the risks of delay and cost overruns inherent in any large construction project, including shortages of equipment, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, inability to obtain necessary certifications and approvals and shortages of materials or skilled labor. Significant delays could negatively impact our anticipated contract commitments with respect to rigs being refurbished, while significant cost overruns or delays in general could adversely affect our financial condition and results of operations. Moreover, customer demand for rigs currently being refurbished may not be as strong as we presently anticipate, and our inability to obtain contracts on anticipated terms or at all may negatively impact our revenues and profitability.

We have a history of losses and may experience losses in the future.

We have a history of losses. We incurred net losses of $2.8 million, $1.6 million and $1.9 million for the years ended December 31, 2004, 2003 and 2002, respectively. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs. Our current utilization rates and dayrates may decline and we may experience losses in the future.

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

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 drilling contracts we compete for are usually awarded on the basis of competitive bids or direct negotiations with customers. 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 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 which can, in turn, reduce our profitability.

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 rigs from other regions could rapidly intensify competition and reduce profitability.

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

Many of our competitors have greater financial, technical and other resources than we do which may make it more difficult for us to compete which can reduce our dayrates 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.

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We are subject to unexpected cost overruns on our footage contracts and, to the extent we enter into such arrangements, turnkey contracts, which could negatively impact our profitability.

For the year ended December 31, 2004, 13% of our total revenues was 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 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. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other

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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 primarily focus on drilling for natural gas.

A majority of our drilling contracts are with exploration and production companies in search of natural gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. 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 “day work” 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 search of natural gas to drilling for customers in search of oil, the majority of our rig fleet would be disadvantaged in competing for new oil drilling projects as compared to competitors that primarily use shallower drilling depth rigs when drilling in search of oil.

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 which may expose us to additional operating costs and liabilities for accidental discharges of oil,

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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.

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, particularly the loss of Frank Harrison, our Chief Executive Officer and President, Zachary Graves, our Chief Financial Officer, or Karl Benzer, our Chief Operating Officer, could disrupt our operations resulting in a loss of revenues. We do not have an employment contract with any of our executives, with the exception of Mr. Benzer, and our executives, with the exception of Mr. Benzer, are not restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, any employment agreement we

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may enter into will not assure the retention of our 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 are occurring 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 drilling operations and jeopardize our relations with customers.

The materials and supplies we use in our drilling operations include fuels to operate our drilling equipment, drilling mud, drill pipe, drill collars, drill bits and cement. Shortages in equipment supplies could limit our drilling operations 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 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 negatively impact our revenues and profitability.

We will be subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected.

We will be required to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as of December 31, 2006. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls and management’s assessment of those controls. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our profitability could be affected.

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We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weakness, the accuracy and timeliness of the filing of our annual and quarterly reports may be negatively affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could negatively impact our business, profitability and financial condition.

Risks Related to this Offering and Our Common Stock

Our largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other stockholders.

Upon completion of this offering, Wexford will beneficially own approximately 58% of our common stock, or approximately 57% if the underwriters exercise their overallotment option in full. As a result, Wexford will continue to be able to exercise significant influence, and in most cases control over matters requiring stockholder approval, including the election of directors, changes to our charter documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Wexford with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Wexford’s continued concentrated ownership will make it impossible for another company to acquire us and for you to receive any related takeover premium for your shares unless Wexford approves the acquisition.

Since we are a “controlled company” for purposes of The Nasdaq National Market’s corporate governance requirements, our stockholders will not have, and may never have, the protections that these corporate governance requirements are intended to provide.

Since we are a “controlled company” for purposes of The Nasdaq National Market’s corporate governance requirements, we are not required to comply with the provisions requiring that a majority of our directors be independent, the compensation of our executives be determined by independent directors or nominees for election to our board of directors be selected by independent directors. As a result, our stockholders will not have, and may never have, the protections that these rules are intended to provide. The board of directors has determined that David L. Houston, Michael O. Thompson and Phillip Lancaster are independent under The Nasdaq National Market listing standards.

We rely upon Gulfport Energy Corporation to provide us with administrative services. Gulfport is an affiliate of ours and conflicts of interest may arise. Further, the unexpected loss of these services could negatively impact our operations.

Historically, we have outsourced a significant portion of our administrative functions to Gulfport Energy Corporation and we expect to continue to outsource certain functions for the foreseeable future pursuant to an administrative services agreement we entered into with Gulfport effective April 1, 2005. Under this agreement, Gulfport’s services for us include accounting, human resources, legal and technical support. In return for the services rendered by Gulfport, we have agreed to pay Gulfport an annual fee of approximately $414,000 payable in equal monthly installments during the term of this agreement. In addition, we will continue to lease approximately 1,100 square feet of office space from Gulfport for our headquarters. We will pay Gulfport annual rent of approximately $20,900 payable in equal monthly installments. The services being provided to us and the

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fees for those services can be amended by mutual agreement of the parties. Two of our directors, Mike Liddell and David L. Houston, are also directors of Gulfport and Mr. Liddell is the Chief Executive Officer of Gulfport. This may create conflicts of interest because these individuals have responsibilities to Gulfport and its stockholders, including Wexford, which is Gulfport’s largest stockholder. Their duties as directors or officers of Gulfport may conflict with their duties as directors of our company regarding business dealings between Gulfport and us and other matters. The resolution of these conflicts may not always be in our or our stockholders’ best interests. The administrative services agreement has a three-year term, and upon expiration, it will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by us at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. Although we believe that if this agreement was terminated we could, over time, replace the required personnel and acquire the accounting and reporting systems and other assets necessary to replace Gulfport, an unanticipated loss of these personnel and systems could negatively impact our business. Further, the fees for such services were arrived at through negotiations between us and Gulfport. Although we believe the fees are reasonable, we have not determined whether unrelated third parties could provide comparable services at a lower cost. See “Certain Relationships and Related Party Transactions—Administrative Services Agreement and Lease of Space” for further discussion of the administrative services agreement.

We will incur increased costs as a result of being a public company.

As a result of becoming a public company in August 2005, we have incurred and will continue to incur significant legal, accounting and other expenses that we did not incur as a private company. We have incurred and will continue to incur costs associated with our public company reporting requirements and costs associated with recently adopted corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as new rules implemented by the SEC and the NASD. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly. We also expect these new rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these new rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

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 National Market, we cannot assure you that an active public market will develop for our common stock or that our common stock will trade in the public market subsequent to this offering at or above the public offering price. If an active public market for our common stock does not develop, 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 prices 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. The offering price may not be indicative of the trading price for our common stock after this offering. 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;

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• 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 are sold in the open market after this offering, the trading price of our common stock could decrease. After this offering, we will have an aggregate of 76,859,632 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 pursue acquisitions and may issue shares of our common stock in connection with these acquisitions.

Bronco Drilling Holdings, L.L.C., an entity controlled by Wexford, will own approximately 58% of our common stock after this offering (approximately 57% if the underwriters exercise their overallotment option in full). We have entered into a registration rights agreement with Bronco Drilling Holdings under which Bronco Drilling Holdings has three demand registration rights, as well as “piggyback” registration rights. Such sales by Bronco Drilling Holdings, sales by other securityholders or the perception that such sales might occur could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities. See “Securities Eligible for Future Sale—Registration Rights” for further information regarding Bronco Drilling Holdings’ registration rights.

Purchasers in this offering will experience immediate and substantial dilution in the book value of their investment.

Purchasers of our common stock in this offering will experience an immediate, substantial dilution of $13.50 per share of common stock (based on an offering price of $23.00) because the price per share of common stock in this offering is substantially higher than the net tangible book value of each share of common stock outstanding immediately after this offering. Our net tangible book value as of June 30, 2005 on a pro forma basis after giving effect to the merger of Bronco Drilling Company, L.L.C., our predecessor company, into us and the issuance of common stock in our initial public offering in August 2005, the Strata, Thomas and Eagle acquisitions and this offering and the application of proceeds from such offerings is approximately $214.5 million, or $9.50 per share of common stock. In addition, purchasers may experience further dilution from issuances of shares of our common stock in the future. See “Dilution.”

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

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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 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.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Our disclosure and analysis in this prospectus 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 prospectus 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 prospectus 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 prospectus. All forward-looking statements speak only as of the date of this prospectus. 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.

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USE OF PROCEEDS

We will receive net proceeds of approximately $75.6 million from our sale of 3,500,000 shares of common stock in this offering, or approximately $87.0 million if the underwriters exercise their overallotment option in full, after deducting the underwriting discount and estimated offering expenses payable by us.

We expect to use a portion of the net proceeds from this offering to repay approximately $50.0 million in borrowings incurred in connection with our Thomas acquisition under a loan agreement we entered into with Theta Investors LLC, an entity controlled by Wexford. The loan will mature, and the outstanding principal balance of the loan plus accrued but unpaid interest will be due in full, on October 14, 2006. Borrowings under our loan with Theta bear interest at a rate equal to LIBOR plus 400 basis points until December 15, 2005, and thereafter at a rate equal to LIBOR plus 600 basis points. See “Certain Relationships and Related Party Transactions—Credit Facilities” for further information regarding the Theta loan.

We expect to use the balance of the net proceeds, together with cash from operations, to refurbish rigs in our inventory at estimated costs ranging from $900,000 million to $6.8 million per rig and for general corporate purposes, which may include the purchase of additional rigs. We plan on refurbishing four additional rigs during the balance of 2005 and ten more rigs during 2006. The amounts and timing of our actual expenditures will depend upon market and other factors.

Pending the use of the remaining net proceeds for refurbishment and general corporate purposes, we may repay a portion of our outstanding borrowings under our term loan with Merrill Lynch. This term loan provides for a term installment loan in an aggregate amount not to exceed $50.0 million and provides for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan may not exceed 60% of the net orderly liquidation value of our operating land drilling rigs. On September 19, 2005, we borrowed $43.0 million under the term loan, which borrowings were used to fund a portion of the Eagle acquisition. The term loan bears interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points. For the period from September 19, 2005 to January 1, 2006, interest only will be payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan will be payable in sixty consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus interest on the outstanding principal balance. Any outstanding principal and accrued but unpaid interest will be immediately due and payable in full on January 1, 2011.

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PRICE RANGE OF COMMON STOCK

Our common stock has been quoted on The Nasdaq National Market under the symbol “BRNC” since August 16, 2005. The following table sets forth for the indicated periods the high and low sale prices of our common stock as quoted on The Nasdaq National Market.

	High		Low
Year Ending December 31, 2005:
Third Quarter (since August 16, 2005)	$	30.00	$	18.00
Fourth Quarter (through October 27, 2005)		29.10		20.97

On October 27, 2005, the last reported sale price of our common stock on The Nasdaq National Market was $23.26.

On October 21, 2005, we had approximately 1,700 beneficial holders of our common stock.

DIVIDEND POLICY

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.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2005:

• on an actual basis;

• on a pro forma basis to give effect to (1) our conversion from an Oklahoma limited liability company to a taxable Delaware corporation, (2) the sale of 5,715,000 shares of common stock by us in our initial public offering for $17.00 per share, our receipt of the approximately $89.7 million of net proceeds from such sale and the application of those net proceeds and (3) certain payments made by our largest stockholder to Steven C. Hale as described in note (2) below; and

• on a pro forma as adjusted basis to give further effect to (1) the Strata acquisition described in note (1) below, (2) the Thomas and Eagle acquisitions described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Business—General” and (3) the sale of our common stock in this offering and the application of the net proceeds from this sale as described under the caption “Use of Proceeds.”

You should read the information in this table in conjunction with the Bronco Drilling Company, Inc. Unaudited Pro Forma Combined Consolidated Financial Statements, “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and related notes appearing elsewhere in this prospectus.

	As of June 30, 2005
	Actual		Pro Forma			Pro Forma As Adjusted
	(in thousands, except share data)
Cash and cash equivalents (1)	$	13,623	$	85,257		$	72,829	(4)
Total debt (including current maturities) (1)	$	40,000	$	22,000		$	72,000	(4)
Members’ equity		55,677		—			—
Stockholders’ equity (deficit):
Common stock, par value $.01; 0 shares authorized and 0 shares issued and outstanding actual; 100,000,000 shares authorized and 19,075,000 shares issued and outstanding pro forma; 100,000,000 shares authorized and 22,575,000 shares issued and outstanding pro forma as adjusted		—		191			226
Additional paid-in capital (2)		—		149,220			224,757
Accumulated deficit (2)(3)		—		(8,412	)		(8,412	)
Total stockholders’ equity		—		140,999			216,571
Total capitalization	$	95,677	$	162,999		$	288,571

(1) In July 2005, we acquired all of the membership interest in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million was paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with proceeds from a $13.0 million loan made to us on June 30, 2005 by Alpha Investors LLC, an entity controlled by Wexford. This $13.0 million loan is included in this table in the Actual column but is reflected as repaid in the Pro Forma and Pro Forma As Adjusted columns. In August 2005, we used a portion of the net proceeds from our initial public offering to repay this loan in full.

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(2) Under the terms of an agreement between Bronco Drilling Holdings, L.L.C. and Steven C. Hale, our former President and Chief Operating Officer, following successful completion of our initial public offering Bronco Drilling Holdings, L.L.C. paid Mr. Hale the sum of $2.0 million and 117,647 shares of our common stock. We will account for these payments as a capital contribution to us in the amount of $4.0 million and compensation expense in the amount of $4.0 million in the third quarter of 2005, the period in which the obligation was incurred.

(3) A one-time charge to operations will be made in the amount of approximately $4.4 million to recognize deferred taxes upon our change in tax status as a result of the merger.

(4) On October 3, 2005, we acquired 12 drilling rigs and related assets from Eagle Drilling, L.L.C. and two of its affiliates for a purchase price of approximately $50.0 million. The purchase price was partially funded by a $43.0 million term loan from Merrill Lynch. The cash payment of $50.0 million and borrowing of $43.0 million are reflected in our Pro Forma As Adjusted column in the above Capitalization table as if the acquisition had occurred on June 30, 2005. The effect of the Eagle acquisition is not included in our Unaudited Pro Forma Combined Financial Statements appearing elsewhere in this prospectus since audited financial statements are not currently available. On October 14, 2005, we acquired 13 drilling rigs and related assets from Thomas Drilling Co. for a purchase price of approximately $68.0 million. The purchase price was partially funded by borrowings of $50.0 million under the Theta loan which will be repaid from a portion of the net proceeds of this offering. The cash payment of $68.0 million and borrowings of $50.0 million are reflected in our Pro Forma As Adjusted column in the above Capitalization table as if the acquisition had occurred on June 30, 2005. The effect of the Thomas acquisition is included in our Unaudited Pro Forma Combined Financial Statements appearing elsewhere in this prospectus.

The number of shares of our common stock to be outstanding immediately after this offering excludes (1) 500,000 shares of our common stock issuable upon the exercise of outstanding options, at a weighted average exercise price of $17.92 per share and (2) the 65,368 shares of our common stock issued to the shareholders of Hays Trucking, Inc. in connection with our acquisition of Hays Trucking, Inc., see “Business—General.”

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DILUTION

Our reported net tangible book value as of June 30, 2005 was $139.0 million, or $7.28 per share of common stock, based upon 19,075,000 shares outstanding as of that date after giving pro forma effect to the merger of Bronco Drilling Company, L.L.C., our predecessor company, into us, the sale of 5,715,000 shares of our common stock in our initial public offering and the application of the net proceeds from that offering, and the Strata, Eagle and Thomas acquisitions. Net tangible book value per share is calculated by subtracting our total liabilities from our total tangible assets, which equals total assets less intangible assets, and dividing this amount by the number of shares of common stock outstanding as of June 30, 2005 after giving pro forma effect to the merger, the sale of 5,715,000 shares of our common stock in our initial public offering and the application of the net proceeds from that offering. After giving additional effect to the sale by us of 3,500,000 shares of common stock offered in this offering at a public offering price of $23.00 per share and after deducting the underwriting discount and estimated offering expenses payable by us, our net tangible book value as of June 30, 2005 would have been $214.5 million, or $9.50 per share of common stock. This represents an immediate increase in the net tangible book value of $2.22 per share to our existing stockholders and an immediate dilution in the net tangible book value of $13.50 per share to new investors.

The following table illustrates this dilution on a per share basis:

Public offering price per share			$	23.00
Net tangible book value per share as of June 30, 2005	$	7.28
Increase per share attributable to new investors	$	2.22
Pro forma as adjusted net tangible book value per share after the offering			$	9.50
Dilution per share in pro forma net tangible book value to new investors			$	13.50

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SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth our selected historical financial data as of and for each of the years and interim periods indicated. We derived the selected historical financial data as of and for each of the years ended 2004, 2003 and 2002 from our historical audited consolidated financial statements. We derived the selected historical financial data as of and for the year ended 2001 and the unaudited interim periods indicated from our historical unaudited consolidated financial statements. The interim unaudited information was prepared on a basis consistent with that used in preparing our audited consolidated financial statements and includes all adjustments, consisting of normal and recurring items, that we consider necessary for a fair presentation of the financial position and results of operations for the unaudited periods. Operating results for the six months ended June 30, 2005 are not necessarily indicative of results that may be expected for the entire year 2005. 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 prospectus.

	Six Months Ended June 30,						Year Ended December 31,
	2005			2004			2004			2003			2002			2001 (1)
	(Unaudited)															(Unaudited)
	(In thousands, except per share amounts)
Consolidated Statements of Operations Information:
Contract drilling revenues	$	20,269		$	7,758		$	21,873		$	12,533		$	3,115		$	592
Costs and expenses:
Contract drilling		12,870			6,937			18,670			10,537			3,239			711
Depreciation		2,851			1,534			3,695			1,985			1,122			145
General and administrative		1,123			686			1,714			1,226			676			174
Total operating costs and expenses		16,844			9,157			24,079			13,748			5,037			1,030
Income (loss) from operations		3,425			(1,399	)		(2,206	)		(1,215	)		(1,922	)		(438	)
Other income (expense):
Interest expense		(309	)		(48	)		(285	)		(21	)		—			—
Interest income		12			5			10			3			5			2
Total other income (expense)		(297	)		(43	)		(275	)		(18	)		5			2
Income (loss) before income taxes		3,128			(1,442	)		(2,481	)		(1,233	)		(1,917	)		(436	)
Deferred tax expense (benefit)		(231	)		(85	)		285			317			—			—
Net income (loss)	$	3,359		$	(1,357	)	$	(2,766	)	$	(1,550	)	$	(1,917	)	$	(436	)
Pro Forma C Corporation Data: (2)
Historical income (loss) from operations before income taxes	$	3,128		$	(1,442	)	$	(2,481	)	$	(1,233	)	$	(1,917	)	$	(436	)
Pro forma provision (benefit) for income taxes attributable to operations		1,181			(544	)		(936	)		(465	)		(723	)		(165	)
Pro forma income (loss) from operations	$	1,947		$	(898	)	$	(1,545	)	$	(768	)	$	(1,194	)	$	(271	)
Pro forma income (loss) per common share—basic and diluted	$	0.15		$	(0.07	)	$	(0.12	)	$	(0.06	)	$	(0.09	)	$	(0.02	)
Weighted average pro forma shares outstanding—basic and diluted		13,360			13,360			13,360			13,360			13,360			13,360
Other Financial Data:
Calculation of EBITDA:
Net income (loss)	$	3,359		$	(1,357	)	$	(2,766	)	$	(1,550	)	$	(1,917	)	$	(436	)
Interest expense		309			48			285			21			—			—
Deferred tax expense (benefit)		(231	)		(85	)		285			317			—			—
Depreciation		2,851			1,534			3,695			1,985			1,122			145
EBITDA (3)	$	6,288		$	140		$	1,499		$	773		$	(795	)	$	(291	)

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	Six Months Ended June 30,						Year Ended December 31,
	2005			2004			2004			2003			2002			2001 (1)
	(Unaudited)															(Unaudited)
	(In thousands)
Consolidated Cash Flow Information:
Net cash provided (used) by:
Operating activities	$	2,897		$	2,320		$	2,364		$	(1,914	)	$	(890	)	$	(447	)
Investing activities (4)		(13,685	)		(10,736	)		(19,511	)		(4,846	)		(12,879	)		(2,522	)
Financing activities		23,272			8,250			16,623			7,798			14,103			3,260
	At June 30						At December 31,
	2005			2004			2004			2003			2002			2001
	(Unaudited)															(Unaudited)
	(In thousands)
Consolidated Balance Sheet Information:
Total current assets	$	23,495		$	6,551		$	8,118		$	5,682		$	1,495		$	608
Total assets		118,906			81,902			90,143			71,920			15,629			2,985
Total debt (5)		40,000			12,550			18,100			4,300			—			—
Total liabilities		63,229			32,557			39,340			21,218			620			161
Total members’ equity		55,677			49,345			50,803			50,702			15,009			2,824

(1) We were formed in June 2001 and purchased one stacked 650-horsepower rig that we refurbished and deployed. We began drilling in September 2001, and our selected consolidated historical financial data for the year ended 2001 only reflects operating activity from that date.

(2) Prior to the completion of our initial public offering in August 2005, we merged with Bronco Drilling Company, L.L.C., our predecessor company. Bronco Drilling, L.L.C. was a limited liability company treated as a partnership for federal income tax purposes. As a result, essentially all of its taxable earnings and losses were passed through to its members, and it did not pay federal income taxes at the entity level. Historical income taxes consist mainly of deferred income taxes on a taxable subsidiary, Elk Hill Drilling, Inc. Since we are a C corporation, for comparative purposes we have included a pro forma provision (benefit) for income taxes assuming we had been taxed as a C corporation in all periods prior to the merger.

(3) EBITDA is a non-GAAP financial measure equal to net income (loss), the most directly comparable GAAP financial measure, plus interest expense, deferred tax expense (benefit) and depreciation. We have presented EBITDA because we use EBITDA as an integral part of our internal reporting to measure our performance and to evaluate the performance of our senior management. We consider EBITDA to be an important indicator of the operational strength of our business. EBITDA eliminates the uneven effect of considerable amounts of non-cash depreciation and amortization. A limitation of this measure, however, is that it does not reflect the periodic costs of certain capitalized tangible and intangible assets used in generating revenues in our business. Management evaluates the costs of such tangible and intangible assets and the impact of related impairments through other financial measures, such as capital expenditures, investment spending and return on capital. Therefore, we believe that EBITDA provides useful information to our investors regarding our performance and overall results of operations. EBITDA is not intended to be a performance measure that should be regarded as an alternative to, or more meaningful than, either net income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition, EBITDA is not intended to represent funds available for dividends, reinvestment or other discretionary uses, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. The EBITDA measure presented in this prospectus may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in our various agreements.

(4) In August 2003, we acquired 22 drilling rigs and drilling rig structures and components for an aggregate of $49.0 million. These transactions were funded directly by our equity holders. Accordingly, they have been accounted for as acquisitions by our equity holders followed by their contribution to us of the acquired assets. As a result, net cash used in investing activities for 2003 does not include the $33.5 million cash portion of the acquisition cost. See Note B to our consolidated financial statements appearing elsewhere in this prospectus.

(5) In July 2005, we acquired all of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million was paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with proceeds from a $13.0 million loan made to us on June 30, 2005 by Alpha Investors LLC, an entity controlled by Wexford. This $13.0 million loan, which is included in this table for our historical balance sheet as of June 30, 2005, was repaid in full with a portion of the proceeds from our initial public offering. The $7.0 million promissory notes to the sellers were not issued until after June 30, 2005 and are not included in this table for our historical balance sheet as of June 30, 2005. For our pro forma balance sheet as of June 30, 2005, the $13.0 million loan is assumed to be repaid in full from offering proceeds and the $7.0 million promissory notes are assumed to be issued and are reflected as outstanding. The $7.0 million promissory notes remain outstanding.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 prospectus. 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 prospectus.

Company Overview

We earn our contract drilling revenues by drilling oil and natural gas wells for our customers. A majority of our wells have been drilled in search of natural gas, which is the primary focus of our customers. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork or footage basis. We have not historically entered into turnkey contracts and do not intend to enter into them, subject to changes in market conditions, although it is possible that we may acquire such contracts in connection with future acquisitions. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Although we are currently operating two of our rigs under agreements with two-year terms and three of our rigs under agreements with one-year terms, our contracts generally provide for the drilling of a single well and typically permit the customer to terminate on short notice.

A significant performance measurement in our industry is operating rig utilization. We compute operating 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 was released from the contract. On daywork contracts, during the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, some of our contracts will provide for the trucking costs to be paid by the customer, and we will receive a reduced dayrate during the mobilization period.

For the six months ended June 30, 2005 and 2004 and years ended December 31, 2004, 2003 and 2002, our rig utilization rates, revenue days and average number of operating rigs were as follows:

	Six Months Ended June 30,				Year Ended December 31,
	2005		2004		2004		2003		2002
Utilization rates	94	%	73	%	81	%	76	%	58	%
Revenue days	1,967		1,143		2,733		1,898		500
Average number of operating rigs	12		9		9		7		2

The annual increases in the number of revenue days in each of 2004, 2003 and 2002 and the period-to-period increase in the six months ended June 30, 2005 as compared to the same period in 2004 are attributable to the increases in the size of our operating rig fleet and improvements in our rig utilization rate due to improved market conditions. Based on current market conditions, we anticipate continued growth in revenue days and stable to improving utilization rates for the balance of 2005.

We devote substantial resources to maintaining, upgrading and expanding our rig fleet. During 2004, we completed the refurbishment of four rigs, which contributed to an increase in revenue days and utilization rates. Since July 2005, we have acquired 28 rigs, of which 16 are operating, three are being refurbished and nine are

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held in inventory. We have also completed the refurbishment of three rigs to date in 2005 and plan on completing the refurbishment of four additional inventoried rigs by the end of 2005. We plan on refurbishing ten inventoried rigs during 2006.

Market Conditions in Our Industry

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

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 June 30, 2005	At December 31,
		2004	2003	2002
Crude oil (Bbl)	$ 56.50	$43.45	$32.52	$31.20
Natural gas (MMbtu)	$   6.98	$  6.15	$  6.19	$  4.79
U.S. land rig count	1,250(1)	1,117	1,003	728(2)

(1) As of June 24, 2005.

(2) As of December 27, 2002.

On October 27, 2005, the closing prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX were $61.09 per barrel and $13.832 per MMbtu, respectively. The Baker Hughes domestic land rig count as of October 21, 2005 was 1,365. Baker Hughes is a large oil field services firm that has issued the rotary rig counts as a service to the petroleum industry since 1944.

We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as shortages in supply of natural gas. The Energy Information Administration recently estimated that U.S. consumption of natural gas exceeded domestic production by 17% in 2004 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic production by 24% in 2010. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding ten years that average “initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time.” The report went on to state that “without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year” and predicted that in ten years eighty percent of gas production “will be from wells yet to be drilled.” We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in the U.S. Consequently, these factors may result in higher rig dayrates and rig utilization.

Critical Accounting Policies and Estimates

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

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available as of the date of the financial statements and, accordingly, actual results could differ from these estimates, sometimes materially. Critical accounting policies and estimates are defined as those that are both most important to the portrayal of our financial condition and operating results and require management’s most subjective judgments. The most critical accounting policies and estimates are described below.

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

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

We are entitled to receive payment under footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since inception, we have completed all our footage contracts. Although our initial cost estimates for footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately adjust our cost estimate for the additional costs to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During 2004, we experienced losses on two of the 11 footage contracts we completed, with aggregate losses of approximately $170,000. We are more likely to encounter losses on footage contracts in years in which revenue rates are lower for all types of contracts.

Revenues and costs during a reporting period could be affected by contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We had no footage contracts in progress at December 31, 2004 or June 30, 2005. At June 30, 2005, our contract drilling in progress totaled approximately $2.2 million, all of which relates to the revenue recognized but not yet billed on daywork contracts in progress at June 30, 2005.

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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, operating overhead allocations and allocations of depreciation and amortization expense. 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 which were not completed prior to the release of our financial statements.

Accounts Receivable—We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, current prices of oil and natural gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 30-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three years. Our allowance for doubtful accounts was $146,000 at December 31, 2004 and June 30, 2005. 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 are credited to the allowance for doubtful accounts.

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

Asset Impairment and Depreciation—We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and natural gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at June 30, 2005, would have resulted in a corresponding decrease in our net income of approximately $991,000 for the quarter ended June 30, 2005.

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.

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We capitalize interest cost as a component of drilling rigs refurbished for our own use. During the year ended December 31, 2004, we capitalized approximately $470,000 of interest incurred.

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

Other Accounting Estimates—Our other accrued expenses as of June 30, 2005 and December 31, 2004 and 2003 included accruals of approximately $77,000, $94,000 and $0, respectively, for costs under our workers’ compensation insurance. We have a deductible of $100,000 per covered accident under our workers’ compensation insurance. Our insurance policy requires us to maintain a letter of credit to cover payments by us of that deductible. As of June 30, 2005, we had a $1.5 million letter of credit for which we have a deposit account in the amount of $1.5 million collateralizing the letter of credit. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.

Interim Financial Statements—The financial statements as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 included in this prospectus have been prepared without audit, pursuant to the rules and regulations of the SEC. The interim financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of the results of the interim periods. Such adjustments are considered to be of a normal recurring nature. Results of operations for the six-month period ended June 30, 2005 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2005.

Results of Operations

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Contract Drilling Revenue.  For the six months ended June 30, 2005, we reported contract drilling revenues of $20.3 million, a 161% increase from revenues of $7.8 million for the same period in 2004. The increase is primarily due to an increase in dayrates, revenue days, utilization and average number of rigs working for the six months ended June 30, 2005 as compared to the same period in 2004. Average dayrates for our drilling services increased $3,296, or 45%, to $10,590 for the six months ended June 30, 2005 from $7,294 in the same period in 2004. Revenue days increased 72% to 1,967 days for the six months ended June 30, 2005 from 1,143 days during the same period in 2004. Our utilization increased to 94% from 73%, and our average number of operating rigs increased to 12 from nine, or 33%, for the six months ended June 30, 2005 as compared to the same period in 2004. The increase in the number of revenue days for the six months ended June 30, 2005 as compared to the same period in 2004 is attributable to the increase in the size of our operating rig fleet and improvements in our rig utilization rate due to improved market conditions. Based on current market conditions, we anticipate continued growth in revenue days and stable to improving utilization rates for the balance of 2005.

Contract Drilling Expense.  Direct rig cost increased $5.9 million to $12.9 million for the six months ended June 30, 2005 from $7.0 million for the same period in 2004. This 86% increase is primarily due to the increase in revenue days, the increase in average number of operating rigs in our fleet and the increase in rig utilization

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for the six months ended June 30, 2005 as compared to the same period in 2004. As a percentage of contract drilling revenue, drilling expense decreased to 63% for the six-month period ended June 30, 2005 from 89% for the same period in 2004 for the reasons discussed above.

Depreciation Expense.  Depreciation expense increased $1.3 million to $2.8 million for the six months ended June 30, 2005 from $1.5 million for the same period in 2004. The increase is primarily due to the 29% increase in fixed assets, including the deployment of four additional rigs, as well as incremental increases in ancillary equipment as compared to the same period in 2004.

General and Administrative Expense.  General and administrative expense increased $437,000, or 64%, to $1.1 million for the six months ended June 30, 2005 from $686,000 for the same period in 2004. The increase is primarily due to an increase in professional fees of $215,000, an increase in general and administrative costs associated with our machine shop of $51,000, an increase in payroll costs of $27,000 and an increase in reimbursements of $79,000 under our administrative services agreement with Gulfport. As a result of our initial public offering, increasing number of operating drilling rigs and accelerated refurbishment program, we expect our general and administrative expenses to continue to increase. Effective April 1, 2005, we entered into an administrative services agreement with Gulfport. Under this agreement, Gulfport’s services for us include accounting, human resources, legal and technical support. In return for the services rendered by Gulfport, we will pay Gulfport an annual fee of approximately $414,000 payable in equal monthly installments during the term of this agreement. In addition, we will continue to lease approximately 1,100 square feet of office space from Gulfport for our headquarters. We will pay Gulfport annual rent of approximately $20,900 payable in equal monthly installments. See “Certain Relationships and Related Party Transactions—Administrative Services Agreement and Lease of Space” for further discussions regarding our administrative services agreement. As a result of our new administrative services agreement, our service payments to Gulfport will increase from an average of approximately $17,000 per month to approximately $36,000 per month.

Interest Expense.  Interest expense increased $261,000 to $309,000 for the six months ended June 30, 2005 from $48,000 for the same period in 2004. The increase is due to an increase in average debt outstanding. We capitalized $547,000 of interest for the six months ended June 30, 2005 compared to $238,000 for the same period in 2004 as part of our rig refurbishment program.

Deferred Tax Expense (Benefit).  We recorded a deferred tax benefit of $231,000 for the six months ended June 30, 2005. This was an increase of $146,000 from a deferred tax benefit of $85,000 for the six months ended June 30, 2004. The increase in deferred tax benefit is primarily due to recognition of operating losses by our taxable subsidiary Elk Hill.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Contract Drilling Revenue.  For the year ended December 31, 2004, we reported contract drilling revenues of $21.9 million, a 75% increase from revenues of $12.5 million during 2003. The increase is primarily due to an increase in dayrates, revenue days, utilization and average number of rigs working for the year ended December 31, 2004 as compared to 2003. Average dayrates for our drilling services increased $1,370, or 21%, to $7,919 for contracts completed in the year ended December 31, 2004 from $6,549 in 2003. Revenue days increased 44% to 2,733 days for the year ended December 31, 2004 from 1,898 days during 2003. Our average number of operating rigs increased to nine from seven, or 29%, for the year ended December 31, 2004 as compared to 2003. The increase in the number of revenue days in 2004 as compared to 2003 is attributable to the increase in the size of our operating rig fleet and improvements in our rig utilization rate due to improved market conditions.

Contract Drilling Expense.  Direct rig cost increased $8.1 million to $18.7 million for the year ended December 31, 2004 from $10.5 million in 2003. The 77% increase is primarily due to the increase in revenue days, average number of rigs in our fleet and rig utilization in 2004 as compared to 2003. As a percentage of contract drilling revenue, drilling expense increased to 85% in 2004 from 84% in 2003.

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Depreciation Expense.  Depreciation expense increased $1.7 million to $3.7 million for the year ended December 31, 2004 from $2.0 million in 2003. The increase is primarily due to the 28% increase in fixed assets, including the deployment of four additional rigs during 2004, as well as incremental increases in ancillary equipment as compared to 2003.

General and Administrative Expense.  General and administrative expense increased $488,000, or 40%, to $1.7 million for the year ended December 31, 2004 from $1.2 million in 2003. This primarily resulted from a $303,000 increase in payroll costs and lease expense and professional fee increases of $75,000 and $77,000, respectively. The increase in payroll costs to $672,000 for the year ended December 31, 2004 from $369,000 in 2003 is due to our increased employee count and related wage increases during 2004. The increase in lease expense to $177,000 for the year ended December 31, 2004 from $102,000 in 2003 is due to the lease of additional yards that were part of the Elk Hill acquisition. The increase in professional fees to $80,000 for the year ended December 31, 2004 from $3,000 in 2003 is due to an increase in audit and legal expense.

Interest Expense.  Interest expense increased $263,000 to $285,000 for the year ended December 31, 2004 from $21,000 in 2003. The increase is due to an increase in average debt outstanding during 2004 under our credit facility with GECC that we entered into on December 26, 2003. We capitalized $470,000 of interest during 2004 as part of our rig refurbishment program.

Deferred Tax Expense.  Deferred tax expense decreased by $32,000, or 10%, to $285,000 for the year ended December 31, 2004 from $317,000 in 2003. The decrease in deferred tax expense is due to a reduction in income by our taxable subsidiary Elk Hill for the year ended December 31, 2004 as compared to 2003.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Contract Drilling Revenue.  For the year ended December 31, 2003, we reported contract drilling revenues of $12.5 million compared to $3.1 million during 2002. The increase is primarily due to increases in revenue days, utilization and average number of rigs working for the year ended December 31, 2003 as compared to 2002. Revenue days increased to 1,898 days for the year ended December 31, 2003 from 500 days during 2002. Our utilization increased to 76% from 58%, and the average number of operating rigs increased to seven from two, for the year ended December 31, 2003 as compared to 2002. The increases in revenue days, utilization and average number of rigs working were partially offset by a decrease in average dayrates for our drilling services to $6,549 in the year ended December 31, 2003 from $6,974 in 2002. The increase in the number of revenue days in 2003 as compared to 2002 is attributable to the increases in the size of our operating rig fleet and improvements in our rig utilization rate due to improved market conditions.

Contract Drilling Expense.  Direct rig cost increased $7.3 million to $10.5 million for the year ended December 31, 2003 from $3.2 million in 2002. The increase is primarily due to the increase in revenue days, average number of rigs in our fleet and rig utilization in 2003 as compared to 2002. As a percentage of contract drilling revenue, contract drilling expense was 84% in 2003 and 104% in 2002.

Depreciation Expense.  Depreciation expense increased $863,000 to $2.0 million for the year ended December 31, 2003 from $1.1 million in 2002. The increase is primarily due to the increase in fixed assets resulting from acquisitions, including an increase in the average number of operating rigs to seven for the year ended December 31, 2003 as compared to two for 2002.

General and Administrative Expense.  General and administrative expense increased $551,000, or 81%, to $1.2 million for the year ended December 31, 2003 from $676,000 in 2002. The increase resulted from increases in insurance, lease expense, payroll costs and professional fees. Insurance costs increased $318,000 due to increases in employees and insurable equipment during 2003. Lease expense and yard expense increased $56,000 and $50,000, respectively, due to the addition of a rig refurbishment yard and an equipment storage yard. In addition, administrative payroll costs and consulting fees increased by $40,000 and $20,000, respectively.

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Interest Expense.  We reported interest expense of $21,000 for the year ended December 31, 2003. We recorded no interest expense in 2002 as we had no debt outstanding during that year.

Deferred Tax Expense.  Deferred tax expense was $317,000 for the year ended December 31, 2003. We had no such expense in 2002. The increase is due to taxable income attributable to Elk Hill, our taxable subsidiary acquired in August of 2003.

Liquidity and Capital Resources

Operating Activities.  Net cash provided by operating activities was $2.9 million for the six months ended June 30, 2005 as compared to $2.3 million for the same period in 2004 and $2.4 million for the year ended December 31, 2004 as compared to net cash used in operating activities of $1.9 million for 2003 and $890,000 for 2002. The change for the period ended June 30, 2005 compared to the same period in 2004 was primarily attributable to a $4.7 million increase in net income from our drilling operations due to the continuing placement into service of our refurbished drilling rigs acquired in 2003. The increase in net income for the six-month period ended June 30, 2005, was substantially offset by an increase in receivables of $1.4 million and a decrease in accounts payable of $2.8 million as compared to the same period in 2004. The change from 2003 to 2004 was primarily attributable to placing refurbished drilling rigs acquired in 2003 in service. The increase in net cash used in operating activities for the year ended December 31, 2003 compared to 2002 was primarily a result of an increase in accounts receivable related to (a) the increased level of drilling activity from the full year of operations for the seven rigs acquired in May 2002 and (b) our acquisition of the 22 drilling rigs, one of which was placed in service in November 2003.

Investing Activities.  We use a significant portion of our cash flows from operations and financing activities for acquisitions and for the refurbishment of our rigs. We used cash for investing activities of $13.7 million for the six months ended June 30, 2005 compared to $10.7 million for the comparable period in 2004, and $19.5 million for the year ended December 31, 2004 compared to $4.8 million for 2003 and $12.9 million for 2002. We acquired seven drillings rigs in 2002 for $12.5 million. In August 2003, we acquired 22 drilling rigs and drilling rig structures and components for an aggregate of $49.0 million. These transactions were funded directly by our equity holders. Accordingly, they have been accounted for as acquisitions by our equity holders followed by their contribution to us of the acquired assets. As a result, net cash used in investing activities for 2003 does not include this $33.5 million. See Note B to our financial statements appearing elsewhere in this prospectus. Also in 2003, we refurbished one of our rigs at a cost of approximately $2.2 million. In 2004, we refurbished four drilling rigs at an aggregate cost of approximately $13.0 million. For the six months ended June 30, 2004, we used $10.7 million to refurbish our drilling rigs. For the six months ended June 30, 2005, we used $12.2 million to refurbish drilling rigs and placed $1.5 million in a restricted account as security for a letter of credit issued to our new workers’ compensation insurance carrier.

Financing Activities.  Our cash flows provided by financing activities were $23.3 million for the six months ended June 30, 2005 compared to $8.3 million for the comparable period in 2004, and $16.6 million for the year ended December 31, 2004 compared to $7.8 million for 2003 and $14.1 million for 2002. Our net cash provided by financing activities for the six months ended June 30, 2005 related to borrowings of $18.0 million from Solitair LLC and Alpha Investors LLC, entities controlled by Wexford, borrowings of $5.0 million from GECC, borrowings of $700,000 from International Bank of Commerce, principal payments on borrowings of $1.8 million to GECC and capital contributions of $1.5 million from entities controlled by Wexford. For the six months ended June 30, 2004, our net cash provided by financing activities related to $9.0 million borrowed under our credit facility with GECC and principal payments on borrowings of $750,000 to GECC. Our financing activities for 2004 relate primarily to an additional $15.0 million borrowed under our credit facility with GECC, related periodic repayments under such credit facility and International Bank of Commerce and capital contributions of $2.9 million from entities controlled by Wexford. For 2003, our net cash provided by financing activities related to capital contributions of $3.7 million from entities controlled by Wexford, borrowings of $3.0 million under our credit facility with GECC and proceeds of $1.3 million from a note payable to International Bank of Commerce. During 2002, the net cash from financing activities was used primarily to acquire and refurbish our rigs.

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Sources of Liquidity.  Our primary sources of liquidity are cash from operations and debt and equity financing. On December 26, 2003, we entered into a credit facility with GECC which provided for term loan advances up to $12.0 million. On each of September 24, 2004 and April 22, 2005, we amended our credit facility with GECC to increase the maximum amount of the terms loans to $18.0 million and then to $25.5 million respectively. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0% (effective rate of 8.11% at June 30, 2005) and were secured by substantially all of our property and assets, including our drilling rigs and associated equipment, and ownership interests in our subsidiary, but excluding cash and accounts receivable. Draws on the facility were required to be in $2.5 million increments each with a five-year term. Payments of principal and accrued but unpaid interest were due on the first day of each month. At June 30, 2005, our outstanding balance under this credit facility was $19.5 million. This credit facility, which was to mature on October 1, 2010, was repaid in full with a portion of the proceeds from our initial public offering and the credit facility was terminated.

An unused fee of 0.50% accrued on the daily average unused portion of the GECC credit facility, payable monthly in arrears. The credit facility provided for an initial prepayment penalty of 5.0%, decreasing by 1.0% on each anniversary of the facility. The credit agreement included customary negative covenants for credit facilities of this type, including covenants limiting liens, hedging, mergers, asset sales, changes in the nature of business, transactions with affiliates, other fundamental changes, indebtedness, acquisitions, dividends or other distributions, and investments. The credit agreement also required that we maintain an EBITDA to debt service coverage ratio of at least one-to-one and that we deliver to GECC audited financial statements within 90 days after the end of our fiscal year. We delivered our audited financial statements for the year ended December 31, 2004 in May 2005 and early this year we increased our borrowing base under our line of credit with the International Bank of Commerce without obtaining the prior approval of GECC. GECC waived both of these events.

On July 1, 2004, we entered into a revolving line of credit with International Bank of Commerce with a borrowing base of the lesser of $2.0 million or 80% of current receivables. Borrowings under this line bear interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime (effective rate of 6.25% at June 30, 2005) and are guaranteed by Wexford Partners VI, L.P. and Taurus Investors, LLC, entities controlled by Wexford. Accrued but unpaid interest is payable monthly, and we are current in our monthly interest payments through the date of this prospectus. On January 1, 2005, we amended our line of credit with International Bank of Commerce to increase the borrowing base to the lesser of $3.0 million or 80% of current receivables. The line of credit matures on November 1, 2005. The line of credit includes customary financial and negative covenants for credit facilities of this type, including covenants requiring the maintenance of depository accounts, a specified current ratio, tangible net worth and tangible net worth of guarantor, insurance, and covenants limiting liens, the sale of assets, the incurrence of additional indebtedness, dividends and other fundamental changes. As of the date of this prospectus, we were in compliance with our covenants under the line of credit. At June 30, 2005, our outstanding borrowings under this line of credit were $2.5 million.

On February 15, 2005, we entered into a $5.0 million revolving credit facility with Solitair LLC, an entity controlled by Wexford. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0% (effective rate of 8.11% at June 30, 2005). Payment of principal and accrued but unpaid interest were due on the maturity date of the credit facility which was the later of (1) six months after the actual maturity date of our credit facility with GECC and (2) December 1, 2010. At June 30, 2005, our outstanding borrowings under this credit facility were $5.0 million. We repaid this facility in full with a portion of the proceeds from our initial public offering and the facility was terminated.

In July 2005, we acquired all of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million was paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with a $13.0 million loan from Alpha Investors LLC, an entity controlled by Wexford. The outstanding principal balance of the loan plus accrued but unpaid interest was due in full upon the earlier to occur

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of the completion of our initial public offering and the maturity of the loan on July 1, 2006. We repaid this loan in full with a portion of the proceeds from our initial public offering. Borrowings under our loan with Alpha bore interest at a rate equal to LIBOR plus 5% until September 30, 2005 (effective rate of 8.11% when the loan was made on June 30, 2005), and thereafter were to bear interest at a rate equal to LIBOR plus 7.5%. The $7.0 million outstanding principal balance of the promissory notes issued to the sellers is automatically reduced by the amount of any costs and expenses we pay in connection with the refurbishment of one of the rigs we acquired from the sellers. The sellers have agreed to complete the refurbishment of this rig on or before the end of 2005, subject to limited exceptions. Payment of the outstanding balance of the loan is due and payable upon completion of the refurbishment of this rig. We granted the sellers a security interest in this rig to secure our obligations under the notes. The outstanding principal balance on these notes do not bear any interest other than default interest in the event of a default.

Our members contributed capital in the amounts of $1.5 million during the six months ended June 30, 2005 and $2.9 million, $37.2 million and $14.1 million during the years ended 2004, 2003 and 2002, respectively.

In August 2005, we completed our initial public offering in which we sold 5,715,000 shares of our common stock at an offering price of $17.00 per share, resulting in net proceeds to us of approximately $89.0 million. We used a portion of these proceeds to repay in full our loans from Alpha and Solitair and all borrowings under our credit agreement with GECC.

Under the terms of an agreement between Bronco Drilling Holdings, L.L.C. and Steven C. Hale, our former President and Chief Operating Officer, following successful completion of our initial public offering Mr. Hale was entitled to receive the sum of $2.0 million and shares of our common stock having a market value of $2.0 million based on the initial public offering price. These payments were made by Bronco Drilling Holdings and not by us. We will account for the payments as a capital contribution to us in the amount of $4.0 million and compensation expense in the amount of $4.0 million during the third quarter of 2005, the period in which such obligations were incurred.

On September 19, 2005, we entered into a Term Loan and Security Agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc., as lender (“Merrill Lynch” or the “lender”). The term loan provides for a term installment loan in an aggregate amount not to exceed $50.0 million and provides for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan may not exceed 60% of the net orderly liquidation value of our operating land drilling rigs. Proceeds of the term loan may be used to replenish our working capital for general business purposes, finance improvements to and the refurbishment of our land drilling rigs, and to acquire additional land drilling rigs. On September 19, 2005, we borrowed $43.0 million under the term loan. A portion of these borrowings, together with proceeds from our initial public offering, were used to fund the Eagle acquisition.

The term loan bears interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points. For the period from September 19, 2005 to January 1, 2006, interest only will be payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan will be payable in sixty consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. Any outstanding principal and accrued but unpaid interest will be immediately due and payable in full on January 1, 2011.

Our obligations under the term loan are secured by a first lien and security interest on substantially all of our assets and are guaranteed by each of our principal subsidiaries. The term loan includes usual and customary negative covenants for loan agreements of this type, including covenants limiting our ability to, among other things: consolidate or merge; form subsidiaries; substantially change the nature of our business; sell, transfer or dispose of assets; create or incur indebtedness; create liens; pay dividends or make other distributions; make loans and investments; enter into transactions with affiliates; and cancel, terminate, or amend any material

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contract. The term loan also requires us to meet certain financial covenants, including maintaining (1) a minimum “Fixed Charge Coverage Ratio” of 1 to 1 as of each consecutive calendar quarter-end from September 30, 2005 through June 30, 2006, 1.10 to 1 as of each consecutive financial quarter-end from July 1, 2006 through June 30, 2007, and 1.20 to 1 as of each consecutive financial quarter-end after June 30, 2007, and (2) a maximum “Total Debt to EBITDA Ratio” of 5 to 1 as of December 31, 2005, 4 to 1 as of March 31, 2005, and 3 to 1 as of June 30, 2006 and each consecutive calendar quarter ended thereafter. For the purposes of the calculation of our Total Debt to EBITDA Ratio, “Total Debt” will be based upon total indebtedness minus any subordinated debt. The term loan also includes customary events of default, including, among other things, breach of representations and warranties, dissolution, bankruptcy, and certain changes of control.

On October 14, 2005, we entered into a loan agreement with Theta Investors LLC, an entity controlled by Wexford, for purposes of funding a portion of the purchase price for the Thomas acquisition. The Theta loan provides for maximum aggregate borrowings of up to $60.0 million, which borrowings bear interest at a rate equal to LIBOR plus 400 basis points until December 15, 2005, and thereafter at a rate equal to LIBOR plus 600 basis points. Payment of principal and accrued but unpaid interest is due on October 14, 2006. Our obligations under the Theta loan are guaranteed by each of our principal subsidiaries. We borrowed $50.0 million under this loan on October 14, 2005 and we will use a portion of the proceeds from this offering to repay those borrowings in full.

Capital Expenditures.  In May 2002, we purchased seven drilling rigs ranging 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. for $12.5 million in cash. After accepting delivery of the rigs, we spent approximately $97,000 upgrading the rigs before placing them into service. The acquisitions in 2002 were funded through capital infusions from our equity holders.

In August 2003, we purchased all of the outstanding stock of Elk Hill Drilling, Inc. and certain drilling rig structures and components from an affiliate of Elk Hill, U.S. Rig & Equipment, for $33.5 million in cash plus the assumption of $15.5 million of deferred tax liabilities. In these transactions, we acquired drilling rigs and inventoried structures and components which, with refurbishment and upgrades, can be used to assemble 22 drilling rigs. At the date of its acquisition, Elk Hill had no customers, employees, operations or operational drilling rigs. As discussed below, we began refurbishing the acquired rigs and deploying one rig per quarter since the acquisition. For accounting purposes, the Elk Hill and U.S. Rig and Equipment acquisitions were treated as acquisitions by our members and then contributions to us. In November 2003, we completed the refurbishment of a 1,400-horsepower electric drilling rig, which we designated as Rig No. 16. We incurred approximately $2.2 million in refurbishment costs for this rig before it was mobilized to Southern Oklahoma in November 2003. The acquisitions and refurbishment expenditures in 2003 were funded through capital infusions from our equity holders.

In March 2004, we completed the refurbishment of a 1,500-horsepower electric drilling rig, which we designated as Rig No. 12. We incurred approximately $2.3 million in refurbishment costs for this rig which we financed with borrowings under our GECC credit facility. We mobilized Rig No. 12 to Grayson County, Texas in March 2004.

In May 2004, we completed the refurbishment of a 1,000-horsepower electric drilling rig, which we designated as Rig No. 11. We incurred approximately $2.7 million in refurbishment costs for this rig. We mobilized Rig No. 11 to Southern Oklahoma in May 2004. In August 2004, we completed the refurbishment of a 1,000-horsepower electric drilling rig, which we designated as Rig No. 10. We incurred approximately $3.2 million in refurbishment costs for this rig. We mobilized Rig No. 10 to Western Oklahoma in August 2004. In December 2004, we completed the refurbishment of a 2,000-horsepower electric drilling rig, which we designated as Rig No. 18. We incurred approximately $4.8 million in refurbishment costs for this rig. We mobilized Rig No. 18 to Eastern Oklahoma in December 2004. Our refurbishment costs for these rigs were financed with borrowings under our GECC credit facility.

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In March 2005, we completed the refurbishment of a 1,200-horsepower electric drilling rig, which we designated as Rig No. 14. We incurred approximately $4.8 million in refurbishment costs for this rig which we financed with borrowings under our GECC credit facility. We mobilized Rig No. 14 to Southern Oklahoma in March 2005.

In July 2005, we completed the refurbishment of a 2,500-horsepower electric drilling rig, which we designated as Rig No. 19. We incurred approximately $6.6 million in refurbishment costs for this rig which we financed with borrowings under our GECC credit facility. We mobilized Rig No. 19 to Southern Oklahoma in July 2005.

In July 2005, we acquired three drilling rigs of 650, 800 and 1,000 horsepower, and related inventory, equipment and components, through our acquisitions of Strata Drilling, L.L.C. and Strata Property, L.L.C., together with a related rig yard, for an aggregate of $20.0 million. The acquisitions were funded with borrowings of $13.0 million from Alpha Investors LLC, an entity controlled by Wexford, and our delivery of promissory notes for an aggregate of $7.0 million.

In September 2005, we acquired all the outstanding common stock of Hays Trucking, Inc. for $3.0 million in cash, which includes the repayment of $1.9 million of debt owed by Hays Trucking, and 65,368 shares of our common stock. In this acquisition, we acquired 18 trucks used to mobilize our rigs to contracted drilling locations.

On October 3, 2005, we purchased 12 rigs from Eagle Drilling, L.L.C. and two of its affiliates. The acquisition involved five operating rigs, seven inventoried rigs and equipment and parts for a purchase price of approximately $50.0 million. We funded this acquisition with borrowings under our Merrill Lynch term loan and a portion of the proceeds from our initial public offering.

On October 14, 2005, we purchased 13 rigs from Thomas Drilling Co. The acquisition involved nine operating rigs, two rigs that are currently being refurbished, two inventoried rigs and rig equipment and parts for a purchase price of approximately $68.0 million. We funded $50.0 million of the purchase price with borrowings under the Theta loan and the remainder with a portion of the proceeds from our initial public offering.

We intend to use a portion of the net proceeds from the sale of shares of our common stock in this offering to repay approximately $50.0 million in borrowings incurred in connection with our Thomas acquisition under the Theta loan. We intend to use the balance of the net proceeds, together with cash from operations, to refurbish rigs in our inventory and for general corporate purposes, which may include the purchase of additional rigs. Pending the use of the remaining net proceeds for refurbishment and general corporate purposes, we may repay a portion of our borrowings under our Merrill Lynch term installment loan.

We intend to refurbish rigs in our inventory at estimated costs (including drill pipe) ranging from $900,000 million to $6.8 million per rig. We plan on completing the refurbishment of four additional inventoried rigs by the end of 2005 and ten inventoried rigs during 2006. Initially, we intend to focus our refurbishment program on our more powerful rigs with 1,000 to 2,000 horsepower, which are capable of drilling to depths between 15,000 and 25,000 feet. The amounts and timing of our actual expenditures will depend upon market and other factors including our estimation of existing and anticipated demand and dayrates, our success in bidding for domestic contracts, including term contracts, and the timing of the refurbishments. The actual cost of refurbishing these rigs will also depend upon various factors including shortages of equipment, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, inability to obtain necessary certifications and approvals, shortages of materials or skilled labor and the specific customer requirements and to the extent that we choose to upgrade these rigs to meet such requirements.

We believe that cash flow from our operations, borrowings under credit facilities we have in place from time to time and proceeds from this offering will be sufficient to fund our operations for at least the next twelve

months. However, additional capital will likely 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.

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Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments at June 30, 2005 (in thousands):

			Payments Due by Period
Contractual Obligations	Total		Less than One Year		1-3 Years		3-5 Years		More than 5 Years
Short- and long-term debt	$	40,000	$	7,100	$	22,200	$	5,700	$	5,000
Operating leases		2,332		272		748		408		904
Total contractual cash obligations	$	42,332	$	7,372	$	22,948	$	6,108	$	5,904

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. Our new term loan with Merrill Lynch provides for interest on borrowings at a floating rate equal to LIBOR plus 271 basis points (6.39% at September 2, 2005 and upon the initial borrowing under this facility) and borrowings under our International Bank of Commerce credit facility bear interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime (6.25% at June 30, 2005) and borrowings under our Theta loan bear interest at a floating rate equal to LIBOR plus 400 basis points (7.98% at October 14, 2005 and upon the initial borrowing under this facility) until December 31, 2005, and thereafter at a rate equal to LIBOR plus 600 basis points. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $595,000 annually, based on the $96.0 million outstanding in the aggregate under our loans and credit facilities as of October 15, 2005.

Recent Accounting Pronouncements

SFAS No. 123(R)

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 123(R), Share Based Payment, which revised SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) requires entities to measure the fair value of equity share-based payments (stock compensation) at grant date, and recognize the fair value over the period during which an employee is required to provide services in exchange for the equity instrument as a component of the income statement. SFAS No. 123(R) is effective for annual periods beginning after June 15, 2005. Prior to our initial public offering in August 2005, we did not have any stock option plans and, therefore the adoption of SFAS No. 123(R) had no impact on our financial position or results of operations. However, in connection with our initial public offering in August 2005, we implemented our 2005 Stock Incentive Plan and granted stock options to certain of our employees and certain non-employee directors. We will recognize the fair value of these and other options which may be granted as an expense over the periods during which the option holders provide services to earn the options.

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BUSINESS

General

We provide contract land drilling services to oil and natural gas exploration and production companies. We currently own a fleet of 58 land drilling rigs, of which 30 are currently operating, six are in the process of being refurbished and 22 are held in inventory. We expect to put four of the rigs currently being refurbished into service by the end of 2005 and the other two into service by the end of the first quarter of 2006. In addition we plan on refurbishing eight additional rigs from our current inventory during 2006, at estimated costs (including drill pipe) ranging from $4.1 million to $6.8 million per rig. Initially, we intend to focus our refurbishment program on our more powerful rigs, with 1,000 to 2,000 horsepower, which are capable of drilling to depths between 15,000 and 25,000 feet. We also own a fleet of 41 trucks used to transport our rigs.

We commenced operations in 2001 with the purchase of one stacked 650-horsepower rig that we refurbished and deployed. We subsequently made selective acquisitions of both operational and inventoried rigs, as well as ancillary equipment. Our most recent acquisitions were completed in October 2005 when we purchased 12 land drilling rigs from Eagle Drilling, L.L.C. for approximately $50.0 million and 13 land drilling rigs from Thomas Drilling Co. for approximately $68.0 million. These transactions not only increased the size of our rig fleet, but also expanded our operations to the Barnett Shale trend in North Texas. In July 2005, we completed a transaction with Strata Drilling, L.L.C. and Strata Property, L.L.C. in which we acquired, among other assets, three land drilling rigs and a 16 acre storage and refurbishment yard for $20.0 million.

Our management team has significant experience not only with acquiring rigs, but also with refurbishing and deploying inventoried rigs. We have successfully refurbished and brought into operation eight of the 22 inventoried drilling rigs we acquired in August 2003. These rigs were refurbished on schedule and for a total cost that was within ten percent of the amount budgeted. Upon completion of refurbishment, the rigs either met or exceeded our operating expectations. In addition, we have recently opened a 41,000 square foot machine shop in Oklahoma City which allows us to refurbish and repair our rigs and equipment in-house. This facility, which complements our existing rig yard in Oklahoma City, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays.

We currently operate in Oklahoma, the Barnett Shale trend in North Texas and the Piceance Basin in Colorado. A majority of the wells we have drilled for our customers have been drilled in search of natural gas reserves. Natural gas is often found in deep and complex geologic formations that generally require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 58 rigs includes 30 rigs ranging from 950 to 2,500 horsepower. Accordingly, such rigs can, or in the case of inventoried rigs upon refurbishment will be able to, reach the depths required to explore for deep natural gas reserves. Our higher horsepower rigs can also drill horizontal wells, which are increasing as a percentage of total wells drilled in North America. We believe our premium rig fleet, rig inventory and experienced crews position us to benefit from the strong natural gas drilling activity in our core operating area.

Recent Developments

We recently completed two acquisitions that have further expanded our fleet of land drilling rigs.

• The Eagle Acquisition.  On October 3, 2005, we purchased 12 rigs from Eagle Drilling, L.L.C. and two of its affiliates. This acquisition involved five operating rigs, seven inventoried rigs and rig equipment and parts for a purchase price of approximately $50.0 million. We intend to refurbish two rigs from inventory by the end of 2006 for a total cost of approximately $11.9 million. We estimate that our costs to refurbish the remaining five inventoried rigs will range from $900,000 million to $6.0 million per rig.

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• The Thomas Acquisition.  On October 14, 2005, we purchased 13 rigs from Thomas Drilling Co. The transaction included nine operating rigs, two rigs currently being refurbished, two inventoried rigs and rig equipment and parts for a purchase price of approximately $68.0 million. In connection with this acquisition, we leased an additional rig refurbishment yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000. We intend to use the Thomas yard to complete the refurbishment of two Thomas rigs in 2006. We estimate our total cost to complete the refurbishment of these rigs will be approximately $4.6 million. We estimate that our costs to refurbish the remaining rigs will be approximately $1.7 million per rig.

Upon completion of the Eagle and Thomas acquisitions, our rig fleet increased to 58 rigs, 30 of which are operating rigs and 28 of which are either in the refurbishment process or held in inventory. Seven of the rigs included in the Eagle and Thomas acquisitions are operating in Texas, including six in the Barnett Shale trend in North Texas, with the balance of the operating rigs drilling in Oklahoma.

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

Date	Acquisition	Acquisition Cost	Number of Rigs Acquired
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

In May 2002, we purchased seven drilling rigs ranging in size from 400 to 950 horsepower, associated spare parts and equipment, drill pipe, haul trucks, and vehicles from Bison Drilling L.L.C. and Four Aces Drilling L.L.C. After accepting delivery of the rigs, we spent approximately $97,000 upgrading the rigs before placing them into service. In August 2003, we purchased all of the outstanding stock of Elk Hill Drilling, Inc. 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, can be used to assemble 22 drilling rigs. At the date of its acquisition, Elk Hill was an inactive corporation with no customers, employees, operations or operational drilling rigs. We began refurbishing the acquired rigs and have deployed approximately one rig per quarter since the acquisition. In July 2005, we acquired all of the membership interests of Strata Drilling, L.L.C. and Strata Property, L.L.C. Included in these acquisitions were two operating rigs, one rig that is currently being 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. 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 completed the Eagle and Thomas acquisitions, both as described above.

Our Industry

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

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influence the number of wells oil and natural gas exploration and production companies decide to drill. Nevertheless, we believe that the following trends in our industry should benefit our operations:

• Need for increased natural gas drilling activity as U.S. demand growth outpaces U.S. supply growth.  From 1994 to 2003, demand for natural gas in the United States grew at an annual rate of 0.6% while the U.S. domestic supply grew at an annual rate of 0.2%. The Energy Information Administration, or EIA, recently estimated that U.S. domestic consumption of natural gas exceeded domestic production by 17% in 2004, a gap that the EIA forecasts will expand to 24% in 2010.

Source:  EIA.

• Increased decline rates in natural gas basins in the U.S.  As the chart above shows, even though the number of U.S. natural gas wells drilled has increased significantly, a corresponding increase in production has not been realized. We believe that a significant reason for the limited supply response, even as drilling activities have increased, is the accelerating decline rates of production from new natural gas wells drilled. A study published by the National Petroleum Council in September 2003 concluded, from analysis of production data over the preceding ten years, that as a result of domestic natural gas decline rates of 25% to 30% per year, 80% of natural gas production in ten years will be from wells that have not yet been drilled. We believe that this tends to support a sustained higher natural gas price environment, which should create incentives for oil and natural gas exploration and production companies to increase drilling activities in the U.S.

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• Trend towards drilling and developing unconventional natural gas resources.  As a result of improvements in extraction technologies along with general increases in natural gas prices, oil and natural gas companies increasingly are exploring for and developing “unconventional” natural gas resources, such as natural gas from tight sands, shales and coalbed methane. This type of drilling activity is frequently done on tighter acreage spacing, and requires that more wells be drilled. It also requires higher horsepower rigs for techniques such as horizontal drilling. The chart below shows the U.S. land rig count is significantly higher than it has been in recent years.

U.S. Land Rig Count

Source: Baker Hughes

• High natural gas prices.  While U.S. natural gas prices are volatile, year to date 2005 marks the third consecutive year of increases in the yearly average NYMEX near month natural gas contract prices, as shown on the chart below. We believe that high natural gas prices in the U.S., if sustained, should result in more exploration and development drilling activity, and thus higher utilization and dayrates for drilling companies like us.

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Source:  Bloomberg.

• Increases in dayrates and operating margins for land drilling.  The increase in the price of natural gas, coupled with accelerating decline rates and an increase in the number of natural gas wells being drilled, have resulted in increases in rig utilization, and consequently improved dayrates and cash margins.

Our Strengths

Our competitive strengths include:

• Premium rig fleet.  We currently operate a fleet of 30 rigs, eleven of which have been refurbished since August 2003. Natural gas reserves are often found in deep and complex geological formations that require higher horsepower or premium rigs to drill. In addition, the recovery of unconventional natural gas resources often involves horizontal drilling techniques that also require premium rigs with approximately 1,000 or more horsepower. We believe that our operating history and high-quality rig fleet position us to benefit from this type of drilling activity.

• Inventory of drilling rigs and ancillary equipment.  In addition to our six rigs currently being refurbished, our 22 drilling rigs held in inventory for refurbishment will allow us to add capacity in response to the currently strong land drilling market. We also have an inventory of excess drawworks, hooks, blow-out preventors and other rig-related equipment. Our inventoried rigs as well as many of the parts we have in inventory would have long delivery lead times if ordered new.

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• Ability to refurbish inventoried rigs.  Our management team has demonstrated the ability to refurbish rigs from our inventory. Since our acquisition of 22 inventoried drilling rigs in August 2003, we have successfully refurbished and placed into service eight of the rigs at costs ranging from $2.2 million to $6.6 million per rig. Through the efforts of our management team and experienced yard labor crews, these rigs were refurbished on schedule and for a total cost that was within ten percent of the amount budgeted. We are currently refurbishing six additional rigs, five of which range from 1,000 to 1,700 horsepower. We expect four of these rigs to be ready for deployment by the end of 2005 and the other two of these rigs to be ready for deployment by the end of the first quarter of 2006. In connection with the Thomas acquisition, we leased the use of an additional refurbishment yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000.

• Ability to attract and retain qualified rig crews.  We believe that our premium rig fleet and experienced management team allow us to successfully attract and retain qualified rig crews relative to some larger, more diversified land drilling companies. As a result, we believe we have been able to refurbish rigs from our inventory and put them into operation without sacrificing our operating quality.

Our Strategy

Our strategy is to continue to expand our contract land drilling services. Specifically, we intend to:

• Refurbish and deploy rigs from our inventory.  We intend to continue the refurbishment and deployment of our inventoried rigs. We plan on completing the refurbishment of four additional rigs from our current inventory that are currently being refurbished by the end of 2005 and two by the end of the first quarter of 2006. We also intend to refurbish eight more rigs from our current inventory during 2006 at estimated costs ranging from $4.1 million to $6.8 million per rig. Initially, we intend to focus our refurbishment program on our higher horsepower rigs. As a result of the Thomas acquisition, we added the use of an additional rig refurbishment yard. We have recently hired additional experienced refurbishing crews, which we believe will complement the experienced crews we currently have in place. Our five rig-up supervisors have an average of 31 years of experience in the drilling industry.

• Expand our rig fleet and geographic focus.  We intend to continue to expand our rig fleet and geographic areas of operation by making selected acquisitions and mobilizing rigs to other regions. We are currently operating in Oklahoma, the Barnett Shale trend in North Texas and the Piceance Basin in Colorado. We began operations in the Barnett Shale with seven rigs through our recent Eagle and Thomas acquisitions. In addition, we are evaluating additional expansion opportunities in the Rocky Mountains and the Cotton Valley trend in Central and East Texas. We also regularly evaluate other potential acquisitions of rigs and ancillary operations.

• Maintain a balanced portfolio of spot and term contracts.  We plan on managing our rig fleet as a portfolio, committing some of our rigs to longer-term contracts that meet our targeted returns on invested capital, and leveraging spot market rates with other rigs. As we expand our geographic focus, we initially plan on favoring longer-term contracts in our new markets until we gain operating maturity in those markets.

• Maintain a conservative capital structure and disciplined approach to capital spending.  We believe that our post-offering balance sheet will allow us to pursue opportunities to grow our business. We will continue to evaluate investment opportunities, including potential acquisitions and additional rig refurbishments, that meet our targeted returns on invested capital.

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Drilling Equipment

General

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

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

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

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

Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a

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shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.

There are numerous factors that differentiate drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons.

Our Fleet of Drilling Rigs

Our rig fleet consists of 58 drilling rigs, of which 30 are currently operating, six are in the process of being refurbished and 22 are held in inventory. We expect to put four of the rigs currently being refurbished into service by the end of 2005 and the other two by the end of the first quarter of 2006. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of operating drilling rigs:

	Six Months Ended June 30,				Year Ended December 31,
	2005		2004		2004		2003		2002
Average number of operating rigs	12		9		9		7		2
Average utilization rate	94	%	73	%	81	%	76	%	58	%

The following table sets forth information regarding our drilling fleet as of October 14, 2005:

Rig	Design	Approximate Drilling Depth (ft)	Type	Horsepower
Working Rigs
19	Mid Continent U-1220 EB	25,000	Electric	2,500
18	Gardner Denver 1500E	25,000	Electric	2,000
12	Gardner Denver 1100E	18,000	Electric	1,500
16	Oilwell 840E	18,000	Electric	1,400
14	Mid Continent U-712-EA	16,000	Electric	1,200
77	Ideco 711	16,000	Mechanical	1,200
78	Seaco 1200	12,000	Mechanical	1,200
56	BDW 800 MI	16,500	Mechanical	1,100
60	Skytop Brewster N46	14,000	Mechanical	1,100
11	Gardner Denver 800E	15,000	Electric	1,000
10	Gardner Denver 800E	15,000	Electric	1,000
3	Cabot 900	10,000	Mechanical	950
4	Skytop Brewster N46	14,000	Mechanical	950
51	Skytop Brewster N42	12,000	Mechanical	850
52	Continental Emsco G-500	11,000	Mechanical	850
53	Skytop Brewster N42	12,000	Mechanical	850
54	Skytop Brewster N46	13,000	Mechanical	850
55	National 50-A	12,000	Mechanical	850
59	Skytop Brewster N46	13,000	Mechanical	850
61	National 50-A	11,500	Mechanical	850
41	Skytop-Brewster N-46	13,500	Mechanical	800
72	Skytop Brewster N45	10,000	Mechanical	750
75	Ideco 750	14,000	Mechanical	750
76	National N55	12,000	Mechanical	700
42	Gardner Denver 500	12,000	Mechanical	650
9	Gardner Denver 500	11,000	Mechanical	650
7	Mid Con U36A	12,000	Mechanical	650
6	Mid Con U36A	12,000	Mechanical	650
5	Mid Con U36A	12,000	Mechanical	650
2	Cardwell L-350	6,000	Mechanical	400

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Rig	Design	Approximate Drilling Depth (ft)	Type	Horsepower
Rigs Being Refurbished
17	Skytop Brewster NE-95	20,000	Electric	1,700
15	Mid Continent U-712-EA	16,000	Electric	1,200
57	Continental Emsco GB800	16,500	Mechanical	1,100
43	National 80B	15,000	Mechanical	1,000
8	National 80-UE	15,000	Electric	1,000
58	Unit U-15	10,200	Mechanical	800
Rigs in Inventory
24	Skytop Brewster N-12	25,000	Electric	2,000
25	National 1320-UE	18,000	Electric	2,000
27	National 1320-UE	18,000	Electric	2,000
73	Brewster N95	18,000	Mechanical	1,700
74	Mid Con 914	16,000	Mechanical	1,400
79	Mid Con 914	16,000	Mechanical	1,400
20	Mid Continent U-914-EC	18,000	Electric	1,400
21	Mid Continent U-914-EC	18,000	Electric	1,400
22	Continental Emsco D-3	15,000	Electric	1,000
23	Continental Emsco D-3	15,000	Electric	1,000
26	National 80-UE	15,000	Electric	1,000
28	Ideco 1200E	15,000	Electric	1,000
80	Skytop Brewster N45	10,000	Mechanical	750
31	Oilwell 660	12,000	Mechanical	700
71	National N55	12,000	Mechanical	700
62	Schaffer SOS 6000	8,000	Mechanical	650
30	Skytop Brewster N42	10,000	Mechanical	600
32	Schaffer 6000S	10,000	Mechanical	600
70	National T32	6,000	Mechanical	450
81	National T32	6,000	Mechanical	450
1	Cardwell L-350	5,000	Mechanical	400
64	National T-32	6,000	Mechanical	325
Excess Rig Inventory
33	Oilwell 500	10,000	Mechanical	500
34	Mac 400	6,000	Mechanical	400
35	Mid Continent U34B	6,000	Mechanical	400
36	Ideco H-35 Hydrair	6,000	Mechanical	400

Working Rigs

We currently have 30 operating rigs. Two of the rigs are operating on two-year term contracts expiring in April and August 2007, respectively, and three rigs are operating on one-year term contracts, two of which expire in August 2006 and one of which expires in September 2006, and twenty-five of the rigs are operating on a well-to-well basis. Eleven of the 30 rigs we currently operate have undergone significant refurbishment since August 2003.

Rig 19. This Mid-Continent U-1220 EB rig was acquired as part of the Elk Hill acquisition. We refurbished this rig from inventory at a cost of approximately $6.6 million and deployed it in July 2005. It is currently working in Stephens County, Oklahoma under a two-year term contract that expires in August 2007.

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Rig 18. This Gardner Denver 1500E rig was acquired in the Elk Hill acquisition. We refurbished this rig from inventory at a cost of approximately $4.8 million and deployed it in December 2004. It has been working for the same operator since it was refurbished. It is currently working in Haskell County, Oklahoma on a well-to-well basis.

Rig 12. This Gardner Denver 1100E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $2.3 million and deployed it in March 2004. It is currently working in Caddo County, Oklahoma under a two-year term contract that expires in April 2007.

Rig 16. This Oilwell 840E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $2.2 million and deployed it in October 2003. It is currently working in Caddo County, Oklahoma on a well-to-well basis.

Rig 14. This Mid-Continent U-712-EA rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $4.8 million and deployed it in March 2005. It is currently working on a term contract in Eastern Oklahoma.

Rig 77. This Ideco 711 rig was acquired as part of the Eagle acquisition. It is currently working in Atoka County, Oklahoma on a well-to-well basis.

Rig 78. This Seaco 1200 rig was acquired as part of the Eagle acquisition. It is currently working in Johnson County, Texas on a one-year term contract.

Rig 56. This BDW 800 MI was acquired as part of the Thomas acquisition. It is currently operating in Stephens County, Oklahoma on a well-to-well basis.

Rig 60. This Skytop Brewster N46 was acquired as part of the Thomas acquisition. It is currently operating in Wise County, Texas on a well-to-well basis.

Rig 11. This Gardner Denver 800E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $2.7 million and deployed it in May 2004. It is currently working in Garvin County, Oklahoma on a well-to-well basis.

Rig 10. This Gardner Denver 800E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $3.2 million and deployed it in August 2004. It is currently working in Caddo County, Oklahoma on a well-to-well basis.

Rig 3. This Cabot 900 was acquired in the Bison Drilling acquisition. It has been drilling horizontal wells in Seminole County, Oklahoma for the same operator since November 2004. This rig is working on a well-to-well basis.

Rig 4. This Skytop Brewster N46 rig was acquired as part of the Bison acquisition. We completed refurbishment of this rig in August 2005. It is currently working in the Piceance Basin in Colorado under a one-year term contract that expires in September 2006.

Rig 51. This Skytop Brewster N42 was acquired as part of the Thomas acquisition. It is currently operating in Kingfisher County, Oklahoma on a well-to-well basis.

Rig 52. This Continental Emsco G-500 was acquired as part of the Thomas acquisition. It is currently operating in Woods County, Oklahoma on a well-to-well basis.

Rig 53. This Skytop Brewster N42 was acquired as part of the Thomas acquisition. It is currently operating in Stephens County, Oklahoma on a well-to-well basis.

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Rig 54. This Skytop Brewster N46 was acquired as part of the Thomas acquisition. It is currently operating in Stephens County, Oklahoma on a well-to-well basis.

Rig 55. This National 50-A was acquired as part of the Thomas acquisition. It is currently operating in Denton County, Texas on a well-to-well basis.

Rig 59. This Skytop Brewster N46 was acquired as part of the Thomas acquisition. It is currently operating in Coal County, Oklahoma on a well-to-well basis.

Rig 61. This National 50-A was acquired as part of the Thomas acquisition. It is currently operating in Grayson County, Texas on a well-to-well basis.

Rig 41. This Skytop Brewster N-46 rig was acquired as part of the Strata acquisitions. It has been working for the same operator for the last three years in Central and Western Oklahoma. This rig is currently working in Grady County, Oklahoma on a well-to-well basis.

Rig 72. This Skytop Brewster N45 rig was acquired as part of the Eagle acquisition. It is currently working in Parker County, Texas on a well-to-well basis.

Rig 75. This Ideco 750 rig was acquired as part of the Eagle acquisition. It is currently working in Denton County, Texas on a well-to-well basis.

Rig 76. This National N55 rig was acquired as part of the Eagle acquisition. It is currently working in Johnson County, Texas on a well-to-well basis.

Rig 42. This Gardner Denver 500 rig was acquired as a part of the Strata acquisitions. It has been working for the same operator for the last three years in Central and Western Oklahoma. This rig is currently working in Blaire County, Oklahoma on a well-to-well basis.

Rig 9. This Gardner Denver 500 was acquired in the Ram acquisition. It has been drilling horizontal wells in Oklahoma County, Oklahoma for the same operator since March 2004. This rig is working on a well-to-well basis.

Rig 7. This Mid-Continent U36A was acquired in the Bison Drilling acquisition. It is drilling a well in Atoka County, Oklahoma on a well-to-well basis.

Rig 6. This Mid-Continent U36A was acquired in the Bison Drilling acquisition. It has been drilling in Beckham, Woodward and Major Counties, Oklahoma for the same operator since March 2004. This rig is working on a well-to-well basis.

Rig 5. This Mid-Continent U36A was acquired in the Bison Drilling acquisition. It is drilling in Grady County, Oklahoma on a well-to-well basis.

Rig 2. This Cardwell L-350 was acquired in the Bison Drilling acquisition. It works primarily in the Arkoma Basin in Eastern Oklahoma. This rig is currently working in Hughes County, Oklahoma on a well-to-well basis.

Rigs Being Refurbished

We are currently in the process of refurbishing six rigs, four of which we anticipate will be completed by the end of 2005.

Rig 17. This Skytop Brewster NE-95 rig was acquired as part of the Elk Hill acquisition. We started its refurbishment in August 2005 and anticipate the rig will be complete and drill ready by the end of 2005. We intend to mobilize Rig 17 to Western Oklahoma under a term contract.

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Rig 15. This Mid-Continent U-712-EA rig was acquired as part of the Elk Hill acquisition. We started its refurbishment in August 2005 and anticipate the rig will be complete and drill ready by the end of 2005.

Rig 57. This Continental Emsco GB800 was acquired as part of the Thomas acquisition. We started its refurbishment in October 2005 and anticipate that it will be complete and drill ready by the end of the first quarter 2006.

Rig 43. This National 80B rig is currently being rigged up in our Oklahoma City yard. It was acquired as part of the Strata acquisitions and anticipate the rig will be complete and drill ready in the fourth quarter of 2005.

Rig 8. This National 80-UE rig was acquired as part of the Elk Hill acquisition. We started its refurbishment in June 2005 and anticipate the rig will be complete and drill ready in the fourth quarter of 2005. We intend to mobilize Rig 8 to the Rocky Mountains under a term contract.

Rig 58. This Unit U-15 was acquired as part of the Thomas acquisition. We started its refurbishment in October 2005 and anticipate that it will be complete and drill ready by the end of the first quarter 2006.

Rigs in Inventory

We currently have 22 rigs held in inventory in our rig yards in Oklahoma. We define an inventoried rig as a rig that is included in our refurbishment plan and has been assigned a start and delivery date.

Rig 20. This Mid-Continent U-914-EC rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in October 2005 and believe it can be delivered in the first quarter of 2006. We have ordered a new derrick and substructure, drill pipe, power packages and SCR house which are scheduled for delivery beginning in the fourth quarter of 2005.

Rig 23. This Continental Emsco D-3 rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in March 2006 and believe it can be delivered in the second quarter of 2006. We have ordered drill pipe, derrick and substructure power packages and SCR house which are scheduled for delivery beginning in the first quarter of 2006.

Rig 24. This Skytop Brewster NE-12 rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in April 2006 and believe it can be delivered in the third quarter of 2006. We have ordered drill pipe, power packages and SCR house which are scheduled for delivery beginning in the first quarter of 2006.

Rig 73. This Skytop Brewster N95 was acquired as part of the Eagle acquisition. We intend to start its refurbishment in April 2006 and believe it can be delivered in the third quarter of 2006.

Rig 21. This Mid-Continent U-914-EC rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in October 2005 and believe it can be delivered in the third quarter of 2006. We have ordered a new derrick and substructure, drillpipe, power packages and SCR house which are scheduled for delivery beginning in the fourth quarter of 2005.

Rig 22. This Continental Emsco D-3 rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in October 2005 and believe it can be delivered in the fourth quarter of 2006. We have ordered drill pipe, power packages and SCR house which are scheduled for delivery beginning in the fourth quarter of 2005.

Rig 74. This Mid-Continent 914 was acquired as part of the Eagle acquisition. We intend to start its refurbishment in July 2006 and believe it can be delivered in the fourth quarter of 2006.

Rig 25. This National 1320-UE rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in May 2006 and believe it can be delivered by the end of 2006. We have ordered drill pipe, power packages and SCR house which are scheduled for delivery beginning in the first quarter of 2006.

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We intend to refurbish and deploy our remaining rigs held in inventory on a periodic basis, with such refurbishment currently scheduled for completion by the end of the second quarter of 2008.

Excess Rig Inventory

We currently have four rigs which we believe can be refurbished, but are not currently part of our refurbishment plan. We periodically review the market, our financial condition and our refurbishment yard capacity to determine if we will add additional rigs to our refurbishment plan.

Excess Equipment

As of October 14, 2005, we had an inventory of excess rig equipment that includes 39 drawworks (30 of which are 1,000 horsepower or higher), 79 blocks, 65 blow out preventors, 14 electric brakes, 52 hydromatic brakes, 55 rotary tables and 30 swivels. This inventoried equipment could be used with newly ordered or purchased parts to build additional rigs.

As of June 30, 2005, we owned a fleet of 17 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and reduce downtime between rig moves. In August 2005, we acquired 18 trucks in connection with our acquisition of Hays Trucking, Inc.

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

Drilling Contracts

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

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

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The following table presents, by type of contract, information about the total number of wells we completed for our customers during the six months ended June 30, 2005 and 2004 and the years ended December 31, 2004, 2003 and 2002.

	Six Months Ended June 30,		Year Ended December 31,
	2005	2004	2004	2003	2002
Daywork	50	35	80	41	13
Footage	5	8	11	28	5
Turnkey	—	—	—	—	—
Total number of wells	55	43	91	69	18

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

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

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

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

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Customers and Marketing

We market our rigs to a number of customers. In 2004, we drilled wells for 29 different customers, compared to 34 customers in 2003 and 12 customers in 2002. The following table shows our customers which accounted for more than 5% of our total contract drilling revenue for each of our last three years.

Customer	Total Contract Drilling Revenue Percentage
2004
Carl E. Gungoll Exploration, L.L.C.	11	%
Western Oil and Gas Development Co.	9	%
New Dominion, L.L.C.	9	%
Chesapeake Energy Corporation.	7	%
XTO Energy	7	%
Triad Energy	6	%
Ward Petroleum Corp.	6	%
2003
Carl E. Gungoll Exploration, L.L.C.	13	%
Zinke and Trumbo, Inc.	11	%
Questar Exploration & Production	8	%
Medicine Bow Operating Co.	8	%
Apache Corporation	7	%
2002
Westport Oil and Gas Company, L.P.	23	%
Prime Operating Company	16	%
Windsor Energy Group, L.L.C.	13	%
BRG Petroleum Corp.	7	%
Carl E. Gungoll Exploration, L.L.C.	7	%
King Energy, L.L.C.	7	%
Titan Resources	6	%

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

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

Competition

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

The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal competitors are Nabors Industries, Inc., Patterson-UTI Energy, Inc., Unit Corp. and Helmerich & Payne, Inc. We

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

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

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Operating Risks and Insurance

Our operations are subject to the many hazards inherent in the contract land drilling 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. Those risks include pollution liability in excess of relatively low limits. 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 deductible on rigs of $1.0 million per occurrence and a $40.0 million aggregate stop loss. Our third-party liability insurance coverage is $5.0 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.

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Employees

As of October 13, 2005, we had approximately 480 employees. Approximately 60 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. 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. In addition, in connection with the Eagle and Thomas acquisitions, we hired approximately 125 and 210, respectively, of their former employees.

Certain personnel of our affiliate, Gulfport Energy Corporation, provide administrative services to us, including accounting, human resources, legal and technical support. We reimbursed Gulfport for its dedicated employee time, office space and general and administrative costs based upon the pro rata share of time its employees spend performing services for us. Effective April 1, 2005, we entered into an administrative services agreement with Gulfport with respect to those services. See “Certain Relationships and Related Party Transactions—Administrative Services Agreement and Lease of Space” for additional information regarding the administrative services agreement.

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 are occurring 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.

Facilities

Our corporate headquarters is located at 14313 North May Avenue, Oklahoma City, Oklahoma in an office building owned by our affiliate, Gulfport. We lease approximately 1,100 square feet of space in the office building for which we pay Gulfport approximately $1,740 per month. This lease of office space is included in our administrative services agreement with Gulfport. The administrative services agreement has a three-year term, and upon expiration, it will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by us at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such default. See “Certain Relationships and Related Party Transaction—Administrative Services Agreement and Lease of Space” for further discussion regarding the administrative services agreement.

We own a 16 acre yard in Oklahoma City, Oklahoma which we acquired in connection with our Strata acquisitions. This yard is used for equipment storage and the refurbishment of stacked rigs. In addition, we lease the following from unaffiliated third parties:

• a 13 acre yard used for equipment storage and the refurbishment of our stacked rigs in Duncan, Oklahoma;

• a 15 acre yard which includes an operations office, rig and equipment storage and a repair facility in Oklahoma City, Oklahoma;

• a 16 acre yard used for equipment storage and the refurbishment of our stacked rigs in Oklahoma City, Oklahoma;

• a 10 acre yard used as our trucking fleet headquarters in Noble, Oklahoma;

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• a 10 acre yard used to dispatch trucks in Seminole, Oklahoma;

• a 5 acre yard used to dispatch trucks in Woodward, Oklahoma; and

• a 13 acre yard which includes our machine shop used for drilling rig refurbishment, repair and maintenance in Oklahoma City, Oklahoma.

In connection with the Thomas acquisition, we leased the Duncan, Oklahoma yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000. We intend to use this yard to complete the refurbishment of the two Thomas rigs that are currently being refurbished and two of the Eagle rigs. We expect the refurbishment of all four of these rigs to be completed in 2006.

We believe these facilities are adequate to serve our current and anticipated needs.

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 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 which 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, CERCLA, the Safe Drinking Water Act, 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

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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.

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.

Legal Proceedings

We are plaintiffs in a lawsuit involving Atoka Operating, Inc., the defendant, originally filed by us on September 7, 2004 in the 15th Judicial District Court, Grayson County, Texas. This is a breach of contract suit or, alternatively, a suit on a sworn account wherein we sued the defendant for $942,000 as a result of the defendant’s refusal to make payment pursuant to the terms of a drilling contract. The defendant filed a counterclaim on October 11, 2004 for damages in excess of $2.8 million, alleging breach of contract, negligence, gross negligence and breach of warranties. Discovery is ongoing and no trial date has yet been set by the Court. We are vigorously prosecuting our claims and defending against the counterclaims in this matter and will continue to file appropriate responses, motions and documents as necessary. It is not possible to predict the outcome of this matter.

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, with the exception of the matter discussed in the prior paragraph, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition or results of operations.

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MANAGEMENT

Executive Officers and Directors

Set forth below is the name, age, position and a brief account of the business experience of each of our executive officers and directors.

Name	Age	Position
D. Frank Harrison	57	Chief Executive Officer, President and Director
Zachary M. Graves	30	Chief Financial Officer, Secretary and Treasurer
Karl W. Benzer	54	Chief Operating Officer
Mike Liddell	52	Chairman of the Board and Director
David L. Houston	52	Director
Michael O. Thompson	52	Director
Phillip Lancaster	47	Director

D. Frank Harrison has served as served as Chief Executive Officer and a director of our company since May 2005 and as President since August 2005. Mr. Harrison served as President of Harding & Shelton, Inc., a privately held oil and natural gas exploration, drilling and development firm, from 1999 to 2002. From 2002 to 2005, Mr. Harrison served as an agent for the purchase and sale of oil and gas properties for entities controlled by Wexford. Mr. Harrison has served since 2003 as a member of the board of directors of Geokinetics, Inc., a publicly held seismic acquisition and interpretation company. He graduated from Oklahoma State University with a Bachelor of Science degree in Sociology.

Zachary M. Graves has served as Chief Financial Officer, Secretary and Treasurer of our company since April 2005. He previously served as our Controller and the Controller of Gulfport from April 2003 to March 2005. Prior to joining our company, Mr. Graves served as an accountant with KPMG LLP from August 2000 to April 2003. He received a Bachelor of Business Administration degree in Accounting from the University of Oklahoma and is a licensed Certified Public Accountant.

Karl W. Benzer has served as our Chief Operating Officer since August 2005. From 2002 to August 2005, Mr. Benzer served as a Vice President and Division Manager of Unit Drilling Co., a privately held oil and natural gas land drilling company. From 1994 to 2001, Mr. Benzer served as the Senior Vice President of UTI Energy Corp. and manager of Southland Drilling Company, Ltd and UTI Central Purchasing. UTI Energy Corp. was a publicly held oil and natural gas land drilling company that subsequently merged with Patterson Energy, Inc., a publicly held oil and natural gas land drilling company. Mr. Benzer graduated from the University of Rhode Island with a Bachelor of Science degree in Mechanical Engineering and a Master of Business Administration.

Mike Liddell has served as the Chairman of the Board and a director of our company since May 2005. Mr. Liddell has served as a director of Gulfport Energy Corporation since July 11, 1997, as its Chief Executive Officer since April 28, 1998, as its Chairman of the Board since July 28, 1998 and as its President since July 15, 2000. He received a Bachelor of Science degree in Education from Oklahoma State University.

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

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Michael O. Thompson has served as a director of our company since July 2005. Mr. Thompson has served as the president of the Oklahoma Independent Petroleum Association (OIPA) since September 1991. The OIPA is the largest state-based oil and natural gas association in the United States. Mr. Thompson has served as the executive director of the Oklahoma Energy Education Foundation since its inception in July 1995 and has served as the administrator of the Oklahoma Energy Resources Board since 1995. He received a Bachelor of Arts degree from East Central University in May 1983.

Phillip Lancaster has served as a director of our company since July 2005. Since April 2000, Mr. Lancaster’s has served as a managing director for a sports facility in Dallas, Texas which is affiliated with ClubCorp. Mr. Lancaster is a founder and has served as a director of three Australian companies, Ozpride Pty LTD., Texoz Pty LTD and Magipark Pty LTD since 1996, 1994 and 1990, respectively. The principal business of these companies is real-estate investment and property management in Australia. Mr. Lancaster was the managing partner of Lankin Drilling Fund, Inc. from 1985 through 1999. Mr. Lancaster received a Bachelor of Science degree in Sociology from David Lipscomb College in 1978.

Our Board of Directors and Committees

Our board of directors currently consists of five directors, three of whom, David L. Houston, Michael O. Thompson and Phillip Lancaster, are independent under The Nasdaq National Market listing standards. Our directors generally serve one-year terms from the time of their election until the next annual meeting of stockholders or until their successors are duly elected and qualified.

Our board of directors has established an audit committee whose functions include the following:

• assist the board of directors in its oversight responsibilities regarding (1) the integrity of our financial statements, (2) our risk management compliance with legal and regulatory requirements, (3) our system of internal controls regarding finance and accounting and (4) our accounting, auditing and financial reporting processes generally, including the qualifications, independence and performance of the independent auditor;

• prepare the report required by the SEC for inclusion in our annual proxy or information statement;

• appoint, retain, compensate, evaluate and terminate our independent accountants;

• approve audit and non-audit services to be performed by the independent accountants; and

• perform such other functions as the board of directors may from time to time assign to the audit committee.

The specific functions and responsibilities of the audit committee are set forth in the audit committee charter. Our audit committee includes three directors, Mr. Houston, Mr. Thompson and Mr. Lancaster, who satisfy the independence requirements of current SEC rules and The Nasdaq National Market listing standards. In addition, Mr. Houston qualifies as an audit committee financial expert as defined under these rules and listing standards, while the other members of our audit committee satisfy the financial literacy standards for audit committee members under these rules and listing standards.

Pursuant to our bylaws, our board of directors may, from time to time, establish other committees to facilitate the management of our business and operations. Because we are considered to be controlled by Wexford under The Nasdaq National Market rules, we are eligible for exemptions from provisions of these rules requiring a majority of independent directors, nominating and corporate governance and compensation committees composed entirely of independent directors and written charters addressing specified matters. We have elected to take advantage of these exemptions. In the event that we cease to be a controlled company within the meaning of these rules, we will be required to comply with these provisions after the specified transition periods.

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Director Compensation

Prior to our initial public offering in August 2005, none of our directors received compensation for services rendered as a board member. Following completion of our initial public offering, our non-employee directors are paid a monthly retainer of $1,000 and a per meeting attendance fee of $500 and are reimbursed for all ordinary and necessary expenses incurred in the conduct of our business. Members of our board of directors who are also officers or employees of our company do not receive compensation for their services as directors.

In connection with our initial public offering, we implemented our 2005 Stock Incentive Plan. Under the plan, certain non-employee directors were granted a nonqualified stock option to purchase 20,000 shares of our common stock at an exercise price of $17.00 per share, an amount equal to the initial public offering price. Options granted to eligible non-employee directors under the plan vest in 36 equal monthly installments beginning on the date of grant and are exercisable for a period of ten years beginning on the date of its grant.

Compensation Committee Interlocks and Insider Participation

We do not currently have a compensation committee. None of our executive officers serves, or has served during the past year, as a member of the board of directors or compensation committee of any other company that has one or more executive officers serving as a member of our board of directors or compensation committee.

Executive Compensation

D. Frank Harrison has served as our Chief Executive Officer since May 2005 and as our President since August 2005. His current annual salary is $200,000.

Karl W. Benzer has served as our Chief Operating Office since August 25, 2005. His current annual salary is $180,000. In addition, Mr. Benzer is entitled to receive a one-time year-end bonus of $50,000 to be paid on December 31, 2005.

Zachary M. Graves has served as our Chief Financial Officer since April 2005. His current annual salary is $135,000.

Steven C. Hale served as our President beginning in June 2001 and our Chief Operating Officer beginning in April 2005 in each case until his resignation in August 2005. He earned $125,000 during each of the years ended December 31, 2004, 2003 and 2002. No other executive officer earned or received more than $100,000 in salary and bonus for 2004. There were no stock option grants to, or option exercises by, Mr. Hale during 2004, 2003 or 2002.

2005 Stock Incentive Plan

We have implemented our 2005 Stock Incentive Plan. The purpose of the plan is to enable our company, and any of its affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to our long range success and to provide incentives which are linked directly to increases in share value which will inure to the benefit of our stockholders. The plan provides a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of our common stock through the granting of incentive stock options and nonstatutory stock options.

Eligible award recipients are employees, consultants and directors of our company and its affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock which may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed 500,000 shares, subject to adjustment to reflect certain corporate transactions or changes in our capital structure.

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We have granted options to employees and certain non-employee directors to purchase a total of 500,000 shares of our common stock under the plan, including option grants covering a total of 200,000 shares to D. Frank Harrison, 60,000 shares to Zachary M. Graves and 70,000 shares to Karl M. Benzer. These options have a weighted average exercise price of $17.92 per share, have a term of ten years and vest in 36 equal monthly installments beginning on the date of grant. In addition, we have granted options to eligible non-employee directors as described in “—Director Compensation,” above.

Employment Agreements

On August 25, 2005, we entered into an employment agreement with Karl W. Benzer, our Chief Operating Officer. The agreement has a five year term and provides for a base salary of $180,000 per year. Under the agreement, Mr. Benzer will be eligible to receive, but is not guaranteed, salary increases, based upon merit (as determined by our Chief Executive Officer), our financial performance (as determined by our monthly profit and loss statements), market conditions and other industry factors. The agreement provides for a one-time year-end bonus of $50,000 to be paid on December 31, 2005, and a one-time, first-quarter bonus of $40,000 to be paid on January 16, 2006, subject to certain forfeiture conditions. Beginning in 2006, Mr. Benzer will also be eligible for bonuses based upon merit, financial performance, market conditions and other industry factors. The agreement also grants Mr. Benzer an option to purchase 70,000 shares of our common stock at a price of $18.70 per share. If we terminate Mr. Benzer’s employment without cause, Mr. Benzer is entitled to severance pay equal to the base salary earned under the agreement through the date of such termination without cause, and base salary for the remainder of the term of the agreement. Mr. Benzer will also be permitted to exercise stock options then vested within ten days of such termination without cause by us. The agreement provides that during the five-year term of Mr. Benzer’s employment with us and for a period of two years thereafter or, if longer, a period of two years following the termination of Mr. Benzer’s employment with us, Mr. Benzer will not recruit, solicit, encourage or induce any employees of ours or our affiliates to terminate their employment or otherwise disrupt any employees relationship with us or our affiliates or hire, employ or offer employment to any person who is or was employed by us or any of our affiliates. Mr. Benzer is also prohibited, during the five-year term of his employment with us and for a period of two years thereafter, or, if longer, a period of two years following the termination of Mr. Benzer’s employment with us, from soliciting any past or current customer, supplier or any other person with a business relationship with us to cease doing business with us.

In connection with our initial public offering, we entered into an employment agreement with Steven C. Hale, our former President and Chief Operating Officer. Mr. Hale resigned from his positions with us in August 2005. His employment agreement provided for an annual base salary of $175,000 during its one-year term. The employment agreement also provided that in the event that Mr. Hale was terminated by us without cause, Mr. Hale would have been entitled to severance pay in an aggregate amount equal to three months of his then current base salary. No severance payments were due, payable or made to Mr. Hale by us under the employment agreement or otherwise. Under the employment agreement, Mr. Hale is prohibited, for a period of five years following the termination of Mr. Hale’s employment, from directly or indirectly disclosing any confidential information Mr. Hale obtained as a result of his employment. Mr. Hale is also prohibited, for a period of 12 months following his termination of employment with us, from soliciting the business of any established customer of ours in the United States or soliciting, enticing, persuading or inducing any employee, agent or representative of ours to terminate such person’s relationship with us or to become employed by any business or person other than us or hire or retain any such person.

Under the terms of an agreement between Bronco Drilling Holdings, L.L.C. and Mr. Hale, following successful completion of our initial public offering, Mr. Hale was entitled to receive the sum of $2.0 million and shares of our common stock having a market value of $2.0 million based on the initial public offering price. These payments were made by Bronco Drilling Holdings and not by us. We will account for these payments as a capital contribution to us in the amount of $4.0 million and compensation expense in the amount of $4.0 million during the third quarter of 2005, the period in which such obligations were incurred.

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Limitations of Liability and Indemnification of Directors and Officers

Certificate of Incorporation and Bylaws

Our certificate of incorporation provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the Delaware General Corporation Law, or DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by the DGCL:

• for any breach of the director’s duty of loyalty to the company or its stockholders;

• for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

• in respect of certain unlawful dividend payments or stock redemptions or repurchases; and

• for any transaction from which the director derives an improper personal benefit.

This provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

Our certificate of incorporation also provides that we will, to the fullest extent permitted by Delaware law, indemnify our directors and officers against losses that they may incur in investigations and legal proceedings resulting from their service.

Our bylaws include provisions relating to advancement of expenses and indemnification rights consistent with those provided in our certificate of incorporation. In addition, our bylaws provide:

• for a right of indemnitee to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time; and

• permit us to purchase and maintain insurance, at our expense, to protect us and any of our directors, officers and employees against any loss, whether or not we would have the power to indemnify that person against that loss under Delaware law.

Liability Insurance and Indemnification Agreements

We have obtained liability insurance for our current directors and officers. We have also entered into contractual indemnification arrangements with our directors and executive officers under which we have agreed, in certain circumstances, to compensate them for costs and liabilities incurred in actions brought against them while acting as directors or executive officers of our company.

At present, there is no pending litigation or proceeding involving any of our directors, officers or employees for which indemnification from us is sought. We are not aware of any threatened litigation that may result in claims for indemnification from us.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Administrative Services Agreement and Lease of Space

Historically, we have outsourced a significant portion of our administrative functions to Gulfport Energy Corporation and we expect to continue to outsource certain functions for the foreseeable future pursuant to an administrative services agreement. In addition, we use approximately 1,100 square feet of space in an office building owned by Gulfport in Oklahoma City, Oklahoma. We have reimbursed Gulfport for its dedicated employee time, office space and general and administrative costs based upon the pro rata share of time its employees spend performing services for us. In 2004, 2003 and 2002, we made payments for such services and overhead totaling approximately $115,000, $33,000 and $37,000, respectively. Effective April 1, 2005, we entered into an administrative services agreement with Gulfport. Under this agreement, Gulfport’s services for us include accounting, human resources, legal and technical support. In return for the services rendered by Gulfport, we have agreed to pay Gulfport an annual fee of approximately $414,000 payable in equal monthly installments during the term of this agreement. In addition, we will continue to lease approximately 1,100 square feet of office space from Gulfport for our headquarters. We will pay Gulfport annual rent of approximately $20,900 payable in equal monthly installments. The services being provided to us and the fees for such services can be amended by mutual agreement of the parties. The administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by us at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. The fees payable by us under the administrative services agreement were arrived at through negotiations between us and Gulfport. Although we believe the fees are reasonable, we have not determined whether unrelated third parties could provide comparable services at a lower cost. Two of our directors, Mike Liddell and David L. Houston, are also directors of Gulfport and Mr. Liddell is the Chief Executive Officer of Gulfport. Wexford, our principal stockholder, is also the largest stockholder of Gulfport.

Credit Facilities

On July 1, 2004, we entered into a revolving line of credit with International Bank of Commerce with a borrowing base of the lesser of $2.0 million or 80% of current receivables. Our performance obligations under this credit facility have been guaranteed by Wexford Partners VI, L.P., a fund controlled by Wexford, and Taurus Investors, LLC, a member of our predecessor company that is also controlled by Wexford. Borrowings under this line bear interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime (effective rate of 6.25% at June 30, 2005). Accrued but unpaid interest is payable monthly, and we are current in our monthly interest payments through the date of this prospectus. On January 1, 2005, we amended our line of credit with International Bank of Commerce to increase the borrowing base to the lesser of $3.0 million or 80% of current receivables. The line of credit matures on November 1, 2005. At June 30, 2005, our outstanding borrowings under this line of credit were $2.5 million.

On February 15, 2005, we entered into a $5.0 million revolving credit facility with Solitair LLC, an entity controlled by Wexford. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0% (effective rate of 8.11% at June 30, 2005). Payments of principal and accrued but unpaid interest were due on the maturity date of the credit facility. In connection with the amendment of our senior credit facility with GECC on April 22, 2005, Solitair entered into a subordination agreement which, among other thing, effectively amended the maturity date of its loan to the later of (1) six months after the actual maturity date of our credit facility with GECC and (2) December 1, 2010. At June 30, 2005, our outstanding borrowings under this credit facility were $5.0 million. We repaid all outstanding borrowings under this credit facility with a portion of the proceeds from our initial public offering and the facility was terminated.

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On June 30, 2005, we borrowed $13.0 million from Alpha Investors LLC, an entity controlled by Wexford, to fund a portion of our acquisitions of 100% of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million. The outstanding principal balance of the loan plus accrued but unpaid interest was due in full upon the earlier to occur of the completion of our initial public offering and the maturity of the loan on July 1, 2006. Borrowings under our loan with Alpha bore interest at a rate equal to LIBOR plus 5% until September 30, 2005 (effective rate of 8.11% when the loan was made on June 30, 2005), and thereafter at a rate equal to LIBOR plus 7.5%. We repaid this loan in full with a portion of the proceeds from our initial public offering.

On October 14, 2005, we borrowed $50.0 million from Theta Investors LLC, an entity controlled by Wexford, to fund a portion of the purchase price for the Thomas acquisition. The loan provides for maximum aggregate borrowings of up to $60.0 million that bear interest at a rate equal to LIBOR plus 400 basis points (7.98% at October 14, 2005 and upon the initial borrowing under this facility) until December 15, 2005, and thereafter at a rate equal to LIBOR plus 600 basis points. Payment of principal and accrued but unpaid interest is due on October 14, 2006. We intend to use a portion of the proceeds from this offering to repay those borrowings in full.

Drilling Services

During 2002 and 2003, we received $396,000 and $184,000, respectively, for drilling services rendered to Windsor Energy, LLC, an affiliate of Wexford. In addition, upon completion of the refurbishment of Rig 4 in August 2005, that rig was mobilized to the Piceance Basin in Colorado under a one-year term drilling contract with Windsor Energy.

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PRINCIPAL STOCKHOLDERS

The following table sets forth certain information regarding the beneficial ownership of our common stock by:

• each of our directors;

• each of our named executive officers;

• all of our directors and executive officers as a group; and

• each person, or group of affiliated persons, known to us to beneficially own 5% or more of our outstanding common stock.

Except as otherwise indicated, the beneficial owners named in the table below have sole voting and investment power with respect to all shares of capital stock held by them.

		Percent of Common Stock Beneficially Owned (2)
Name (1)	Number	Before the     Offering		After the     Offering
5% Stockholder:
Bronco Drilling Holdings, L.L.C. (3)	13,092,353	68	%	58	%
Directors and Named Executive Officers:
D. Frank Harrison (4)	27,778	*		*
Mike Liddell	—	*		*
David L. Houston (5)	2,778	*		*
Michael O. Thompson (5).	2,778	*		*
Phillip Lancaster (5)	2,778	*		*
Karl W. Benzer (6)	9,722	*		*
Zachary M. Graves (7)	8,333	*		*
Steven C. Hale	117,647	*		*
Directors and executive officers as a group (7 persons) (8)	54,167	*		*

* Less than 1%

(1) Unless otherwise indicated, the address for all of the executive officers, directors and stockholders named in the table is c/o 14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma 73134.

(2) Percentage of beneficial ownership is based upon 19,140,368 shares of common stock outstanding prior to the offering, and 22,640,368 shares of common stock outstanding after the offering. The table assumes no exercise of the underwriters’ overallotment option. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares which such person owns or has the right to acquire within 60 days. For purposes of computing the percentage of outstanding shares held by each person or group of persons named above, any security which such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our stockholders may differ.

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(3) Wexford Capital LLC is the sole manager of Bronco Drilling Holdings, L.L.C. Wexford’s address is Wexford Plaza, 411 West Putnam Avenue, Greenwich, Connecticut 06830.

(4) Includes 27,778 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after the date hereof.

(5) Includes 2,778 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after the date hereof.

(6) Includes 9,722 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after the date hereof.

(7) Includes 8,333 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after the date hereof.

(8) Includes 54,167 shares beneficially owned by the directors and executive officers under options that are currently exercisable or will become exercisable within 60 days after the date hereof.

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DESCRIPTION OF CAPITAL STOCK

The following description of our common stock, amended and restated certificate of incorporation and our bylaws are summaries thereof and are qualified by reference to our certificate of incorporation and our bylaws as so amended and restated, copies of which will be filed with the SEC as exhibits to the registration statement of which this prospectus is a part.

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share, and 1,000,000 shares of preferred stock, par value $0.01 per share. Our shares of common stock are quoted on The Nasdaq National Market.

Common Stock

Holders of shares of common stock are entitled to one vote per share on all matters submitted to a vote of stockholders. Shares of common stock do not have cumulative voting rights, which means that the holders of more than 50% of the shares voting for the election of the board of directors can elect all the directors to be elected at that time, and, in such event, the holders of the remaining shares will be unable to elect any directors to be elected at that time. Our certificate of incorporation denies stockholders any preemptive rights to acquire or subscribe for any stock, obligation, warrant or other securities of ours. Holders of shares of our common stock have no redemption or conversion rights nor are they entitled to the benefits of any sinking fund provisions.

In the event of our liquidation, dissolution or winding up, holders of shares of common stock shall be entitled to receive, pro rata, all the remaining assets of our company available for distribution to our stockholders after payment of our debts and after there shall have been paid to or set aside for the holders of capital stock ranking senior to common stock in respect of rights upon liquidation, dissolution or winding up the full preferential amounts to which they are respectively entitled.

Holders of record of shares of common stock are entitled to receive dividends when and if declared by the board of directors out of any assets legally available for such dividends, subject to both the rights of all outstanding shares of capital stock ranking senior to the common stock in respect of dividends and to any dividend restrictions contained in debt agreements.

Preferred Stock

Our board of directors is authorized to issue up to 1,000,000 shares of preferred stock in one or more series. The board of directors may fix for each series:

• the distinctive serial designation and number of shares of the series;

• the voting powers and the right, if any, to elect a director or directors;

• the terms of office of any directors the holders of preferred shares are entitled to elect;

• the dividend rights, if any;

• the terms of redemption, and the amount of and provisions regarding any sinking fund for the purchase or redemption thereof;

• the liquidation preferences and the amounts payable on dissolution or liquidation;

• the terms and conditions under which shares of the series may or shall be converted into any other series or class of stock or debt of the corporation; and

• any other terms or provisions which the board of directors is legally authorized to fix or alter.

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We do not need stockholder approval to issue or fix the terms of the preferred stock. The actual effect of the authorization of the preferred stock upon your rights as holders of common stock is unknown until our board of directors determines the specific rights of owners of any series of preferred stock. Depending upon the rights granted to any series of preferred stock, your voting power, liquidation preference or other rights could be adversely affected. Preferred stock may be issued in acquisitions or for other corporate purposes. Issuance in connection with a stockholder rights plan or other takeover defense could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, control of our company. We have no present plans to issue any shares of preferred stock.

Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws

Some provisions of our certificate of incorporation and our bylaws contain provisions that could make it more difficult to acquire us by means of a merger, tender offer, proxy contest or otherwise, or to remove our incumbent officers and directors. These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiation of such proposals could result in an improvement of their terms.

Undesignated preferred stock.  The ability to authorize and issue undesignated preferred stock may enable our board of directors to render more difficult or discourage an attempt to change control of us by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary obligations, the board of directors were to determine that a takeover proposal is not in our best interest, the board of directors could cause shares of preferred stock to be issued without stockholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer or insurgent stockholder or stockholder group.

Stockholder meetings.  Our certificate of incorporation and bylaws provide that a special meeting of stockholders may be called only by the Chairman of the Board, the Chief Executive Officer or by a resolution adopted by a majority of our board of directors.

Requirements for advance notification of stockholder nominations and proposals.  Our bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors.

Stockholder action by written consent.  Our certificate of incorporation and bylaws provide that, except as may otherwise be provided with respect to the rights of the holders of preferred stock, no action that is required or permitted to be taken by our stockholders at any annual or special meeting may be effected by written consent of stockholders in lieu of a meeting of stockholders, unless the action to be effected by written consent of stockholders and the taking of such action by such written consent have expressly been approved in advance by our board. This provision, which may not be amended except by the affirmative vote of holders of at least 66 ²/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, makes it difficult for stockholders to initiate or effect an action by written consent that is opposed by our board.

Amendment of the bylaws.  Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our charter and bylaws grant our board the power to adopt, amend and repeal our bylaws at any regular or special meeting of the board on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by an affirmative vote of holders of at least 66 ²/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

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Removal of Director.  Our certificate of incorporation and bylaws provide that members of our board of directors may only be removed for cause and only by the affirmative vote of holders of at least 66 ²/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Amendment of the Certificate of Incorporation.  Our certificate of incorporation provides that, in addition to any other vote that may be required by law or any preferred stock designation, the affirmative vote of the holders of at least 66 ²/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, is required to amend, alter or repeal, or adopt any provision as part of our certificate of incorporation inconsistent with the provisions of our certificate of incorporation dealing with distributions on our common stock, our board of directors, our bylaws, meetings of our stockholders or amendment of our certificate of incorporation.

The provisions of our certificate of incorporation and bylaws could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions which stockholders may otherwise deem to be in their best interests.

Transfer Agent and Registrar

Computershare Shareholder Services, Inc. and its subsidiary, EquiServe Trust Company, N.A., are the transfer agent and registrar for our common stock.

75

SECURITIES ELIGIBLE FOR FUTURE SALE

Future sales in the public markets of substantial amounts of common stock could adversely affect the market prices prevailing from time to time for our common stock. It could also impair our ability to raise capital through future sales of equity securities.

Upon completion of this offering, we will have 22,640,368 shares of our common stock outstanding, assuming no exercise of the underwriters’ overallotment option. All of the shares sold in this offering will be freely tradable without restriction or further registration under the Securities Act, except for shares, if any, which may be acquired by our “affiliates” as that term is defined in Rule 144 under the Securities Act. Persons who may be deemed to be affiliates generally include individuals or entities that control, are controlled by, or are under common control with, us and may include our directors and officers as well as our significant stockholders, if any.

Lock-Up Agreements

In connection with our initial public offering, we, our officers and directors and Bronco Drilling Holdings, L.L.C., our largest stockholder and an entity controlled by Wexford, entered into lock-up agreements in favor of the underwriters of our initial public offering that prohibit us and these other individuals or entities, directly or indirectly, from selling or otherwise disposing of any shares or securities convertible into shares for a period of 180 days ending February 12, 2006, without the prior written consent of Johnson Rice & Company L.L.C., subject to limited exceptions. In connection with this offering, Mr. Karl Benzer entered into a lock-up agreement on the same terms as the lock-up agreements described above. Immediately following this offering, persons subject to lock-up agreements will beneficially own 13,264,167 shares, representing approximately 58% of the then outstanding shares, or approximately 57% if the underwriters’ overallotment option is exercised in full.

Rule 144

In general, under Rule 144 as currently in effect, beginning 90 days after the date of this prospectus, a person who has beneficially owned restricted securities for at least one year is entitled to sell within any three-month period the number of those restricted securities that does not exceed the greater of:

• 1% of the total number of shares then outstanding; and

• the average weekly trading volume of the shares on The Nasdaq National Market during the four calendar weeks preceding the filing of a notice on Form 144 with respect to such sale.

Sales under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Under Rule 144(k), a person that has not been one of our affiliates at any time during the three months preceding a sale, and that has beneficially owned the shares proposed to be sold for at least two years, is entitled to sell those shares without regard to the volume, manner of sale or other limitations contained in Rule 144.

Stock Options

An aggregate of 500,000 shares of our common stock have been reserved for issuance pursuant to our 2005 Stock Incentive Plan, all of which have been granted. We intend to file a registration statement on Form S-8 with respect to the issuance of all shares issuable under the plan. Accordingly, shares issued pursuant to this plan will be freely tradable, except for any shares held by our affiliates, as such term is defined by the SEC.

Registration Rights

We have entered into a registration rights agreement with Bronco Drilling Holdings. Under the registration rights agreement, Bronco Drilling Holdings has three demand registration rights, as well as “piggyback” registration rights. The demand rights enable Bronco Drilling Holdings to require us to register its shares of our common stock with the SEC at any time, subject to the 180-day lock-up agreement it has entered into in connection with our initial public offering. The piggyback rights will allow Bronco Drilling Holdings to register the shares of our common stock that it owns along with any shares that we register with the SEC. These registration rights are subject to customary conditions and limitations, including the right of the underwriters of an offering to limit the number of shares.

76

UNDERWRITING

We and the underwriters named below have entered into an underwriting agreement with respect to the shares being offered. Subject to the terms and conditions of the underwriting agreement, the underwriters named below have severally agreed to purchase from us the number of shares of our common stock set forth opposite their names on the table below at the public offering price, less the underwriting discounts and commissions shown on the cover page of this prospectus as follows:

Name	Number of Shares
Johnson Rice & Company L.L.C.	1,750,000
Jefferies & Company, Inc.	700,000
Friedman, Billings, Ramsey & Co., Inc.	525,000
Raymond James & Associates, Inc.	525,000
Total	3,500,000

The underwriting agreement provides that the underwriters’ obligations to purchase shares of our common stock depend on the satisfaction of the conditions contained in the underwriting agreement. The conditions contained in the underwriting agreement include the condition that the representations and warranties made by us to the underwriters are true, that there has been no material adverse change to our condition or in the financial markets and that we deliver to the underwriters customary closing documents. The underwriters are obligated to purchase all of the shares of common stock (other than those covered by the overallotment option described below) if they purchase any of the shares.

The underwriters propose to offer the shares of common stock to the public at the public offering price set forth on the cover of this prospectus. The underwriters may offer the common stock to securities dealers at the price to the public less a concession not in excess of $0.759 per share. After the shares of common stock are released for sale to the public, the underwriters may vary the offering price and other selling terms from time to time.

We have granted to the underwriters an option, exercisable for 30 days from the date of the underwriting agreement, to purchase up to 525,000 additional shares at the public offering price per share less the underwriting discounts and commissions shown on the cover page of this prospectus. The underwriters may exercise this option solely to cover overallotments, if any, made in connection with this offering.

The following table summarizes the compensation to be paid to the underwriters by us and the proceeds, before expenses, payable to us.

			Total
	Per Share		Without Over- Allotment		With Over- Allotment
Public offering price by us	$	23.000	$	80,500,000	$	92,575,000
Underwriting fees to be paid by us	$	1.265	$	4,427,500	$	5,091,625
Proceeds, before expenses, to us	$	21.735	$	76,072,500	$	87,483,375

We estimate our expenses associated with the offering, excluding underwriting discounts and commissions, will be approximately $500,000.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the federal securities laws, or to contribute to payments that may be required to be made in respect of these liabilities.

In connection with our initial public offering in August 2005, we, Bronco Drilling Holdings, L.L.C. and our officers and directors agreed that, for a period of 180 days ending on February 12, 2006, we and they will not,

77

without the prior written consent of Johnson Rice & Company L.L.C., directly or indirectly, offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any share of common stock or any securities convertible into or exercisable or exchangeable for common stock, or file any registration statement under the Securities Act of 1933 with respect to any of the foregoing or enter into any swap or any other agreement or transaction that transfers, in whole or in part, directly or indirectly, the economic consequence of ownership of the common stock, except for the issuance by us of any securities or options to purchase common stock under employee benefit plans existing as of August 16, 2005, the filing by us of one or more registration statements on Form S-8 relating to the issuance and exercise of options to purchase common stock granted under our employee benefit plans existing on August 16, 2005, the issuance by us of securities in exchange for or upon conversion of our outstanding securities described herein, certain transfers in the case of officers and directors in the form of bona fide gifts, intra family transfers and transfers related to estate planning matters or the transfer by Bronco Drilling Holdings, L.L.C. to an affiliate, if such affiliate agrees in writing to be bound by the lockup restrictions contained in the underwriting agreement. In connection with this offering, Mr. Karl Benzer entered into a lock-up agreement on the same terms as the lock-up agreements described above. Notwithstanding the foregoing, if (1) during the last 17 days of such 180-day restricted period we issue an earnings release or (2) prior to the expiration of such 180-day restricted period we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the foregoing restrictions shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release. The underwriters have advised us that, except to the extent contemplated by this offering, they do not have any present intent to release the lock-up agreements prior to the expiration of the applicable restricted period.

The underwriters may engage in overallotment, stabilizing transactions, syndicate covering transactions, penalty bids and passive market making in accordance with Regulation M under the Securities Exchange Act of 1934. Overallotment involves syndicate sales in excess of the offering size, which creates a syndicate short position. Covered short sales are sales made in an amount not greater than the number of shares available for purchase by the underwriters under their overallotment option. The underwriters may close out a covered short sale by exercising their overallotment option or purchasing shares in the open market. Naked short sales are sales made in an amount in excess of the number of shares available under the overallotment option. The underwriters must close out any naked short sale by purchasing shares in the open market. Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. Syndicate covering transactions involve purchases of the shares of common stock in the open market after the distribution has been completed in order to cover syndicate short positions. Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the shares of common stock originally sold by such syndicate member is purchased in a syndicate covering transaction to cover syndicate short positions. Penalty bids may have the effect of deterring syndicate members from selling to people who have a history of quickly selling their shares. In passive market making, market makers in the shares of common stock who are underwriters or prospective underwriters may, subject to certain limitations, make bids for or purchases of the shares of common stock until the time, if any, at which a stabilizing bid is made. These stabilizing transactions, syndicate covering transactions and penalty bids may cause the price of the shares of common stock to be higher than it would otherwise be in the absence of these transactions. The underwriters are not required to engage in these activities, and may end any of these activities at any time.

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LEGAL MATTERS

The validity of the shares of common stock that are offered hereby by us will be passed upon by Akin Gump Strauss Hauer & Feld LLP. Certain legal matters will be passed upon for the underwriters by Porter & Hedges, L.L.P.

EXPERTS

The consolidated financial statements of Bronco Drilling Company, L.L.C. and Subsidiaries as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, the balance sheet of Bronco Drilling Company, Inc. as of June 30, 2005 and the combined financial statements of Strata Drilling, L.L.C. and Affiliate as of December 31, 2004 and for the year then ended appearing in this prospectus and the registration statement of which this prospectus is a part have been audited by Grant Thornton LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon the authority of such firm as experts in accounting and auditing.

The financial statements of Thomas Drilling Company as of December 31, 2004 and 2003 and for each of the two years in the period ended December 31, 2004 appearing in this prospectus and the registration statement of which this prospectus is a part have been audited by Freemon, Shapard & Story, independent accountants, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act covering the securities offered by this prospectus. This prospectus, which constitutes a part of that registration statement, does not contain all of the information that you can find in that registration statement and its exhibits. Certain items are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information about us and the common stock offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus and any prospectus supplement as to the contents of any contract or other document referred to are not necessarily complete and in each instance such statement is qualified by reference to each such contract or document filed as part of the registration statement. We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read any materials we file with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

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INDEX TO PRO FORMA COMBINED

FINANCIAL STATEMENTS

	Page
Bronco Drilling Company, Inc. Unaudited Pro Forma Combined
Introduction to Unaudited Pro Forma Combined Financial Statements	P-2
Unaudited Pro Forma Combined Balance Sheet as of June 30, 2005	P-4
Unaudited Pro Forma Combined Statement of Operations for the six months ended June 30, 2005	P-5
Unaudited Pro Forma Combined Statement of Operations for the year ended December 31, 2004	P-6
Notes to Unaudited Pro Forma Combined Financial Statements	P-7

P-1

BRONCO DRILLING COMPANY, INC.

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Introduction

The following are our unaudited pro forma combined balance sheet as of June 30, 2005 and our unaudited pro forma combined statements of operations for the year ended December 31, 2004 and six months ended June 30, 2005. The unaudited pro forma combined balance sheet gives pro forma effect to the following transactions as if such transactions had been consummated on June 30, 2005 and the unaudited pro forma combined statements of operations give pro forma effect to the following transactions as if such transactions had been consummated on January 1, 2004:

Formation and Offering Adjustments:

• The merger of our predecessor, Bronco Drilling Company, L.L.C., an Oklahoma limited liability company into us, a taxable Delaware corporation, in August 2005;

• The sale of 5,715,000 shares of our common stock in our initial public offering at a price of $17.00 per share for proceeds of $89.7 million, net of underwriting discounts and estimated offering expenses, and the application of such proceeds;

• The repayment of $18.1 million of outstanding indebtedness and accrued interest as of June 30, 2005;

• Certain payments made by our principal stockholder to our former president; and

• The sale of 3,500,000 shares of common stock in this offering at an offering price of $23.00 per share for proceeds of $75.6 million, net of underwriting discounts and estimated offering expenses, and the application of such proceeds as set forth under “Use of Proceeds.”

Pro Forma Adjustments:

• The acquisition of Strata Drilling, L.L.C. and its affiliate, Strata Property, L.L.C. (collectively “Strata”); and

• The acquisition of Thomas Drilling Co. (“Thomas”).

The Thomas and Strata acquisitions are accounted for as purchases and, as a result, the acquired assets are recorded at their fair value at the time of purchase. The fair values are based upon our management’s estimate of fair value and, although they are believed to be reasonable, the purchase price allocation is subject to change as we gather additional information to finalize the fair value appraisals of assets acquired.

The following unaudited pro forma combined financial statements and accompanying notes should be read together with our historical financial statements and the historical financial statements of Strata and Thomas appearing elsewhere in this prospectus. The unaudited pro forma combined balance sheet and the unaudited pro forma combined statements of operations were derived by adjusting those historical financial statements. The adjustments are based on currently available information and certain estimates and assumptions; therefore, the actual adjustments may differ from the pro forma adjustments when we finalize our asset appraisals in our fourth quarter of 2005. However, management believes that the assumptions provide a reasonable basis for presenting

P-2

the significant effects of this offering and the other transactions specified above, and that the pro forma adjustments give appropriate effect to the assumptions made and are properly applied in the unaudited pro forma combined financial statements. The unaudited pro forma combined financial statements do not give effect to our recently completed acquisition of Hays Trucking, Inc., which was not a financially significant acquisition, or our transaction with Eagle Drilling, L.L.C. and its affiliates, for which audited financial statements are not currently available.

The unaudited pro forma combined financial statements do not purport to present the financial position or results of operations of the Company had this offering and the other transactions actually been completed as of the dates indicated. Moreover, they do not purport to project the Company’s financial position or results of operations for any future date or period.

P-3

BRONCO DRILLING COMPANY, INC.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

JUNE 30, 2005

(in thousands)

	Predecessor Historical Bronco Drilling LLC		Formation and Offerings Adjustments			Predecessor Pro Forma Bronco Drilling Company, Inc.			Historical Strata Drilling, LLC			Historical Thomas Drilling Co.			Pro Forma Adjustments			Pro Forma Combined
ASSETS
Current assets:
Cash and cash equivalents	$	13,623	$	89,734	(b)	$	160,829		$	201		$	—		$	(201	)(h)	$	79,829
				(18,100	)(c)											(68,000	)(f)
				75,572	(j)											(13,000	)(e)
Short-term investments							—			952			—			(952	)(h)		—
Trade receivables		7,276		—			7,276			1,053			5,480			(5,480	)(h)		7,276
																(1,053	)(h)
Contract Drilling in Progress		2,186		—			2,186			—			—			—			2,186
Prepaid expenses and other		410		—			410			3			241			(241	)(h)		410
																(3	)(h)
Total current assets		23,495		147,206			170,701			2,209			5,721			(88,930	)		89,701
Property and equipment, at cost		102,443		—			102,443			7,219			17,540			12,781	(e)		188,403
																48,420	(f)
Less accumulated depreciation and amortization		9,764		—			9,764			1,012			13,162			(13,162	)(h)		9,764
																(1,012	)(h)
Net property and equipment		92,679					92,679			6,207			4,378			75,375			178,639
Intangible and other assets, net of amortization		356		—			356			—			—			2,040	(f)		2,396
Restricted cash and other		2,376		—			2,376			—			122			(122	)(h)		2,376
Total assets	$	118,906	$	147,206		$	266,112		$	8,416		$	10,221		$	(11,637	)	$	273,112
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	5,824	$	—		$	5,824		$	693		$	2,034		$	(2,034	)(h)	$	5,824
																(693	)(h)
Accrued liabilities		1,577		(100	)(c)		1,477			259			—			(259	)(h)		1,477
Current maturities of long-term debt		4,600		—			4,600			749			—			(749	)(h)		4,600
Notes payable		2,500		—			2,500			—			2,987			(2,987	)(h)		9,500
																20,000	(e)
																(13,000	)(e)
Total current liabilities		14,501		(100	)		14,401			1,701			5,021			278			21,401
Non-current liabilities:
Long-term debt		32,900		(18,000	)(c)		14,900			2,580			—			(2,580	)(h)		14,900
Deferred income taxes		15,828		4,412	(a)		20,240			—			—			—			20,240
Total liabilities		63,229		(13,688	)		49,541			4,281			5,021			(2,302	)		56,541
Equity:
Common Stock		—		134	(a)		226			—			—			—			226
				57	(b)
				35	(j)
Paid in capital		—		55,543	(a)		224,757			—			1,341			(1,341	)(h)		224,757
				4,000	(d)
				89,677	(b)
				75,537	(j)
Accumulated deficit		—		(4,000	)(d)		(8,412	)		—			4,033			(4,033	)(h)		(8,412	)
				(4,412	)(a)
Treasury Stock		—		—			—			—			(174	)		174	(h)		—
Notes receivable from member		—		—						(2,304	)		—			2,304	(h)		—
Members’ interest		55,677		(55,677	)(a)		—			6,439			—			(6,439	)(h)		—
Total equity		55,677		160,894			216,571			4,135			5,200			(9,335	)		216,571
Total liabilities and equity	$	118,906	$	147,206		$	266,112		$	8,416		$	10,221		$	(11,637	)	$	273,112

See accompanying notes to the unaudited pro forma financial statements.

P-4

BRONCO DRILLING COMPANY, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2005

(Amounts in thousands, except per share amounts)

	Predecessor Historical Bronco Drilling LLC			Formation and Offerings Adjustments			Predecessor Pro Forma Bronco Drilling Company, Inc.			Historical Strata Drilling, LLC			Historical Thomas Drilling Co.			Pro Forma Adjustments			Pro Forma Combined
Contract drilling revenues	$	20,269		$	—		$	20,269		$	3,715		$	14,186		$	—		$	38,170
Expenses:
Contract drilling		12,870			—			12,870			1,965			5,591			—			20,426
Depreciation and amortization		2,851			—			2,851			272			438			165	(e)		5,114
														—			1,388	(f)
General and administrative		1,123			—			1,123			781			5,960			—			7,864
Total operating costs and expenses		16,844			—			16,844			3,018			11,989			1,553			33,404
Income from operations		3,425			—			3,425			697			2,197			(1,553	)		4,766
Other income (expense):
Interest expense		(309	)		120	(g)		(189	)		(16	)		(33	)		(185	)(e)		(423	)
Interest income		12			—			12			13			8			—			33
Other		—			—			—			411			150			—			561
Total other income (expense)		(297	)		120			(177	)		408			125			(185	)		171
Income from continuing operations and before income taxes		3,128			120			3,248			1,105			2,322			(1,738	)		4,937
Income tax expense		1,179	(i)		45	(i)		1,224			—			—			637	(i)		1,861
Net Income	$	1,949		$	75		$	2,024		$	1,105		$	2,322		$	(2,375	)	$	3,076
Pro forma income per common share – basic and diluted (Note 4)	$	0.15					$	0.11											$	0.16
Weighted average pro forma shares outstanding – basic and diluted (Note 4)		13,360						18,764												18,764

See accompanying notes to the unaudited pro forma financial statements.

P-5

BRONCO DRILLING COMPANY, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2004

(Amounts in thousands, except per share amounts)

	Predecessor Historical Bronco Drilling LLC			Formation and Offering Adjustments		Predecessor Pro Forma Bronco Drilling Company, Inc.			Historical Strata Drilling, LLC			Historical Thomas Drilling Co.			Pro Forma Adjustments			Pro Forma Combined
Contract drilling revenues	$	21,873		$	—	$	21,873		$	6,116		$	18,943		$	—		$	46,932
Expenses:
Contract drilling		18,670			—		18,670			3,570			6,115			—			28,355
Depreciation and amortization		3,695			—		3,695			392			653			482	(e)		8,222
																3,000	(f)
General and administrative		1,714			—		1,714			1,144			9,340			—			12,198
Total operating costs and expenses		24,079			—		24,079			5,106			16,108			3,482			48,775
Income from operations		(2,206	)				(2,206	)		1,010			2,835			(3,482	)		(1,843	)
Other income (expense):
Interest expense		(285	)		—		(285	)		(312	)		(18	)		(7	)(e)		(622	)
Interest income		10			—		10			—			19			—			29
Other		—					—			14			141			—			155
Gain on sale of assets							—			—			251			—			251
Total other income (expense)		(275	)		—		(275	)		(298	)		393			(7	)		(187	)
Income (loss) from continuing operations and before income taxes		(2,481	)		—		(2,481	)		712			3,228			(3,489	)		(2,030	)
Income tax expense (benefit)		(935	)(i)		—		(935	)		—			—			170	(i)		(765	)
Net Income (loss)	$	(1,546	)	$	—	$	(1,546	)	$	712		$	3,228		$	(3,659	)	$	(1,265	)
Pro forma loss per common share – basic and diluted (Note 4)	$	(0.12	)			$	(0.08	)										$	(0.07	)
Weighted average pro forma shares outstanding – basic and diluted (Note 4)		13,360					18,483												18,483

See accompanying notes to the unaudited pro forma financial statements.

P-6

BRONCO DRILLING COMPANY, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Note 1.    Basis of Presentation, the Offerings and Other Transactions

The historical financial information is derived from the historical financial statements of Bronco Drilling, L.L.C., Strata and Thomas. The Thomas and Strata acquisitions are accounted for as purchases and, as a result, the acquired assets are recorded at their fair value at the time of purchase.

The pro forma financial statements reflect the following:

Formation and Offering Adjustments:

• The merger of our predecessor, Bronco Drilling Company, L.L.C., an Oklahoma limited liability company, into us, a taxable Delaware corporation, in August 2005;

• The sale of 5,715,000 shares of our common stock in our initial public offering at a price of $17.00 per share, our receipt of the estimated $89.7 million of net proceeds from such sale, after deducting the underwriting discount and estimated offering expenses payable by us;

• The repayment of $18.1 million of outstanding indebtedness and accrued interest as of June 30, 2005 with a portion of the proceeds from our initial public offering;

• Certain payments made by our principal stockholder to our former president; and

• The sale of 3,500,000 shares of common stock in this offering at an offering price of $23.00 per share for proceeds of $75.6 million, net of underwriting discounts and estimated offering expenses, and the application of such proceeds as set forth under “Use of Proceeds.”

Pro Forma Adjustments:

• The acquisition of all the membership interests in Strata and a related rig yard. Included in these acquisitions were two operating rigs, one rig that is currently being refurbished, related structures, equipment and components and a 16-acre yard in Oklahoma City, Oklahoma used for equipment storage and refurbishment of stacked rigs. The aggregate purchase price was $20.0 million, of which $13.0 million was paid in cash and $7.0 million was paid in the form of promissory notes issued to the sellers; and

• The acquisition of Thomas for approximately $68.0 million in cash. In this acquisition we acquired nine operating rigs, two rigs currently being refurbished, two inventoried rigs and excess rig equipment and inventory. The purchase price was partially funded through a $50 million loan from Theta Investors LLC which will be repaid from a portion of the proceeds of this offering. Therefore, pro forma interest expense is not reflected in the unaudited pro forma combined statements of operations.

Note 2.    Pro Forma Adjustments and Assumptions

(a) Reflects: the merger of our predecessor, an Oklahoma limited liability company, into us, a taxable Delaware corporation; the recognition of deferred tax liability and expense; and the issuance of 13,360,000 shares of common stock to our founder in the merger. The $4.4 million effect of the change in tax status as a result of the merger is a material nonrecurring charge resulting directly from the formation transaction that will be charged to operations for the three months ended September 30, 2005 and is not included in the unaudited pro forma combined statements of operations.

P-7

BRONCO DRILLING COMPANY, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS – CONTINUED

Note 2.    Pro Forma Adjustments and Assumptions - Continued

(b) Reflects the net proceeds of $89.7 million from the issuance and sale of 5,715,000 shares of common stock in our initial public offering at a price of $17.00 per share, after deducting the underwriting discount and estimated offering expenses.

(c) Reflects the use of a portion of the proceeds from our initial public offering to repay $18.1 million of outstanding indebtedness and accrued interest.

(d) Reflects the one-time payment by our principal stockholder to our former president of $2.0 million in cash and shares of our common stock having market value of $2.0 million based on the initial public offering price. The payment results in a capital contribution of $4.0 million and compensation expense which will be included in operations for the three months ended September 30, 2005. However, as a material nonrecurring charge, the expense is not included in the unaudited pro forma combined statements of operations.

(e) To reflect the purchase of Strata assets and the related increase in depreciation expense resulting from the purchase price allocation to property and equipment in service, depreciated on a straight line basis over three to 15 years for the purchased drilling equipment and 30 years for the purchased building. The purchase price allocation to property and equipment includes $7.0 million allocated to a drilling rig, which is being refurbished (not in service) and is therefore not depreciated. It also represents an increase in debt issued to finance a portion of the purchase of Strata, and the related interest expense. The purchase price of $20.0 million was financed by a $13.0 million loan from Alpha Investors L.L.C. and $7.0 million in promissory notes issued to the sellers. The $13.0 million loan from Alpha Investors L.L.C. was due and paid upon completion of our initial public offering, and therefore does not result in an adjustment to recognize interest expense for pro forma purposes. The $7.0 million promissory notes to sellers do not bear interest, however, interest expense has been imputed on the notes at LIBOR plus 2.71%, our effective borrowing rate. The notes are due upon completion of rig refurbishment (on or before the end of 2005).

(f) To reflect the purchase of Thomas assets and the related increase in depreciation and amortization expense resulting from the purchase price allocation to property and equipment depreciated and amortized on a straight line basis over five to 15 years for the purchased drilling equipment, vehicles and intangibles related to customer relationships. The purchase price allocation to property and equipment includes $10.4 million allocated to inventoried rigs or rigs being refurbished (not in service) and is therefore not depreciated. The purchase price of approximately $68.0 million was partially funded through a $50 million loan from Theta Investors LLC which will be repaid from a portion of the proceeds of this offering. Therefore, pro forma interest expense is not reflected in the unaudited pro forma combined statements of operations.

(g) Reflects the elimination of interest expense due to repayment of outstanding indebtedness with proceeds from our initial public offering and this offering.

(h) To remove the historical basis of assets not acquired, liabilities not assumed and equity accounts of Strata and Thomas.

(i) To reflect income taxes for our predecessor assuming our predecessor was operated as a taxable corporation throughout each period (see note 3).

(j) Reflects the net proceeds of $75.6 million from the issuance and sale of 3,500,000 shares of our common stock in this offering at an offering price of $23.00 per share, after deducting the underwriting discount and estimated offering expenses.

P-8

BRONCO DRILLING COMPANY, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS – CONTINUED

Note 3.    Income Taxes

Our predecessor, a limited liability company, was classified as a partnership for income tax purposes. Accordingly, income taxes on net earnings were payable by the members and are not reflected in historical financial statements except for taxes associated with a taxable subsidiary. Pro forma adjustments are reflected to provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109. For unaudited pro forma income tax calculations, deferred tax assets and liabilities were recognized for the future tax consequences attributable to differences between the assets and liabilities and were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences. A statutory Federal tax rate of 34% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the pro forma enacted tax rate for all periods. The pro forma tax effects are based upon currently available information and assume the Company had been a taxable entity in the periods presented. Management believes that these assumptions provide a reasonable basis for presenting the pro forma tax effects.

P-9

BRONCO DRILLING COMPANY, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS – CONTINUED

Note 4.    Pro Forma Net Income (Loss) Per Share

Pro forma income (loss) per basic and diluted common share is computed based on weighted average pro forma number of basic and diluted shares assumed to be outstanding during the periods. Pro forma basic and diluted income (loss) per share is presented for the Predecessor’s Historical year ended December 31, 2004 and the six months ended June 30, 2005 on the basis of 13,360,000 shares issued to our founder in the merger immediately prior to our initial public offering in August 2005. The pro forma income (loss) per basic and diluted common share for the pro forma Bronco Drilling Company, Inc. as adjusted for Formation and Offering effects and the Pro Forma Combined adjusted for the acquisition of Strata and Thomas includes additional shares whose proceeds are reflected in the pro forma adjustments in the statements of operations. The net proceeds of these shares sold in our initial public offering ($15.81 per share) are assumed to be outstanding and used to repay $5.0 million of debt outstanding for the pro forma statement of operations for the six months ended June 30, 2005 which was required to be repaid as a result of our initial public offering and $81.0 million of proceeds used to fund the Strata and Thomas acquisitions, assumed to be used at January 1, 2004. No pro forma effect is given to shares which may be issuable under our Incentive Stock Option Plan adopted in August, 2005 or to 65,368 shares issued in connection with our acquisition of Hays Trucking, Inc. in September 2005 since these shares are not the result of the pro forma transactions. The weighted average additional shares outstanding are computed as follows:

Year ended December 31, 2004:
Proceeds used in Thomas Acquisition	$	68,000,000
Proceeds used in Strata Acquisition		13,000,000
	$	81,000,000
Net Proceeds Per Share		÷$15.81
Shares Assumed to be Issued		5,123,000
Founders Shares		13,360,000
Weighted average pro forma shares outstanding – basic and diluted		18,483,000
Six months ended June 30, 2005:
Proceeds used in Thomas Acquisition	$	68,000,000
Proceeds used in Strata Acquisition		13,000,000
Proceeds used to retire weighted average balance of Solitair debt		4,436,000
	$	85,436,000
Net Proceeds Per Share		÷$15.81
Shares Assumed to be Issued		5,404,000
Founders Shares		13,360,000
Weighted average pro forma shares outstanding – basic and diluted		18,764,000

P-10

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Bronco Drilling Company, L.L.C. and Subsidiaries (Predecessor)
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2004 and 2003 and June 30, 2005 (unaudited)	F-3
Consolidated Statements of Operations and Members’ Equity for the Years Ended December 31, 2004, 2003 and 2002 and for the six months ended June 30, 2005 and 2004 (unaudited)	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 and for the six months ended June 30, 2005 and 2004 (unaudited)	F-5
Notes to Consolidated Financial Statements	F-6
Bronco Drilling Company, Inc.
Report of Independent Registered Public Accounting Firm	F-18
Balance Sheet as of June 30, 2005	F-19
Note to Balance Sheet	F-20
Strata Drilling, L.L.C. and Affiliate
Report of Independent Registered Public Accounting Firm	F-21
Combined Balance Sheets as of December 31, 2004 and June 30, 2005 (unaudited)	F-22
Combined Statements of Operations and Members’ Equity for the Year Ended December 31, 2004 and for the six months ended June 30, 2005 (unaudited)	F-23
Combined Statements of Cash Flows for the Year Ended December 31, 2004 and for the six months ended June 30, 2005 (unaudited)	F-24
Notes to Combined Financial Statements	F-26
Thomas Drilling Company
Report of Independent Accountant	F-32
Balance Sheets as of December 31, 2004, and 2003 and June 30, 2005 (unaudited)	F-33
Statements of Operations and Shareholders’ Equity for the years ended December 31, 2004 and 2003 and for the six months ended June 30, 2005 (unaudited)	F-34
Statements of Cash Flows for the years ended December 31, 2004 and 2003 and for the six months ended June 30, 2005 (unaudited)	F-35
Notes to Financial Statements	F-36

F-1

Report of Independent Registered Public Accounting Firm

Members

Bronco Drilling Company, L.L.C.

We have audited the accompanying consolidated balance sheets of Bronco Drilling Company, L.L.C. (an Oklahoma limited liability company) and Subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations and members’ equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Bronco Drilling Company, L.L.C. and Subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

April 21, 2005

F-2

Bronco Drilling Company, L.L.C. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands)

	June 30, 2005		December 31,
ASSETS			2004		2003
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	13,623	$	1,139	$	1,663
Receivables
Trade, net of allowance for doubtful accounts of $146 in     2005 and 2004 and $0 in 2003		7,276		5,557		2,997
Contract drilling in progress		2,186		1,403		609
Other		—		—		75
Prepaid expenses		410		19		338
Total current assets		23,495		8,118		5,682
PROPERTY AND EQUIPMENT – AT COST
Drilling rigs and related equipment		99,096		86,090		67,144
Transportation, office and other equipment		3,347		1,992		1,447
		102,443		88,082		68,591
Less accumulated depreciation		9,764		6,913		3,238
		92,679		81,169		65,353
OTHER ASSETS
Debt issue costs, net of amortization		356		242		241
Restricted cash and other		2,376		614		644
		2,732		856		885
	$	118,906	$	90,143	$	71,920
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	5,824	$	3,922	$	1,071
Accrued liabilities
Payroll related		602		863		57
Deferred revenue and other		975		396		16
Note payable		2,500		1,800		1,300
Current maturities of long-term debt		4,600		3,550		600
Total current liabilities		14,501		10,531		3,044
LONG-TERM DEBT; less current maturities ($18,000 to affiliate at June 30, 2005)		32,900		12,750		2,400
DEFERRED INCOME TAXES		15,828		16,059		15,774
COMMITMENTS AND CONTINGENCIES (Notes F and H)
MEMBERS’ EQUITY		55,677		50,803		50,702
	$	118,906	$	90,143	$	71,920

The accompanying notes are an integral part of these statements.

F-3

Bronco Drilling Company, L.L.C. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS AND MEMBERS’ EQUITY

(Amounts in thousands, except per share amounts)

	Six Months Ended June 30,						Year ended December 31,
	2005			2004			2004			2003			2002
	(Unaudited)
REVENUES
Contract drilling (13% from an affiliate in 2002)	$	20,269		$	7,758		$	21,873		$	12,533		$	3,115
EXPENSES
Contract drilling		12,870			6,937			18,670			10,537			3,239
Depreciation		2,851			1,534			3,695			1,985			1,122
General and administrative		1,123			686			1,714			1,226			676
		16,844			9,157			24,079			13,748			5,037
Income (loss) from operations		3,425			(1,399	)		(2,206	)		(1,215	)		(1,922	)
OTHER INCOME (EXPENSE)
Interest expense		(309	)		(48	)		(285	)		(21	)		—
Interest income		12			5			10			3			5
		(297	)		(43	)		(275	)		(18	)		5
Income (loss) before income taxes		3,128			(1,442	)		(2,481	)		(1,233	)		(1,917	)
Deferred tax expense (benefit)		(231	)		(85	)		285			317			—
NET INCOME (LOSS)		3,359			(1,357	)		(2,766	)		(1,550	)		(1,917	)
Members’ equity at beginning of period		50,803			50,702			50,702			15,010			2,824
Capital contributions		1,515			—			2,867			37,242			14,103
Members’ equity at end of period	$	55,677		$	49,345		$	50,803		$	50,702		$	15,010
PRO FORMA INFORMATION (unaudited):
Historical income (loss) from operations before income taxes	$	3,128		$	(1,442	)	$	(2,481	)	$	(1,233	)	$	(1,917	)
Pro forma provision (benefit) for income taxes		1,181			(544	)		(936	)		(465	)		(723	)
Pro forma income (loss)	$	1,947		$	(898	)	$	(1,545	)	$	(768	)	$	(1,194	)
Pro forma income (loss) per common share – Basic and Diluted	$	0.15		$	(0.07	)	$	(0.12	)	$	(0.06	)	$	(0.09	)
Weighted average pro forma common shares outstanding-Basic and Diluted		13,360			13,360			13,360			13,360			13,360

The accompanying notes are an integral part of these statements.

F-4

Bronco Drilling Company, L.L.C. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Six Months Ended June 30,						Year ended December 31,
	2005			2004			2004			2003			2002
	(Unaudited)
Cash flows from operating activities
Net income (loss)	$	3,359		$	(1,357	)	$	(2,766	)	$	(1,550	)	$	(1,917	)
Adjustments to reconcile net income ( loss) to net cash provided by (used in) operating activities
Depreciation and amortization		2,881			1,553			3,738			1,988			1,122
Change in deferred income taxes		(231	)		(85	)		285			317			—
Change in assets and liabilities
Receivables, net		(2,502	)		(1,065	)		(3,279	)		(2,848	)		(545	)
Prepaid expenses		(392	)		31			319			(307	)		(3	)
Other assets		(217	)		70			30			(38	)		(6	)
Accounts payable		(319	)		2,519			2,850			655			256
Accrued and other liabilities		318			654			1,187			(131	)		203
Net cash provided by (used in) operating activities		2,897			2,320			2,364			(1,914	)		(890	)
Cash flows from investing activities
Acquisition of property and equipment		(12,170	)		(10,736	)		(19,511	)		(4,246	)		(379	)
Restricted cash account		(1,515	)		—			—			(600	)		—
Acquisition of business		—			—			—			—			(12,500	)
Net cash used in investing activities		(13,685	)		(10,736	)		(19,511	)		(4,846	)		(12,879	)
Cash flows from financing activities
Debt issue costs		(143	)		—			(44	)		(244	)		—
Proceeds from borrowings ($18,000 from affiliate in 2005)		23,700			9,000			15,500			4,300			—
Principal payments on borrowings		(1,800	)		(750	)		(1,700	)		—			—
Capital contributions		1,515			—			2,867			3,742			14,103
Net cash provided by financing activities		23,272			8,250			16,623			7,798			14,103
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		12,484			(166	)		(524	)		1,038			334
Cash and cash equivalents at beginning of year		1,139			1,663			1,663			625			291
Cash and cash equivalents at end of year	$	13,623		$	1,497		$	1,139		$	1,663		$	625
Supplemental Disclosure of Cash Flow Information
Interest paid, net of amount capitalized	$	189		$	48		$	241		$	11		$	—

Supplemental Disclosure of Noncash Investing and Financing Activities

In connection with the contribution of Elk Hill’s common stock and certain drilling rigs, structures and components to the Company by the Company’s members in 2003, assets of approximately $49,000 were acquired and liabilities of approximately $15,500 were assumed (Note B).

The accompanying notes are an integral part of these statements.

F-5

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES

Bronco Drilling, L.L.C. (the “Company”) was formed on June 1, 2001 and provides contract drilling services to oil and gas exploration and production companies, primarily in Oklahoma. As a limited liability company, members have limited liability for the obligations or debts of the Company and the term of the Company will expire upon the sale of all or substantially all of the Company’s properties. The Company has two consolidated subsidiaries: Elk Hill Drilling, Inc. (“Elk Hill”) and Wrangler Equipment, LLC. All material intercompany accounts and transactions have been eliminated in consolidation.

In August 2003, the Company’s members acquired and contributed to the Company the outstanding stock of Elk Hill. The cost of Elk Hill’s stock was allocated to the assets acquired and liabilities assumed based on their fair values at the date of acquisition and, since Elk Hill is a taxable entity, the Company recognized deferred tax liabilities for the differences between the assigned values and the tax bases of the recognized assets acquired and liabilities assumed (see Note B).

A summary of the significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows.

1.    Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market mutual funds to be cash equivalents.

The Company maintains its cash and cash equivalents in accounts and instruments which may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risks on cash and cash equivalents.

At December 31, 2004 and 2003, the Company had restricted cash of $600 at a bank that collateralized a letter of credit to the Company’s workers’ compensation insurer. At June 30, 2005, the Company had restricted cash of $2,115 at a bank collateralizing letters of credit with the Company’s workers’ compensation insurers.

2.    Revenue Recognition

The Company earns contract drilling revenue under daywork and footage contracts.

The Company follows 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 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.

Revenues on daywork contracts are recognized based on the days completed at the dayrate each contract specifies. Mobilization revenues and costs for daywork contracts are deferred and recognized over the days of actual drilling.

F-6

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES - CONTINUED

2.    Revenue Recognition - Continued

The receivables from contract drilling in progress represents revenues in excess of amounts billed on contracts in progress.

Revenue arising from claims for amounts billed in excess of the contract price or for amounts not included in the original contract are recognized when billed less any allowance for uncollectibility. Revenue from such claims is only recognized if it is probable that the claim will result in additional revenue, the costs for the additional services have been incurred, management believes there is a legal basis for the claim and the amount can be reliably estimated. Historically, such claims have been immaterial as we have not billed any customers for amounts not included in the original contract.

3.    Accounts Receivable

Substantially all of the Company’s accounts receivable are due from companies in the oil and gas industry. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.

4.    Property and Equipment

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs are expensed currently. Assets are depreciated on a straight-line basis. The depreciable lives of drilling rigs and related equipment are three to 15 years. The depreciable life of other equipment is three years. Depreciation is not commenced until acquired rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished or between periods of deployment. Assets not placed in service and not being depreciated were $36,131, $34,118 and $45,329 as of June 30, 2005 and December 31, 2004 and 2003, respectively.

The Company capitalizes interest as a component of the cost of drilling rigs constructed for its own use. During the year ended December 31, 2004, interest incurred was approximately $754, of which approximately $470 was capitalized and $284 was charged to operations. No amounts were capitalized in 2003 or 2002.

The Company reviews long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the assets, the Company recognizes an impairment loss based upon fair value of the asset.

F-7

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES - CONTINUED

5.    Debt Issue Costs

Legal fees and other debt issue costs incurred in obtaining financing are amortized over the term of the debt, approximately 60 months, using a method which approximates the effective interest method. Amortization expense was $43, $3 and $0 for the years ended December 31, 2004, 2003 and 2002, respectively, and is included in interest expense in the consolidated statements of operations. Accumulated amortization was $46 and $3 as of December 31, 2004 and 2003, respectively.

6.    Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts and disclosures; accordingly, actual results could differ from those estimates.

7.    Income Taxes

The Company, a limited liability company, is classified as a partnership for income tax purposes; accordingly, income taxes on net earnings are payable by the members and are not reflected in the financial statements. Pro forma adjustments are reflected on the statement of operations to provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109. For unaudited pro forma income tax calculations, deferred tax assets and liabilities were recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences. A statutory Federal tax rate of 34% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the pro forma enacted tax rate for all periods. The pro forma tax effects are based upon currently available information and assume the Company had been a taxable entity in all periods presented. Management believes that these assumptions provide a reasonable basis for presenting the pro forma tax effects.

Elk Hill is a taxable entity and a current income tax provision is provided for estimated income taxes payable or refundable on tax returns for the periods. Also, deferred income taxes are provided to reflect the future tax consequences of carryforwards and differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred income tax assets and liabilities are reflected at currently enacted income tax rates applicable to the period in which the carryforwards or the deferred tax assets or liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred income tax assets and liabilities are adjusted through the provision for income taxes. 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. The classification of current and noncurrent deferred tax assets and liabilities is based primarily on the classification of the assets and liabilities generating the difference.

8.    Pro Forma Income (Loss) Per Common Share

Pro forma income per basic and diluted common share is computed based on the weighted average pro forma number of basic and diluted shares outstanding during the period. Pro forma basic and diluted income (loss) per share is presented for all periods on the basis of shares to be issued to the Company’s founders.

F-8

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES - CONTINUED

9.    Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 123(R), Share Based Payment, which revised SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) requires entities to measure the fair value of equity share-based payments (stock compensation) at grant date, and recognize the fair value over the period during which an employee is required to provide services in exchange for the equity instrument as a component of the income statement. SFAS No. 123(R) is effective for annual periods beginning after June 15, 2005. The Company has not had any stock option plans and, therefore the adoption of SFAS No. 123(R) currently would have no impact on its financial position or results of operations. The adoption could have a future impact, however, as the Company intends to implement its 2005 stock incentive plan in connection with its initial public offering.

10.    Reclassifications

Certain reclassifications have been made to the 2004 and 2003 consolidated financial statements to conform to the presentation for the six months ended June 30, 2005.

NOTE  B  -  ACQUISITIONS

In August 2003, the members of the Company acquired the outstanding stock of Elk Hill for $45,458, which was comprised of $30,000 paid in cash and $15,458 of assumed deferred tax liabilities, and contributed the stock to the Company. Elk Hill’s assets included drilling rigs and inventoried structures and components to complete drilling rigs which, with refurbishment and upgrades, can be placed in service to supplement the Company’s existing fleet. At the date of its acquisition, Elk Hill had no customers, employees, operations or operational drilling rigs. As part of the acquisition of Elk Hill, members of the Company acquired certain drilling rig structures and components from an affiliate of Elk Hill for $3,521 and contributed these assets to the Company. These assets will be used as component parts for drilling rigs and, as such, are reported as drilling rigs and related equipment in the accompanying consolidated balance sheets. At December 31, 2004, refurbishment had been completed on five drilling rigs and two drilling rigs were undergoing refurbishment. The Company expects to refurbish and complete additional drilling rigs at significant additional cost to the Company. The acquisitions were accounted for at the members’ cost basis and the results of their operations have been included in the consolidated results of operations since the date of contribution.

The following summarizes the assets acquired and liabilities assumed:

Drilling rigs and related equipment	$	48,979
Deferred tax liabilities		(15,458	)
Net assets acquired	$	33,521

In May 2002, the Company acquired the drilling operations of Bison Drilling L.L.C. (“Bison”) and Four Aces Drilling L.L.C. (“Four Aces”) for approximately $12,500. Bison and Four Aces were wholly owned subsidiaries of a privately owned independent oil and gas exploration company. The assets consisted of seven drilling rigs and associated spare parts and equipment and were acquired to expand the Company’s drilling operations. The

F-9

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  B  -  ACQUISITIONS - CONTINUED

operations of the acquired companies are included in the statements of operations of the Company since the acquisition in May 2002. The purchase price was allocated to the drilling rigs and equipment based upon their fair value.

The following summarizes the assets acquired and liabilities assumed:

Drilling rigs and related equipment	$	12,055
Vehicles		445
		12,500
Liabilities assumed		—
Net assets acquired	$	12,500

The unaudited pro forma information of the Company set forth below includes the operations of Bison and Four Aces for the year ended December 31, 2002 as if the acquisition occurred on January 1, 2002. The unaudited pro forma information is presented for information only and is not necessarily indicative of the results of operations that would have been achieved had the acquisition been consummated at that time:

	As reported			Pro Forma
Revenue	$	3,115		$	6,103
Net loss	$	(1,917	)	$	(1,794	)

NOTE  C  -  NOTE PAYABLE

Note payable consists of advances under a $2,000 revolving line of credit with a bank (“Bank Note Payable”) that bears interest based on JPMorgan Chase prime (effective rate of 5.25% at December 31, 2004). Interest on the line of credit is due monthly with outstanding principal due July 1, 2005 and is guaranteed by the Company’s members, and is collateralized by the Company’s accounts receivable. The note has certain financial covenants which include maintaining a 1 to 1 current ratio and minimum tangible net worth for which the Company was in compliance at December 31, 2004 and, among other things, prohibits the payment of dividends. Effective January 1, 2005, the line was increased to $3,000 and the maturity date extended to November 1, 2005.

NOTE  D  -  LONG-TERM DEBT

Long-term debt consists of the following at December 31:

	2004		2003
Corporate term note	$	16,300	$	3,000
Less current maturities		3,550		600
	$	12,750	$	2,400

The term note (“GECC Term Note”) from a commercial lender provides for monthly advances at the Company’s request of at least $3,000, subject to maximum borrowings of $18,000. At December 31, 2004, the Company has

F-10

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  D  -  LONG-TERM DEBT - CONTINUED

no amounts available to be advanced. Each advance is payable in 60 equal monthly installments with final maturity at April 1, 2010. Interest is due monthly at LIBOR plus 5% (effective rate of 7.28% at December 31, 2004). The term note is collateralized by the Company’s assets, excluding cash and accounts receivable. Effective April 22, 2005, the borrowing limit was increased to $25,500.

Future maturities of long-term debt at December 31, 2004 are as follows:

Year ending December 31
2005	$	3,550
2006		3,600
2007		3,600
2008		3,600
2009		1,900
Thereafter		50
	$	16,300

The GECC Term Note contains covenants that require the Company to maintain certain financial ratios and reporting requirements. The Company must maintain a debt service coverage ratio of not less than 1 to 1 for each fiscal quarter. The debt service coverage ratio is defined as the Company’s EBITDA to the sum of interest expense and all installments of principal on indebtedness that are due on demand or during the period of determination. The Company has reporting requirements to provide audited financial statements 90 days subsequent to year-end. The Company delivered its audited financial statements for the year ended December 31, 2004 in May 2005 and early this year the Company increased its borrowing base under its line of credit under the Bank Note Payable without obtaining the prior approval of GECC. GECC has waived both of these events.

On February 15, 2005 the Company entered into a $5,000 credit facility with Solitair LLC, one of its members. The facility bears interest at a rate equal to LIBOR plus 5.0% (effective rate of 7.69% at March 31, 2005). Payment of principal and accrued but unpaid interest is due on the maturity date of the credit facility which is the later of (1) six months after the actual maturity date of our credit facility with GECC and (2) December 1, 2010. Borrowings under this credit facility were used primarily for the refurbishment of the Company’s rig fleet. At March 31, 2005, the outstanding borrowings under this credit facility were $3,000.

NOTE  E  -  INCOME TAXES

Income tax expense consists of the following for the years ended December 31:

	2004		2003		2002
Deferred tax expense	$	285	$	317	$	—

F-11

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  E  -  INCOME TAXES - CONTINUED

Deferred income tax assets and liabilities are as follows at December 31:

	2004			2003
Deferred income tax assets related to:
Net operating loss carryforwards	$	7		$	9
Deferred income tax liabilities related to:
Drilling rigs and equipment		(16,067	)		(15,783	)
Net deferred income tax liabilities	$	(16,060	)	$	(15,774	)

The provision for income taxes on continuing operations differs from the amounts computed by applying the federal income tax rate of 34% to net income. The differences are summarized as follows for the years ended December 31:

	2004			2003
Tax benefit at federal statutory rate	$	(843	)	$	(419	)
Tax benefit at state statutory rate		(149	)		(74	)
Increase (decrease) from
Loss attributable to nontaxable entity		1,294			831
Other		(17	)		(21	)
Actual tax provision	$	285		$	317

The difference between the Company’s effective tax rate and the statutory federal income tax rate results from taxes being provided on only Elk Hill for the years ended December 31, 2004 and 2003. Prior to 2003, the Company had no taxable entities.

NOTE  F  -  WORKERS’ COMPENSATION

The Company is insured under a large deductible workers’ compensation insurance policy. The policy generally provides for a $100 deductible per covered accident. Due to the high deductible, the policy requires the Company to maintain a $600 letter of credit with a bank. At December 31, 2004 and 2003, the Company has a $600 deposit with a bank collateralizing the letter of credit. The deposit is reflected in other assets.

NOTE  G  -  TRANSACTIONS WITH AFFILIATES

An entity under common management provides office space and certain administrative services to the Company. The Company reimbursed the entity approximately $115, $33 and $37 in consideration for those services during the years ended December 31, 2004, 2003 and 2002, respectively. The administrative reimbursement amount is determined by management’s estimates on time devoted to each company. At December 31, 2004 and 2003, approximately $17 and $6, respectively, was owed to the entity and included in accounts payable.

Additionally, the Company provided contract drilling services totaling $184 and $396 to an affiliated entity during 2003 and 2002, respectively.

F-12

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  H  -  COMMITMENTS AND CONTINGENCIES

The Company leases three service locations under a noncancelable operating lease that expires in August 2008. Related rent expense was $177, $98 and $42 for the years ended December 31, 2004, 2003 and 2002, respectively.

Aggregate future minimum lease payments under the noncancelable operating lease for years subsequent to December 31, 2004 are as follows:

Year ending December 31
2005	$	150
2006		180
2007		180
2008		120
	$	630

The Company currently has a lawsuit pending, in which the Company sued the defendant, an oil and gas operating company, for approximately $942 as a result of the defendant’s refusal to make payment pursuant to the terms of its drilling contract. The defendant has countersued for damages in excess of $2,800, alleging breach of contract, negligence, gross negligence and breach of warranties. Currently, no trial date has been set by the court. The Company is vigorously prosecuting its claims and defending against the counterclaims in this matter, and will continue to file appropriate responses, motions and documents as necessary. It is not possible to predict the outcome of this matter.

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 or results of operations.

NOTE  I  -  SIGNIFICANT CUSTOMERS

For 2004, revenue from one customer was approximately 11% of total revenues, for 2003 two customers accounted for 13% and 11% of total revenues, and for 2002 three customers accounted for 23%, 16% and 13% of total revenues. At December 31, 2004, three customers accounted for approximately 17%, 13% and 12% of accounts receivable. At December 31, 2003, three customers accounted for approximately 28%, 13% and 13% of accounts receivable.

NOTE  J  -  FAIR VALUE OF FINANCIAL STATEMENTS

Cash and cash equivalents, trade receivables and payables and short-term debt:

The carrying amounts of cash and cash equivalents, trade receivables, restricted cash, payables and short-term debt approximate their fair values.

Long-term debt and note payable.

The carrying amounts of our long-term debt and note payable approximate fair value, as supported by the recent issuance of the debt and because the variable rates approximate market rates.

F-13

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  K  -  VALUATION AND QUALIFYING ACCOUNTS

The Company’s valuation and qualifying accounts for the years ended December 31, 2004, 2003 and 2002 are as follows:

	Balance at Beginning of Period	Additions Charged to Costs and Expenses		Deductions Describe	Foreign Currency Translation	Balance at End Period
Accounts Receivable Reserves:
Year ended December 31, 2004 Bad Debt Reserve	—	$	146,000	—	—	$	146,000
Year ended December 31, 2003 Bad Debt Reserve	—		—	—	—		—
Year ended December 31, 2002 Bad Debt Reserve	—		—	—	—		—

NOTE  L  -  SUBSEQUENT EVENTS (unaudited)

In connection with the Company’s initial public offering of common stock in 2005, substantially all of the Company’s assets and liabilities were transferred to Bronco Drilling Company, Inc., a newly formed Delaware corporation.

Prior to the closing of the offering the Company converted to a taxable Delaware corporation. The pro forma effect of this merger and change in tax status is as follows:

	June 30, 2005
	Historical		Pro Forma
Deferred income taxes	$	15,828	$	20,240
Equity
Members’ equity	$	55,677	$	—
Common stock $.01 par value 100,000 shares authorized; 10,000 shares issued and outstanding		—		100
Additional paid-in capital		—		55,577
Accumulated deficit		—		(4,412	)
Total equity	$	55,677	$	51,265

A one-time charge to operations of approximately $4,412 will be recognized in the third quarter to record deferred taxes upon change in tax status.

In July 2005, the Company acquired all the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard. Included in these acquisitions were two operating rigs, one rig that is currently being refurbished, related structures, equipment and components and a 16 acre yard in Oklahoma City, Oklahoma used for equipment storage and refurbishment of stacked rigs. The aggregate purchase price was

F-14

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  L  -  SUBSEQUENT EVENTS (unaudited) - CONTINUED

$20,000, of which $13,000 was paid in cash and $7,000 was paid in the form of promissory notes issued to the sellers. The Company funded the cash portion of the purchase price with a $13,000 loan from Alpha Investors LLC, an entity controlled by Wexford Capital LLC. The outstanding principal balance of the Alpha loan plus accrued but unpaid interest must be repaid in full upon the earlier to occur of the completion of this offering and the maturity of the loan on July 1, 2006. Borrowings under the Company’s loan with Alpha bear interest at a rate equal to LIBOR plus 5% until September 30, 2005 (effective rate of 8.11% when the loan was made on June 30, 2005), and thereafter at a rate equal to LIBOR plus 7.5%. The $7,000 outstanding principal balance of the promissory notes issued to the sellers is automatically reduced by the amount of any costs and expenses the Company pays in connection with the refurbishment of one of the rigs we acquired from the sellers. The sellers have agreed to complete the refurbishment of this rig on or before the end of 2005, subject to limited exceptions. Payment of the outstanding balance of the loan is due and payable upon completion of the refurbishment of this rig. The Company granted the sellers a security interest in this rig to secure its obligations under the notes. The outstanding principal balance on these notes do not bear any interest other than default interest in the event of a default.

The Bank Note Payable has a borrowing base equal to the lesser of $3,000 or 80% of current receivables. As of June 30, 2005 the note payable had a balance of $2,500 and had available borrowings of $500 with an effective interest rate of 6.25%. The Company was in compliance with all financial covenants related to the note payable.

At June 30, 2005, the balance of the GECC Term Note was $19,500 and had available borrowings of $2,500 with an effective interest rate of 8.11%. At June 30, 2005, the Company was in compliance with all financial covenants related to the term note. There were no available borrowings through credit facilities with Solitair LLC and Alpha Investors LLC.

Future maturities of note payable and long-term debt at June 30, 2005 are as follows:

2006	$	7,100
2007		17,600
2008		4,600
2009		4,050
2010		1,650
Thereafter		5,000
	$	40,000

Effective April 1, 2005, the Company entered into an administrative services agreement with Gulfport. Under this agreement, Gulfport’s services for the Company include accounting, human resources, legal and technical support. In return for the services rendered by Gulfport, the Company has agreed to pay Gulfport an annual fee of approximately $414 payable in equal monthly installments during the term of this agreement. In addition, the Company will continue to lease approximately 1,100 square feet of office space from Gulfport for the Company’s headquarters. The Company will pay Gulfport annual rent of approximately $20 payable in equal monthly installments. The services being provided to the Company and the fees for such services can be amended by mutual agreement of the parties. The administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by the Company at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other

F-15

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  L  -  SUBSEQUENT EVENTS (unaudited) - CONTINUED

party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. The fees payable by the Company under the administrative services agreement were arrived at through negotiations between the Company and Gulfport.

Under the terms of an agreement between Bronco Drilling Holdings L.L.C., the Company’s principal shareholder, and Steven C. Hale, the Company’s President and Chief Operating Officer, following completion of the offering, Mr. Hale will be entitled to receive the sum of $2,000 and shares of the Company’s common stock having a market value of $2,000 based on the initial public offering price. These payments will be made by Bronco Drilling Holdings and not by the Company. The Company will account for these payments as a capital contribution to it in the amount of $4,000 and compensation expense in the amount of $4,000 during the period in which such obligations are incurred.

On September 19, 2005, the Company entered into a Term Loan and Security Agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc., as lender (“Merrill Lynch” or the “lender”). The term loan provides for a term installment loan in an aggregate amount not to exceed $50,000 and provides for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan may not exceed 60% of the net orderly liquidation value of the Company’s operating land drilling rigs. The lender’s commitment to make advances expires on December 31, 2005. Proceeds of the term loan may be used to replenish working capital for general business purposes, finance improvements to and the refurbishment of land drilling rigs, and to acquire additional land drilling rigs. On September 19, 2005, the Company borrowed $43,000 under the term loan.

The term loan bears interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points. For the period from September 19, 2005 to January 1, 2006, interest only is payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan will be payable in sixty consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. Any outstanding principal and accrued but unpaid interest will be immediately due and payable in full on January 1, 2011.

The Company’s obligations under the term loan are collateralized by a first lien and security interest on substantially all of the Company’s assets and are guaranteed by each of the Company’s principal subsidiaries. The term loan includes usual and certain restrictive negative covenants and requires the Company to meet certain financial covenants, including maintaining (1) a minimum “Fixed Charge Coverage Ratio”, and (2) a maximum “Total Debt to EBITDA Ratio”, as defined in the agreement.

On October 3, 2005, the Company purchased 12 rigs from Eagle Drilling, L.L.C. and two of its affiliates. This acquisition involved five operating rigs, seven inventoried rigs and rig equipment and parts for a purchase price of approximately $50,000.

On October 14, 2005, the Company purchased 13 land drilling rigs from Thomas Drilling Co. This acquisition involved nine operating rigs, two rigs currently being refurbished, two inventoried rigs and rig equipment and parts for a purchase price of approximately $68,000. In connection with this acquisition, the Company leased the use of an additional rig refurbishment yard for a six-month term, with the right to extend the term for an

F-16

Bronco Drilling Company, L.L.C. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2004 and 2005 is unaudited)

(Amounts in thousands, except per share amounts)

NOTE  L  -  SUBSEQUENT EVENTS (unaudited) - CONTINUED

additional three years, and obtained an option to purchase the yard for $175. The purchase price was partially funded through a $50,000 loan from Theta Investors LLC, an affiliate of Wexford, which is expected to be repaid from the proceeds of an offering of the Company’s stock. The loan provides for maximum aggregate borrowings of up to $60.0 million that bear interest at a rate equal to LIBOR plus 400 basis points (7.98% at October 14, 2005 and upon the initial borrowing under this facility) until December 15, 2005, and thereafter at a rate equal to LIBOR plus 600 basis points. Payment of principal and accrued but unpaid interest is due on October 14, 2006.

F-17

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholder

Bronco Drilling Company, Inc.

We have audited the accompanying balance sheet of Bronco Drilling Company, Inc. as of June 30, 2005. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement 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 the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Bronco Drilling Company, Inc. as of June 30, 2005 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

September 27, 2005

F-18

Bronco Drilling Company, Inc.

Balance Sheet

June 30, 2005

Assets
Cash	$	100
Total Assets	$	100
Stockholder’s Equity
Stockholder’s Equity
Common stock $0.01 par value; 100,000,000 shares authorized; 100 shares issued and outstanding	$	1
Additional paid-in capital		99
Total Stockholder’s Equity	$	100

The accompanying note is an integral part of this balance sheet.

F-19

Bronco Drilling Company, Inc.

Note to Balance Sheet

June 30, 2005

Bronco Drilling Company, Inc. (the “Corporation”) is a Delaware corporation capitalized on May 26, 2005 to acquire and operate the drilling business of Bronco Drilling Company, L.L.C., our predecessor company. Other than initial capitalization through June 30, 2005 there have been no other transactions involving the Corporation.

In August 2005, the Company merged with Bronco Drilling Company, L.L.C., completed its initial public offering, and issued 5,715,000 shares of common stock at $17.00 per share for net proceeds of $89.7 million, after deducting underwriting commissions and other offering expenses.

F-20

Report of Independent Registered Public Accounting Firm

Members

Strata Drilling, L.L.C. and Affiliate

We have audited the accompanying combined balance sheet of Strata Drilling, L.L.C. (an Oklahoma limited liability company) and Affiliate as of December 31, 2004, and the related combined statements of operations and members’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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 the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Strata Drilling, L.L.C. and Affiliate as of December 31, 2004, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

September 21, 2005

F-21

Strata Drilling, L.L.C. and Affiliate

COMBINED BALANCE SHEETS

(Amounts in thousands)

	June 30, 2005			December 31, 2004
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	201		$	378
Short-term investments		952			—
Trade receivables		1,053			407
Other		3			5
Total current assets		2,209			790
PROPERTY AND EQUIPMENT – AT COST
Drilling rigs and related equipment		5,868			5,574
Transportation, office, other equipment and building		1,351			1,295
		7,219			6,869
Less accumulated depreciation		1,012			1,249
		6,207			5,620
ASSETS HELD FOR SALE		—			6,626
	$	8,416		$	13,036
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	693		$	337
Accrued liabilities
Payroll related		27			46
Deferred revenue and other		232			400
Current maturities of long-term debt		749			3,007
Total current liabilities		1,701			3,790
LONG-TERM DEBT, less current maturities ($699 and $1,067 to affiliates at June 30, 2005 and December 31, 2004)		2,580			8,222
COMMITMENTS AND CONTINGENCIES (NOTES E and F)
MEMBERS’ EQUITY
Members’ interest		6,439			3,746
Note receivable from member		(2,304	)		(2,722	)
		4,135			1,024
	$	8,416		$	13,036

The accompanying notes are an integral part of these statements

F-22

Strata Drilling, L.L.C. and Affiliate

COMBINED STATEMENTS OF OPERATIONS AND MEMBERS’ EQUITY

(Amounts in thousands)

	Six Months Ended June 30, 2005			Year Ended December 31, 2004
	(Unaudited)
REVENUES
Contract drilling	$	3,715		$	6,116
EXPENSES
Contract drilling		1,965			3,570
Depreciation and amortization		272			392
General and administrative		781			1,144
		3,018			5,106
Income from operations		697			1,010
OTHER INCOME (EXPENSE)
Interest expense		(16	)		(312	)
Interest income		13			—
Gain on sale of assets		426			—
Other income		(15	)		14
		408			(298	)
Income from continuing operations		1,105			712
DISCONTINUED OPERATIONS
Income (loss) from operations of drilling rig sold (including gain on disposal of $3,211 for June 30, 2005)		3,174			542
NET INCOME		4,279			1,254
Members’ equity at beginning of period		1,024			3,003
Decrease (increase) in note receivable from member		419			(2,722	)
Distributions		(1,587	)		(511	)
Members’ equity at end of period	$	4,135		$	1,024

The accompanying notes are an integral part of these statements

F-23

Strata Drilling, L.L.C. and Affiliate

COMBINED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Six Months Ended June 30, 2005			Year Ended December 31, 2004
	(Unaudited)
Cash flows from operating activities
Net income	$	4,279		$	1,254
Adjustments to reconcile net income to net cash used in operating activities
Depreciation and amortization		272			645
(Gain)/loss on sale of assets		(3,637	)		—
Change in assets and liabilities
Short-term investments		(952	)		—
Trade receivables		(340	)		(438	)
Prepaid expenses		—			79
Other assets		2			158
Accounts payable		356			144
Accrued liabilities		(187	)		403
Net cash (used in) provided by operating activities		(207	)		2,245
Cash flows from investing activities
Proceeds from the sale of equipment		10,885			—
Acquisition of property and equipment		(1,786	)		(4,448	)
Net cash provided by (used in) investing activities		9,099			(4,448	)
Cash flows from financing activities
Proceeds from note payable		—			4,643
Principal payments on borrowings		(7,901	)		(2,013	)
Distributions		(1,168	)		(253	)
Net cash (used in) provided by financing activities		(9,069	)		2,377
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(177	)		174
Cash and cash equivalents at beginning of period		378			204
Cash and cash equivalents at end of period	$	201		$	378
Supplemental Disclosure of Cash Flow Information
Interest paid	$	16		$	312

The accompanying notes are an integral part of these statements

F-24

Strata Drilling, L.L.C. and Affiliate

COMBINED STATEMENTS OF CASH FLOWS – CONTINUED

(Information for the six months ended June 30, 2005 is unaudited)

(Amounts in thousands)

Supplemental Disclosure of Noncash Investing and Financing Activities

During 2004, certain members sold a combined 44% of their membership interests in the Company to an outside party. The Company issued notes payable to the sellers and obtained a note receivable from the buyer in the amount of $2,980. The Company makes payments on these notes payable and records a corresponding non-cash distribution to the buyer and reduction of note receivable from member. Non cash distributions and reductions of note receivable from member of $419 and $258 were recorded during the six-months ended June 30, 2005 and year ended December 31, 2004, respectively

During 2004, the Company and Affiliate also assumed and issued new debt in the amount of $4,251 related to the acquisition of rig equipment, a building and land.

F-25

Strata Drilling, L.L.C. and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

(Information as of June 30, 2005 and for the six months ended June 30, 2005 is unaudited)

(Amounts in thousands)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES

Strata Drilling, L.L.C. (the “Company”) was formed on October 26, 2000 and provides contract drilling services to oil and gas exploration and production companies, primarily in Oklahoma. As a limited liability company, members have limited liability for the obligations or debts of the Company and the term of the Company will expire upon the sale of all or substantially all of the Company’s properties. The Company has an affiliate, Strata Property, L.L.C. (Affiliate), that is combined with the Company due to common control by members. All material intercompany accounts and transactions have been eliminated in the combined financial statements.

A summary of the significant accounting policies consistently applied in the preparation of the accompanying combined financial statements follows.

1.    Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market mutual funds to be cash equivalents.

The Company maintains its cash and cash equivalents in accounts and instruments which may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risks on cash and cash equivalents.

2.    Investments

The Company determines the appropriate classification of its investments in debt and equity securities at the time of purchase and reevaluates such determinations at each balance sheet date. Debt securities are classified as held-to-maturity when the Company has the positive intent and ability to hold the securities to maturity. Debt securities for which the Company does not have the intent or ability to hold to maturity are classified as available-for-sale. Held-to-maturity securities are recorded as either short-term or long-term on the balance sheet based on contractual maturity date and are stated at amortized cost. Marketable securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and are reported at fair value, with unrealized gains and losses recognized in earnings. At June 30, 2005 the Company had approximately $952 in trading securities.

3.    Revenue Recognition

The Company earns contract drilling revenue under daywork and footage contracts.

The Company follows 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 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.

F-26

Strata Drilling, L.L.C. and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2005 is unaudited)

(Amounts in thousands)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES - CONTINUED

3.    Revenue Recognition - Continued

Revenues on daywork contracts are recognized based on the days completed at the dayrate each contract specifies. Mobilization revenues and costs for daywork contracts are deferred and recognized over the days of actual drilling.

The receivables from contract drilling in progress represents revenues in excess of amounts billed on contracts in progress.

Revenue arising from claims for amounts billed in excess of the contract price or for amounts not included in the original contract are recognized when billed less any allowance for uncollectibility. Revenue from such claims is only recognized if it is probable that the claim will result in additional revenue, the costs for the additional services have been incurred, management believes there is a legal basis for the claim and the amount can be reliably estimated. Historically, such claims have been immaterial as we have not billed any customers for amounts not included in the original contract.

4.    Accounts Receivable

The majority of the Company’s accounts receivable are due from companies in the oil and gas industry. Credit is extended based on the evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At June 30, 2005 and December 31, 2004 no accounts were evaluated as uncollectible.

5.    Property and Equipment

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs are expensed currently. Depreciation is provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives. The depreciable lives of drilling rigs and related equipment approximate 15 years. Depreciation is not commenced until rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished or between periods of deployment. The depreciable life of other equipment and building, ranges from five to 30 years.

The Company reviews long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the assets, the Company recognizes an impairment loss based upon fair value of the asset.

F-27

Strata Drilling, L.L.C. and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2005 is unaudited)

(Amounts in thousands)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES - CONTINUED

6.    Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts and disclosures; accordingly, actual results could differ from those estimates.

7.    Income Taxes

The Company and Affiliate, are limited liability companies, and are classified as partnerships for income tax purposes; accordingly, income taxes on net earnings are payable by the members and are not reflected in the financial statements.

NOTE  B  -  MEMBERS’ EQUITY

During 2004, certain members of the Company entered into a transaction with a third party and sold a combined 44% of their membership interests for approximately $3 million. The purchaser of the membership interests issued a note receivable to the Company for the amount of the purchase price and the Company entered into notes payable agreements with the selling members for the same amounts. The note receivable to the Company contains required monthly principal and interest payments and is collateralized by the purchaser’s interest in the Company. The note receivable for members’ interest is reported as a reduction of members’ equity in the accompanying combined financial statements. In lieu of monthly payments the Company records a distribution to the member and a reduction to the note receivable. The notes payable from the Company to the members are also payable in monthly installments, which include principal and interest ranging from 6%-7.2%.

F-28

Strata Drilling, L.L.C. and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2005 is unaudited)

(Amounts in thousands)

NOTE  C  -  LONG-TERM DEBT

Long-term debt consists of the following at:

	June 30, 2005		December 31, 2004
Note payable to bank in monthly installments of $103, including interest at prime plus 1% (6.25% at December 31, 2004), due in September 2007, collateralized by rig equipment, life insurance policy of member and all accounts receivable. The note was paid in full in 2005.	$	—	$	3,177
Note payable to bank in monthly installments of $8, including interest at prime (6.25% and 5.25% at June 30, 2005 and December 31, 2004, respectively), due in February 2014, uncollateralized		760		770
Notes payable to members in monthly installments of $83 including interest ranging from 6% to 7.2%, due dates ranging from June 2006 to May 2014, collateralized by member’s interest		2,569		4,181
Note payable to an entity in monthly installments of $14, including interest at 4%, due in June 2005, collateralized by rig equipment. The note was paid in full in 2005.		—		84
Note payable to bank in monthly installments of $39, including interest at prime plus 2%(7.25% at December 31, 2004), due in December 2009, collateralized by rig equipment. The note was paid in full in 2005.		—		2,016
Note payable to an entity in monthly installments of $22, including interest at 6.7%, due in May 2008, collateralized by equipment. The note was paid in full in 2005		—		806
Note payable to an entity in monthly installments of $12, including interest at 6%, due in June 2006, collateralized by rig equipment. The note was paid in full in 2005.		—		195
		3,329		11,229
Less current maturities		749		3,007
	$	2,580	$	8,222

Future maturities of long-term debt at December 31, 2004 are as follows:

Year ending December 31
2005	$	3,007
2006		2,490
2007		2,801
2008		1,357
2009		761
Thereafter		813
	$	11,229

F-29

Strata Drilling, L.L.C. and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2005 is unaudited)

(Amounts in thousands)

NOTE  D  -  TRANSACTIONS WITH AFFILIATES

On May 24, 2004, the Affiliate entered into an agreement to purchase a 16-acre yard used for equipment storage and refurbishment of stacked rigs. The purchase price was approximately $1,038, which included the assumption of the outstanding indebtness of the seller in the amount of $773 and a note payable to the seller for $265. The Company made all of the principal and interest payments on the assumed debt for the six months ended June 30, 2005 and year ended December 31, 2004. Management fees of $300 and $360 were paid to two members for the six months ended June 30, 2005 and the year ended December 31, 2004, respectively.

NOTE  E  -  COMMITMENTS AND CONTINGENCIES

The Company leases certain office space on a month-to-month basis. Payments made during the six months ended June 30, 2005 and the year ended December 31, 2004 totaled approximately $3 and $6, respectively.

From time to time, claims and lawsuits, incidental to the ordinary course of business, may be 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 or results of operations.

NOTE  F  -  DISCONTINUED OPERATIONS

On January 3, 2005, the Company completed the sale of one of its rigs for total cash proceeds of $10,465. The assets sold consisted primarily of one rig, additional rig components and other equipment, which the Company sold to realize the increased value of its drilling rig. The assets qualify as a component of an entity to be classified as held for sale and reported in discontinued operations in accordance with Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”. The following is the revenue, net income and assets related to the rig included in the Company’s balance sheet at December 31, 2004 and the statements of operations for the six months ended June 30, 2005 and the year ended December 31, 2004:

	June 30 2005		December 2004
Revenue	$	31	$	2,111
Net (loss) income (including gain on disposal of $3,211 for June 30, 2005)	$	3,174	$	542
Assets held for sale
Trade accounts receivable, net			$	306
Property and equipment, net				6,320
			$	6,626

NOTE  G  -  SIGNIFICANT CUSTOMERS

For 2004, revenue from two customers was approximately 62% and 35% of total revenues and at December 31, 2004 all accounts receivable were from these two customers.

For the six months ended June 30, 2005, revenue from two customers was approximately 46% and 44% of total revenues and at June 30, 2005 all accounts receivable were from these two customers.

F-30

Strata Drilling, L.L.C. and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 and for the six months ended June 30, 2005 is unaudited)

(Amounts in thousands)

NOTE  H  -  SUBSEQUENT EVENTS

In July 2005, the Company’s members sold all of their membership interests in the Company and Affiliate to Bronco Drilling Company, L.L.C. (Bronco) an unrelated third party. The aggregate purchase price was $20,000, of which $13,000 was paid in cash and $7,000 was paid in the form of promissory notes issued to certain members. Included in the sale were two operating rigs, one rig that is currently being refurbished, related structures, equipment and components and a 16-acre yard in Oklahoma City, Oklahoma used for equipment storage and refurbishment of stacked rigs. The $7,000 outstanding principal of the promissory notes issued to certain members is automatically reduced by the amount of any costs and expenses Bronco pays in connection with the refurbishment of one of the rigs that was sold. The Company has agreed to complete the refurbishment of the rig on or before the end of 2005, subject to limited exceptions. Payment of the outstanding balance of the loan is due and payable upon completion of the refurbishment of this rig. The selling members have a security interest in this rig to collateralize the obligations under the notes. The outstanding principal balance on the notes does not bear any interest other than default interest in the event of a default.

F-31

Independent Auditors’ Report

The Shareholders and Board of Directors

Thomas Drilling Company

We have audited the accompanying balance sheets of Thomas Drilling Company as of December 31, 2004 and 2003, and the related statements of income and shareholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Thomas Drilling Company as of December 31, 2004 and 2003 and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Freemon, Shapard and Story

Wichita Falls, Texas

June 16, 2005

F-32

Thomas Drilling Company

BALANCE SHEETS

(Amounts in thousands except share amounts)

ASSETS	June 30, 2005			December 31, 2004			December 31, 2003
	(Unaudited)
CURRENT ASSETS
Cash	$	—		$	823		$	75
Receivables – Note C		5,480			3,579			3,448
Inventory – Drill bits		48			56			56
Deposits		241			159			74
Total current assets		5,769			4,617			3,653
PROPERTY AND EQUIPMENT – AT COST
Drilling rigs and related equipment		17,110			15,575			14,051
Transportation, office, and other equipment		382			299			164
		17,492			15,874			14,215
Less accumulated depreciation		(13,162	)		(12,725	)		(12,371	)
		4,330			3,149			1,844
OTHER ASSETS
Notes receivable – Note D		122			165			219
TOTAL ASSETS	$	10,221		$	7,931		$	5,716
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Bank overdraft	$	87		$	—		$	—
Accounts payable – Note E		1,947			1,131			760
Notes payable – Note G		2,987			2,622			2,603
		5,021			3,753			3,363
SHAREHOLDERS EQUITY
Capital stock, 250 Authorized,
114 issued and 109 outstanding
Additional paid-in capital		1,341			1,341			1,341
Retained earnings		4,033			3,011			1,186
Treasury stock		(174	)		(174	)		(174	)
Total shareholders’ equity		5,200			4,178			2,353
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	10,221		$	7,931		$	5,716

The accompanying notes are an integral part of these financial statements.

F-33

Thomas Drilling Company

STATEMENTS OF OPERATIONS AND SHAREHOLDERS’ EQUITY

(Amounts in thousands)

	Six Months Ended June 30, 2005			Year Ended December 31, 2004			Year Ended December 31, 2003
	(Unaudited)
REVENUES
Drilling rig income	$	14,186		$	18,943		$	13,471
Rental income		150			141			54
Total current assets		14,336			19,084			13,525
EXPENSES
Contract drilling		10,388			13,455			9,982
Depreciation and amortization		438			653			539
General and administrative		1,163			2,000			1,603
		11,989			16,108			12,124
Income (loss) from operations		2,347			2,976			1,401
OTHER INCOME (EXPENSE)
Interest expense		(33	)		(18	)		(21	)
Interest income		8			18			5
Gain on sale of assets					251			—
		(25	)		251			(16	)
NET INCOME (LOSS)		2,322			3,227			1,385
Shareholders’ equity at beginning of period		4,178			2,353			1,768
Distributions		(1,300	)		(1,402	)		(800	)
Shareholders’ equity at end of period	$	5,200		$	4,178		$	2,353

The accompanying notes are an integral part of these financial statements.

F-34

Thomas Drilling Company

STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Six Months Ended June 30, 2005			Year Ended December 31, 2004			Year Ended December 31, 2003
	(Unaudited)
Cash Flows From Operating Activities
Net income	$	2,322		$	3,227		$	1,385
Adjustments to reconcile net income (loss to net cash provided by (used for) operating activities
Depreciation and amortization		438			653			539
Changes in assets and liabilities
Receivables		(1,901	)		(131	)		(1,988	)
Inventory		8						(6	)
Deposits		(81	)		(85	)		25
Gain on sale of assets					(251	)		—
Accounts payable		816			390			272
Net cash provided by operating activities		1,602			3,803			227
Cash Flows From Investing Activities
Non-current note receivable collection		45			54			53
Purchase of equipment		(1,620	)		(1,960	)		(689	)
Sale of equipment					253			—
Accrued interest income		(2	)					—
Net cash used for investing activities		(1,577	)		(1,653	)		(636	)
Cash Flows From Financing Activities
Net accrued interest expense		15
Notes payable advances		350						250
Distributions to shareholders		(1,300	)		(1,402	)		(800	)
Net cash used for financing activities		(935	)		(1,402	)		(550	)
Net increase in cash and cash equivalents		(910	)		748			(959	)
Cash and cash equivalents, beginning of year		823			75			1,034
Cash and cash equivalents, end of year	$	(87	)	$	823		$	75
Supplemental disclosure of cash flow information
Cash paid during the year for interest	$	18		$	9		$	50

The accompanying notes are an integral part of these financial statements.

F-35

Thomas Drilling Company

NOTES TO FINANCIAL STATEMENTS

(Information as of June 30, 2005 unaudited)

(Amounts in thousands)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES

The Company is engaged primarily in drilling for oil, gas, and natural gas liquids. The Company provides contract drilling services to domestic exploration companies.

A summary of the significant accounting policies consistently applied in the preparation of the accompanying financial statements follows.

1.    Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market mutual funds to be cash equivalents.

The Company maintains its cash and cash equivalents in accounts and instruments which may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risks on cash and cash equivalents.

2.    Revenue Recognition

The Company earns contract drilling revenue under daywork and footage contracts.

The Company follows 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 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.

Revenue on daywork contracts are recognized based on the days completed at the day-rate each contract specifies. Mobilization revenues and costs for daywork contracts are deferred and recognized over the days of actual drilling.

The receivables from contract drilling in progress represents revenues in excess of amounts billed on contracts in progress.

Revenue arising from claims for amounts billed in excess of the contract price or for amounts not included in the original contract is recognized when billed less any allowance for uncollectibility. Revenue from such claims is recognized if it is probable that the claim will be realized, the costs for the additional services have been incurred, management believes there is a legal basis for the claim, and the amount can be reliably estimated.

3.    Accounts Receivable

Substantially all of the Company’s accounts receivable are due from companies in the oil and gas industry. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance

F-36

Thomas Drilling Company

NOTES TO FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 unaudited)

(Amounts in thousands)

NOTE  A  -  ORGANIZATION, NATURE OF BUSINESS AND SUMMARY OF ACCOUNTING POLICIES - CONTINUED

3.    Accounts Receivable - Continued

for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.

4.    Property and Equipment

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs are expensed currently. Assets are depreciated on a straight-line basis. The depreciable lives of drilling rigs and related equipment are five to ten years. Depreciation is not commenced until acquired rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished, or between periods of deployment.

The Company reviews long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the assets, the Company recognizes an impairment loss based upon fair value of the asset.

5.    Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosures. Accordingly, actual results could differ from those estimates.

6.    Income Taxes

The Company has elected to operate as an S-Corporation for income tax reporting. Income tax on net earnings are payable by the shareholders and are not reflected in the financial statements.

7.    Inventories

Inventories are valued at the lower of cost or market, based on the first-in first-out method.

NOTE  B  -  RELATED PARTY TRANSACTIONS

The Company conducts business with many related parties. Jath Oil Co., Mack Oil Co., and SouthOk Development Co., L.C., utilize the Company for drilling services. The family that has controlling interest of Thomas Drilling also owns control of these related companies.

F-37

Thomas Drilling Company

NOTES TO FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 unaudited)

(Amounts in thousands)

NOTE  C  -  ACCOUNTS RECEIVABLE

The Company has various receivable balances due from other entities including related parties at June 30, 2005 and December 31, 2004. A summary of the account is as follows:

	June 30, 2005		December 31, 2004
Mack Energy Company	$	2	$	523
M&M Supply Co.				6
Total receivables from related parties		2		529
Accounts receivable from unrelated parties		5,478		3,050
Accounts receivable	$	5,480	$	3,579

NOTE  D  -  NOTES RECEIVABLE

The Company has the following notes receivable balances due from related parties at June 30, 2005 and December 31, 2004:

	June 30, 2005		December 31, 2004
Unpaid balance of company-financed officer stock options exercised in prior years	$	122	$	165
Total notes receivable from related parties		122		165
Notes receivable from unrelated parties
Notes receivable	$	122	$	165

NOTE  E  -  ACCOUNTS PAYABLE

The Company has received various payments that are due to other entities including several related parties at June 30, 2005 and December 31, 2004. These transactions are recorded in the accounts payable account until they are disbursed to the interest owners. A summary of the account is as follows:

	June 30, 2005		December 31, 2004
Mack Energy Company	$	239	$	198
M & M Supply		210		116
Total amounts due related parties		449		314
Due to non-related parties		1,498		817
Accounts payable	$	1,947	$	1,131

NOTE  F  -  LINE OF CREDIT

Since December 27, 2002, the Company had a revolving line of credit for $5,000 available with BancFirst which was increased to $15,000 on November 26, 2004. This line of credit matures on November 26, 2005.

F-38

Thomas Drilling Company

NOTES TO FINANCIAL STATEMENTS – CONTINUED

(Information as of June 30, 2005 unaudited)

(Amounts in thousands)

NOTE  F  -  LINE OF CREDIT - CONTINUED

These funds are accessible either jointly or severally by this company and the following other companies; Mack Energy Co., Jath Oil Co., Oilco Gas Co., L.C., M & M Supply Co., Enerwest Trading Co, L.C., SouthOk Development Co., L.C., and Mack Oil Co. The Company may also request the issuance of a letter of credit from BancFirst, which will have an effective date from September 29, 2003. As of June 30, 2005 and December 31, 2004, the line of credit and letters of credit were unused.

NOTE  G  -  NOTES PAYABLE

The Company had related party notes payable to Mack Oil Company at June 30, 2005. The notes are due on demand. Interest accrues according to the current rate at BancFirst. The current rate at June 30, 2005 was 2.8%. A summary of the notes is as follows:

	June 30, 2005		December 31, 2004
Mack Oil	$	2,225	$	1,875
Mack Oil		729		729
Interest Payable		33		18
Notes payable	$	2,987	$	2,622

NOTE  H  -  SUBSEQUENT EVENTS

On September 2, 2005, the Company entered into an asset purchase agreement with Bronco Drilling Company, Inc. effective as of August 1, 2005. Bronco Drilling Company agreed to purchase the assets from the Company for $68,000 and to assume the contractual service liabilities of the Company. The companies agreed to close the sale on or before October 15, 2005.

The Company converted from a C Corporation to an S Corporation effective January 1, 2001. An S Corporation may be subject to tax on subsequent sales of property or liquidation at the corporate level if there were built-in gains at the time of conversion. Management believes that there were no built-in gains at the time of conversion to an S Corporation.

F-39

3,500,000 Shares

BRONCO DRILLING COMPANY, INC.

Common Stock

P R O S P E C T U S

Joint Book-Running Managers

Johnson Rice & Company L.L.C. Jefferies & Company, Inc.

Friedman Billings Ramsey Raymond James

October 28, 2005