Bronco Drilling 10-K 2008 FY Annual report

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2007

or

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

For the transition period from                      to                     

Commission file number 000-51471

Bronco Drilling Company, Inc.

(Exact name of registrant as specified in its charter)

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

(405) 242-4444

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class	Name of Each Exchange on Which Registered
Common Stock $0.01 Par Value per Share	The Nasdaq Stock Market LLC
Securities Registered Pursuant to Section 12(g) of the Act:
None

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

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

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

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

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

Large Accelerated Filer  ¨ Accelerated Filer  x     Non-Accelerated Filer  ¨     Smaller Reporting Company  ¨    

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of the most recently completed second fiscal quarter (June 30, 2007), based on the price at which the common equity was last sold on such date: $426,796,695.

As of February 29, 2008, 26,269,961 shares of common stock were outstanding.

Documents Incorporated By Reference

Certain information called for by Part III is incorporated by reference to certain sections of the Proxy Statement for the 2008 Annual Meeting of our stockholders which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 2007.

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BRONCO DRILLING COMPANY, INC.

INDEX

Item No.		Form 10-K Report Page
	Cautionary Note Regarding Forward-Looking Statements	4
PART I
1.	Business	4
1A.	Risk Factors	9
1B.	Unresolved Staff Comments	14
2.	Properties	15
3.	Legal Proceedings	15
4.	Submission of Matters to a Vote of Security Holders	15
PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
6.	Selected Financial Data	17
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
7A.	Quantitative and Qualitative Disclosures About Market Risk	23
8.	Financial Statements and Supplementary Data	23
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	23
9A.	Controls and Procedures	23
9B.	Other Information	26
PART III
10.	Directors and Executive Officers and Corporate Governance	26
11.	Executive Compensation	26
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	26
13.	Certain Relationships and Related Transactions, and Director Independence	26
14.	Principal Accounting Fees and Services	26
PART IV
15.	Exhibits and Financial Statement Schedules	26

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Cautionary Note Regarding Forward-Looking Statements

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

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

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

PART I

Item 1. Business

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

Our Company

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

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

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

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

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

Our Acquisitions

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

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

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

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

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

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

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In October 2005, we purchased 12 land drilling rigs from Eagle Drilling, L.L.C., or Eagle Drilling, for approximately $50.0 million plus approximately $500,000 of related transaction costs, and 13 land drilling rigs from Thomas Drilling Co. for approximately $68.0 million plus approximately $2.6 million of related transaction costs.

In January 2006, we purchased six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling L.L.C., or Big A, for $16.3 million in cash and 72,571 shares of our common stock.

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

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

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

 In a separate transaction, we sold to Challenger four additional drilling rigs and ancillary equipment for $13.4 million, payable in installments over thirty-six months.  The general specifications of the sold rigs are as follows:

		Approximate
		Drilling
Rig	Design	Depth (ft)	Type	Horsepower
91	Ideco H-35	8,000	Mechanical	450
92	Weiss 45	8,000	Mechanical	500
94	Unit U-15	9,000	Mechanical	650
95	Emsco GB800	12,000	Mechanical	1,000

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 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

As of February 29, 2008, our drilling rig fleet consisted of 56 drilling rigs, of which 45 were marketed, and 11 were held in inventory. The following table sets forth information regarding utilization for our fleet of marketed drilling rigs:

	For The Year Ended December 31,
	2007			2006			2005
Average number of marketed rigs		51			45			17
Average utilization rate		76	%		93	%		95	%

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 The following table sets forth information regarding our drilling fleet as of February 29, 2008:

		Approximate
		Drilling
Rig	Design	Depth (ft)	Type	Horsepower
Working Rigs
21	National 1320	20,000	Electric	2,000
17	Skytop Brewster NE-95	20,000	Electric	1,700
12	Gardner Denver 1100E	18,000	Electric	1,500
25	Mid Continent U-914	18,000	Electric	1,500
27	Mid Continent U-914	18,000	Electric	1,500
29	Mid Continent U-914	18,000	Electric	1,500
16	Oilwell840E	18,000	Electric	1,400
20	Mid Continent U-914-EC	18,000	Electric	1,400
15	Mid Continent U-712-EA	16,000	Electric	1,200
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
26	Ideco 1200E	14,000	Electric	1,200
28	Ideco 1200E	14,000	Electric	1,200
56	BDW 800 MI	16,500	Mechanical	1,100
57	Continental Emsco D-3	15,000	Mechanical	1,100
11	Gardner Denver 800E	15,000	Electric	1,000
10	Gardner Denver 800E	15,000	Electric	1,000
43	Gardner Denver 800	15,000	Mechanical	1,000
8	National 80-UE	15,000	Electric	1,000
23	Continental Emsco D-3	15,000	Electric	1,000
22	Continental Emsco D-3	15,000	Electric	1,000
62	Brewster N-75	12,000	Mechanical	1,000
37	Citation A-800	14,000	Electric	1,000
55	Oilwell 660	12,000	Mechanical	1,000
4	Skytop Brewster N46	14,000	Mechanical	950
41	Skytop-Brester N-46	13,500	Mechanical	950
60	Skytop Brewster N46	14,000	Mechanical	850
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
59	Skytop Brewster N46	13,000	Mechanical	850
97	Mid Con U-15	12000	Mechanical	850
58	National N55	12,000	Mechanical	800
72	Skytop Brewster N42	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
70	Schaeffer 6000S	6,000	Mechanical	450
2	Cardwell L-350	6,000	Mechanical	400
Rigs In Inventory
24	Skytop Brewster N-12	25,000	Electric	2,000
73	Gardner Denver 1500	18,000	Mechanical	2,000
74	National 1320	20,000	Mechanical	2,000
36	Continental Emsco C-1	18,000	Electric	1,500
31	National 80 UE	14,000	Electric	1,000
30	Mid Continent U-914	18,000	Electric	1,500
32	Mid Continent U-914	18,000	Electric	1,500
33	Continental Emsco D-3	15,000	Electric	1,000
35	Ideco 7-11	12,000	Electric	1,000
34	Ideco 900E	12,000	Electric	900
61	National 50-A	11,500	Mechanical	850
Excess Rig Inventory
79	Oilwell 500	10,000	Mechanical	500
80	Mac 400	6,000	Mechanical	400
81	Mid Continent U34B	6,000	Mechanical	400
82	Ideco H-35 Hydrair	6,000	Mechanical	400

Working Drilling Rigs

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

Drilling Rigs In Inventory

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

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Other Equipment

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

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

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

Drilling Contracts

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

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

The following table presents, by type of contract, information about the total number of wells we completed for our customers during the years ended December 31, 2007, 2006 and 2005.

	Years Ended December 31,
	2007		2006		2005
Daywork Contracts		430		449		148
Footage Contracts		3		1		5
Turnkey Contracts		-		-		-
Total		433		450		153

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

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

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

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

Customers and Marketing

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

Customer	Total Contract Drilling Revenue Percentage
2007
Antero Resources	11%
Chesapeake Energy Corporation	8%
Comstock Oil and Gas	7%
XTO Energy	6%
Pablo Energy II, LLC	5%
2006
Chesapeake Energy Corporation	7%
Comstock Oil and Gas	5%
2005
New Dominion LLC	10%
Chesapeake Energy Corporation	9%
Carl E. Gungoll Exploration LLC	6%
Western Oil and Gas Development Co	6%
XTO Energy	5%

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

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.

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Competition

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

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

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

• the mobility and efficiency of the rigs;

• the quality of service and experience of the rig crews;

• the offering of ancillary services; and

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

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

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

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

• better withstand industry downturns;

• compete more effectively on the basis of price and technology;

• better retain skilled rig personnel; and

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

Raw Materials

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

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

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.  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. Our umbrella liability insurance coverage is $25.0 million per occurrence and in the aggregate, with a deductible of $10,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

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Employees

As of February 29, 2008, we had 1,551 employees. Approximately 195 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees, the majority of whom operate or maintain our drilling rigs, workover 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.

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.

Governmental Regulation

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

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

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

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

Available Information

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

For more information regarding the merger, please refer to the joint proxy statement/prospectus of Allis-Chalmers and Bronco that is included in the registration statement on Form S-4 (Registration No. 333-149326) filed by Allis-Chalmers with the SEC on February 20, 2008, and other relevant materials that may be filed by us or Allis-Chalmers with the SEC, including any amendments to such registration statement.

Item 1A. Risk Factors

Risks Relating to the Oil and Natural Gas Industry

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

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

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

• the discovery rate of new oil and natural gas reserves;

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

• available pipeline and other oil and natural gas transportation capacity;

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

• actions by OPEC, the Organization of Petroleum Exporting Countries;

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

• economic conditions in the United States and elsewhere;

• governmental regulations, both domestic and foreign;

• domestic and foreign tax policy;

• weather conditions in the United States and elsewhere;

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

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

• the overall supply and demand for oil and natural gas.

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

• our revenues, cash flows and profitability;

• our ability to maintain or increase our borrowing capacity;

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

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

• the fair market value of our rig fleet.

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, could be used to assemble 22 drilling rigs. In July 2005, we acquired three additional rigs and related inventory, equipment, components and a rig yard. On October 3, 2005, we acquired five operating rigs, seven inventoried rigs and rig equipment and parts. On October 14, 2005, we acquired nine operating rigs, two rigs undergoing refurbishment, two inventoried rigs and rig equipment and parts. On January 18, 2006, we acquired six operating land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment. On January 9, 2007, we acquired 31 workover rigs through our acquisition of Eagle Well.  Acquisitions, including those described above, involve numerous risks, including:

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

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

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

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

• risk of entering markets in which we have limited prior experience; and

• an increase in our expenses and working capital requirements.

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

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

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

 An 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. There has been a substantial increase in the supply of land rigs in the United States over the past two years which has led to a broad decline in dayrates and utilization industry wide.

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

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

Our investment in Challenger is illiquid and may never generate cash.

 There currently is no readily available market that would facilitate the disposal of our 25% equity investment in Challenger.  Furthermore, based on our minority equity position in Challenger, We will not directly receive cash proceeds resulting from the operations of Challenger.  We can not assure that the investment will ever yield cash proceeds, absent a liquidating event or the increase in our equity position above a threshold that would constitute control.

Our minority equity investment in Challenger limits our control of the company.

 Bronco representatives hold two of the eight total board seats on the Challenger board of directors. We also have various rights as a shareholder which include:

• preemptive rights;

• transfer rights;

• tag-along rights;

• drag-along rights;

• registration rights; and

• certain voting rights.

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

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

Challenger is an Isle of Man company with its principal operations in Libya.  Risks associated with Challenger’s contract land drilling and workover operations include:

• terrorist acts, war and civil disturbances;

• expropriation or nationalization of assets;

• renegotiation or nullification of existing contracts;

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

• assaults on property or personnel;

• changing political conditions;

• foreign and domestic monetary policies; and

• travel limitations or operational problems caused by public health threats.

 We anticipate that we will account for our investment in Challenger using the equity method of accounting, and that our balance sheet and statement of operations will contain captions showing the investment in Challenger based on fair market value of the contributed assets and the income or loss generated by our 25% ownership in Challenger.  The manifestation of any of the risks enumerated above could adversely affect the financial results we report relating to our ownership interest in Challenger.

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 quality of equipment 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 competitors with greater resources that may make it more difficult for us to compete, which can reduce our dayrates and utilization rates.

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

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

For the years ended December 31, 2007 and 2006, 0% of our total revenues were derived from footage contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. The risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. The occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a negative impact on our profitability. Similar to our footage contracts, under turnkey contacts drilling companies assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. Although we historically have not entered into turnkey contracts, if we were to enter into a turnkey contract or acquire such a contract in connection with future acquisitions, the occurrence of uninsured or under-insured losses or operating cost overruns on such a job could negatively impact our profitability.

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

Our operations are subject to the many hazards inherent in the contract land drilling 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.

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

• suspension of drilling operations;

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

• personal injury and loss of life;

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

• environmental damage.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases 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 “daywork” indemnification language that transfers responsibility for down hole exposures such as blowout and fire to the operator, leaving us responsible only for damage to our rig and our personnel. If we do not adequately insure the risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled, our profitability and other results of operation and our financial condition could be adversely affected in the event we encounter blowouts or other significant operating difficulties while drilling at deeper depths. If our primary focus shifts from drilling for customers in search of natural gas to drilling for customers in search of oil, a portion of our rig fleet could 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 that may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids, contaminated water or other substances or for noncompliance with other aspects of applicable laws and regulations. Historically, we have not been required to obtain environmental or other permits prior to drilling a well. Instead, the operator of the oil and gas property has been obligated to obtain the necessary permits at its own expense.

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

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

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, or Zachary Graves, our Chief Financial Officer, could disrupt our operations resulting in a loss of revenues. Although we have employment agreements with a small number of our employees, as a practical matter such employment agreements will not assure the retention of those employees. In addition, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

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

Our success depends in large part on our ability to attract and retain skilled and qualified personnel. Our inability to hire, train and retain a sufficient number of qualified employees could impair our ability to manage and maintain our business. We require skilled employees who can perform physically demanding work. Shortages of qualified personnel 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.

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

The materials and supplies we use in our operations include fuels to operate our drilling equipment, drilling mud, drill pipe, drill collars, drill bits and cement. Shortages in drilling equipment and supplies could limit our drilling operations and jeopardize our relations with customers. We do not rely on a single source of supply for any of these items. From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit our operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our drilling rigs, which could negatively impact our revenues and profitability.

We have incurred and will continue to 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.  These rules and regulations could increase our legal and financial compliance costs and could make some activities more time-consuming and costly. These new rules and regulations could 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.

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

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

• our quarterly operating results;

• changes in our earnings estimates;

• additions or departures of key personnel;

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

• changes in general market or economic conditions; and

• announcements of legislative or regulatory change.

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

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

If a large number of shares of our common stock is sold in the open market, the trading price of our common stock could decrease. As of December 31, 2007, we had an aggregate of 71,491,670 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.

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

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

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

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

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

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

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

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

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

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

Risk Factors Relating to the Merger

The number of shares of Allis-Chalmers common stock that holders of Bronco common stock will receive is not fixed because the stock component of the merger consideration is based on the average of the closing sale prices of Allis-Chalmers common stock during a ten-day period ending two trading days before the merger closes.

 The number of shares of Allis-Chalmers common stock to be issued in the merger will be based on the average of the closing sale prices of Allis-Chalmers common stock on the NYSE Composite Transactions Tape (as reported by The Wall Street Journal (Northeast edition), or, if not reported thereby, as reported by any other authoritative source) for the ten consecutive trading days ending with the second complete trading day prior to the closing date (not including the closing date), or the Allis-Chalmers Common Stock Value. Although the aggregate value of the stock consideration in the merger is fixed at $157.8 million, the number of shares of Allis-Chalmers common stock to be issued to our stockholders will depend on the Allis- Chalmers Common Stock Value. Therefore, our stockholders cannot be sure of the number of shares that they will receive, and Allis-Chalmers stockholders cannot be sure of the number of shares of Allis-Chalmers common stock that will be issued to the our stockholders. In addition, because the exchange ratio will be determined using a period that ends two trading days prior to the closing date, the number of shares of Allis-Chalmers common stock to be issued will likely be different than it would be if the price on the closing date were to be used.

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 For more information regarding the merger, please refer to the joint proxy statement/prospectus of Allis-Chalmers and Bronco that is included in the registration statement on Form S-4 (Registration No. 333-149326) filed by Allis-Chalmers with the SEC on February 20, 2008, and other relevant materials that may be filed by us or Allis-Chalmers with the SEC, including any amendments to such registration statement.

The price of Allis-Chalmers common stock will continue to fluctuate after the merger and may be affected by factors that are different than the separate factors that currently affect the prices of Allis-Chalmers common stock and Bronco common stock.

 Holders of our common stock will receive Allis-Chalmers common stock in the merger. Allis-Chalmers’ results of operations, as well as the price of Allis-Chalmers common stock following the merger, may be affected by factors that are different than those factors currently affecting Allis-Chalmers’ or our results of operations and the prices of Allis-Chalmers common stock and our common stock.

Any delay in completing the merger and integrating the businesses may reduce the benefits expected to be obtained from the merger.

 In addition to obtaining the required regulatory clearances and approvals, the merger is subject to a number of other conditions beyond the control of Bronco and Allis-Chalmers that may prevent, delay or otherwise materially adversely affect its completion.  Allis-Chalmers and Bronco cannot predict whether or when the conditions to closing will be satisfied. Any delay in completing the merger and integrating the businesses may reduce the benefits that Allis-Chalmers and Bronco expect to achieve in the merger.

Failure to complete the announced merger with Allis-Chalmers could negatively affect the stock price and the future business and financial results of Bronco.

 There can be no assurance that the merger agreement will be adopted by Bronco stockholders, that the issuance of the shares of Allis-Chalmers common stock will be approved by Allis-Chalmers stockholders or that the other conditions to the completion of the merger will be satisfied. In addition, Bronco has the right to terminate the merger agreement and pursue alternative transactions under certain conditions. If the merger is not completed, Bronco’s stockholders will not receive any expected benefits of the merger and will be subject to risks and/or liabilities, including the following:

• failure to complete the merger might be followed by a decline in the market price of Bronco common stock;

• Bronco must pay Allis-Chalmers a termination fee and expense reimbursements of up to $10.0 million if the merger agreement is terminated under specified circumstances;

• some costs relating to the merger (such as legal and accounting fees) are payable by Bronco regardless of whether the merger is completed; and

• the proposed merger may disrupt our business and distract our management and employees from day-to-day operations, because work related to the merger (including integration planning) requires substantial time and resources, which could otherwise have been devoted to other business opportunities for the benefit of Bronco.

 If the merger is not completed, these risks and liabilities may materially adversely affect Bronco’s business, financial results, financial condition and stock price.

There are three separate lawsuits seeking to delay or prevent the consummation of the merger.

Three of our stockholders have separately filed complaints seeking class action status relating to our proposed merger with Allis-Chalmers.  Two actions were filed in the District Court of Oklahoma County in the State of Oklahoma on January 29, 2008 and February 28, 2008, respectively.  The defendants named in the first Oklahoma complaint are Bronco, the Bronco board of directors, Allis-Chalmers and Merger Sub while the defendants named in the second Oklahoma complaint are Bronco, the Bronco board of directors and Allis-Chalmers.  The third action was filed in the Court of Chancery in the State of Delaware on January 29, 2008.  The defendants named in the Delaware complaint are Bronco, the Bronco board of directors and Allis-Chalmers.  The plaintiff in the first Oklahoma complaint has filed a motion for expedited discovery.  The complaints generally allege that the merger consideration is inadequate and that the Bronco board of directors has breached its fiduciary duties.  The second Oklahoma complaint also alleges that the joint proxy statement/prospectus included as part of Allis-Chalmers’ registration statement on Form S-4 filed with the SEC on February 20, 2008 contains materially incomplete and misleading information. The actions generally seek to enjoin the merger, cause the Bronco board of directors to undertake an auction for Bronco or otherwise take action to maximize stockholder value, award monetary damages to the stockholders of Bronco and, in the case of the two Oklahoma complaints, rescind the transaction (to the extent that it is consummated).  The claims against Allis-Chalmers seek monetary damages.  Answers to the complaints are not yet due, although a motion to dismiss the first Oklahoma proceeding has been filed by Bronco.  Bronco intends to vigorously defend these actions.  As of this time, no order has been issued in either proceeding that would preclude the consummation of the merger.  Each of Allis-Chalmers and Bronco has the right to terminate the merger agreement in the event a court enjoins the consummation of the merger.

A group that beneficially owns a significant amount of our outstanding voting stock has announced its intention to oppose the merger.

 On January 25, 2008, we received a letter from Third Avenue Management LLC, or Third Avenue, stating that it was opposed to the merger. The letter was also filed with the SEC by Third Avenue on an amendment to its Schedule 13D on January 25, 2008. According to its filing, Third Avenue, on behalf of its investment advisory clients, beneficially owned 5,512,116 shares of our common stock, representing 21.18% of our outstanding common stock as of January 25, 2008.

The rights of Bronco stockholders who become Allis-Chalmers stockholders in the merger will be governed by Allis-Chalmers’ certificate of incorporation and bylaws.

 Bronco stockholders who receive shares of Allis-Chalmers common stock in the merger will become Allis-Chalmers stockholders. Although their rights as stockholders will remain subject to the Delaware General Corporation Law, they will be governed by Allis-Chalmers’ certificate of incorporation and bylaws, rather than Bronco’s certificate of incorporation and bylaws. As a result, there will be material differences between the current rights of Bronco stockholders, as compared to the rights they will have as Allis-Chalmers stockholders.

The directors and executive officers of Bronco may have personal interests that differ from yours and that may motivate them to support or approve the merger.

 The directors of Bronco who have recommended the merger to Bronco stockholders and the executive officers of Bronco who provided information to the Bronco board of directors relating to the merger have employment, indemnification and/or severance benefit arrangements, will benefit from the acceleration of restricted stock awards, if any, and have rights to ongoing indemnification and director and officer insurance.  Any of these arrangements or benefits may cause these individuals to have interests that may differ from yours. The benefits that would result from the merger may have influenced these directors in approving the merger and these executive officers in supporting the merger. You should consider these interests when you consider the recommendation of the Bronco board of directors that you vote for the adoption of the merger agreement. As a result of these interests, these directors and executive officers may be more likely to support the merger than they would if they did not have these interests.

The merger agreement limits Bronco’s ability to pursue an alternative to the merger.

 The merger agreement prohibits Bronco from soliciting alternative transactions.  Additionally, under the merger agreement, before (i) the board of directors of Bronco changes its recommendation regarding the merger as a result of its receipt of an unsolicited acquisition proposal, (ii) the board of directors of Bronco recommends an alternative transaction or (iii) Bronco enters into an alternative transaction, Bronco must allow Allis-Chalmers a four-business day period to make a revised proposal. These provisions limit Bronco’s ability to pursue offers from third parties that could result in greater value to its stockholders.  Bronco’s obligation to pay a termination fee may also discourage a third party from pursuing an alternative transaction proposal. Under the merger agreement, Bronco may be required to pay to Allis-Chalmers a termination fee of $10.0 million or out-of-pocket expenses of up to $5.0 million if the merger agreement is terminated under specified circumstances. If a termination fee is payable, the payment of this fee could have material and adverse consequences on Bronco’s financial condition.

Item 1B. Unresolved Staff Comments

None.

-14-

Item 2. Property

Our corporate headquarters is located at 16217 North May Avenue, Edmond, Oklahoma in an office building we purchased on January 2, 2007.  The approximately 18,100 square foot building was purchased for a total purchase price of $3.0 million, less an amount equal to one-half of the principal reduction on the seller’s loan secured by the property between the effective date of the purchase agreement and the closing. We paid $1.4 million in cash and assumed existing debt of approximately $1.6 million. Prior to closing, we subleased a total of 9,050 square feet of the building from its tenants until the closing date for a monthly rental of $8,341.

We own or lease from third parties the following properties:

• an approximately 6,205 square foot building used for office space in Duncan, Oklahoma;

• an approximately 841 square foot building used for office space in Craig, Colorado;

• an approximately 2,300 square foot building used for office space in Craig, Colorado;

• an approximately 465 square foot building used for office space in Shattuck, Oklahoma;

• a 13 acre yard used for equipment storage and the refurbishment of our inventoried 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;

• Two 16 acre yards used for equipment storage and the refurbishment of our inventoried rigs in Oklahoma City, Oklahoma;

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

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

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

• a 4 acre yard which includes a machine shop used for drilling rig refurbishment, repair and maintenance in Liberal, Kansas;

• a 3 acre yard which includes a machine shop used for drilling rig refurbishment, repair and maintenance in Raton, New Mexico;

• a 10 acre yard which includes a machine shop used for drilling rig refurbishment, repair and maintenance in Snyder, Texas;

• a 1 acre yard which includes a machine shop used for drilling rig refurbishment, repair and maintenance in Ulysses, Kansas;

• a 4 acre yard which includes a machine shop used for drilling rig refurbishment, repair and maintenance in El Reno, Oklahoma;

• a 4 acre yard which includes a repair shop used for well service equipment, storage and workover rig repair in Guymon, Oklahoma;

• a 2 acre yard which includes a repair shop used for well service equipment, storage and workover rig repair in Craig, Colorado;

• a 2 acre yard which includes a repair shop used for well service equipment, storage and workover rig repair in Cushing, Oklahoma;

• a 1 acre yard which includes a repair shop used for well service equipment, storage and workover rig repair in Midland, Texas;

• a 4 acre yard which includes a repair shop used for well service equipment, storage and workover rig repair in Healdton, Oklahoma; and

• a 4 acre yard which includes a repair shop used for well service equipment, storage and workover rig repair in Levelland, Texas.

Item 3. Legal Proceedings

Three of our stockholders have separately filed complaints seeking class action status relating to our proposed merger with Allis-Chalmers.  Two actions were filed in the District Court of Oklahoma County in the State of Oklahoma on January 29, 2008 and February 28, 2008, respectively.  The defendants named in the first Oklahoma complaint are Bronco, the Bronco board of directors, Allis-Chalmers and Merger Sub while the defendants named in the second Oklahoma complaint are Bronco, the Bronco board of directors and Allis-Chalmers.  The third action was filed in the Court of Chancery in the State of Delaware on January 29, 2008.  The defendants named in the Delaware complaint are Bronco, the Bronco board of directors and Allis-Chalmers.  The plaintiff in the first Oklahoma complaint has filed a motion for expedited discovery.  The complaints generally allege that the merger consideration is inadequate and that the Bronco board of directors has breached its fiduciary duties.  The second Oklahoma complaint also alleges that the joint proxy statement/prospectus included as part of Allis-Chalmers’ registration statement on Form S-4 filed with the SEC on February 20, 2008 contains materially incomplete and misleading information. The actions generally seek to enjoin the merger, cause the Bronco board of directors to undertake an auction for Bronco or otherwise take action to maximize stockholder value, award monetary damages to the stockholders of Bronco and, in the case of the two Oklahoma complaints, rescind the transaction (to the extent that it is consummated).  The claims against Allis-Chalmers seek monetary damages.  Answers to the complaints are not yet due, although a motion to dismiss the first Oklahoma proceeding has been filed by Bronco.  Bronco intends to vigorously defend these actions.  As of this time, no order has been issued in either proceeding that would preclude the consummation of the merger.  Each of Allis-Chalmers and Bronco has the right to terminate the merger agreement in the event a court enjoins the consummation of the merger.

In addition to the merger litigation, 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, 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.

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

 We did not submit any matter to a vote of our stockholders during the fourth quarter of 2007.

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PART II

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

Market Information

Our common stock has been quoted on The Nasdaq Global Market (formerly 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 Global Market.

	High		Low
Year Ending December 31, 2005:
Third Quarter (since August 16, 2005)	$	30.00	$	18.00
Fourth Quarter	$	29.10	$	20.97
Year Ending December 31, 2006:
First Quarter	$	32.00	$	22.50
Second Quarter	$	29.57	$	17.50
Third Quarter	$	21.41	$	16.01
Fourth Quarter	$	19.69	$	15.25
Year Ending December 31, 2007:
First Quarter	$	17.20	$	13.53
Second Quarter	$	19.21	$	15.37
Third Quarter	$	16.67	$	13.58
Fourth Quarter	$	16.04	$	13.10
Year Ending December 31, 2008:
First Quarter (through February 29, 2008)	$	16.15	$	11.21

 On February 29, 2008, the last reported sale price of our common stock on The Nasdaq Global Market was $15.81 and we had approximately 11,000 beneficial holders of our common stock.

Dividend Policy

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

Equity Compensation Plan Information

The following table provides information as of December 31, 2007 with respect to shares of our common stock that may be issued under on our equity compensation plan:

			Number of securities
			remaining available for
	Number of securities to be	Weighted-average	future issuance under equity
	issued upon exercise of	exercise price per share	compensation plans
	outstanding options,	of outstanding options,	(excluding securities
Plan category	warrants and rights	warrants and rights	reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved
by security holders	20	$                                26.14	1,904
Equity compensation plans not approved
by security holders	-	-	-
	20	$                                26.14	1,904

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Item 6. Selected Financial Data.

The following table sets forth our selected historical financial data as of and for each of the years indicated. We derived the selected historical financial data as of and for each of the years ended 2007, 2006, 2005, 2004 and 2003 from our historical audited consolidated financial statements. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated historical financial statements and related notes included elsewhere in this Form 10-K.

	Years Ended December 31,
	(in thousands, except per share amounts)
	2007			2006			2005		2004		2003
Consolidated Statements of Operations
Information:
Contract drilling revenues		$	276,088		$	285,828	$	77,885	$	21,873	$	12,533
Well service			22,864			-		-		-		-
Costs and expenses:
Contract drilling			153,797			139,607		44,695		18,670		10,537
Well service			14,299			-		-		-		-
Depreciation and amortization			44,241			30,335		9,143		3,695		1,985
General and administrative			22,690			15,709		9,395		1,714		1,226
Total operating costs and expenses			235,027			185,651		63,233		24,079		13,748
Income (loss) from operations			63,925			100,177		14,652		(2,206)		(1,215)
Other income (expense):
Interest expense			(4,762)			(1,736)		(1,415)		(285)		(21)
Loss from early extinguishment of debt			-			(1,000)		(2,062)		-		-
Interest income			1,239			164		432		10		3
Other income			294			284		53		-		-
Total other income (expense)			(3,229)			(2,288)		(2,992)		(275)		(18)
Income (loss) before income taxes			60,696			97,889		11,660		(2,481)		(1,233)
Income tax expense			23,104			38,056		6,529		285		317
Net income (loss)		$	37,592		$	59,833	$	5,131	$	(2,766)	$	(1,550)
Income per common share-Basic		$	1.45		$	2.43	$	0.32
Income per common share-Diluted		$	1.44		$	2.43	$	0.31
Weighted average number of shares outstanding-Basic			25,996			24,585		16,259
Weighted average number of shares outstanding-Diluted			26,101			24,623		16,306
Pro Forma C Corporation Data (Unaudited): (1)
Historical income (loss)
before income taxes							$	11,660	$	(2,481)	$	(1,233)
Pro forma provision (benefit) for income
taxes								4,396		(935)		(465)
Pro forma income (loss)							$	7,264	$	(1,546)	$	(768)
Pro forma income (loss) per common share basic and diluted							$	0.45	$	(0.12)	$	(0.06)
Weighted average pro forma shares outstanding-Basic								16,259		13,360		13,360
Weighted average pro forma shares outstanding-Diluted								16,306		13,360		13,360
Other Financial Data (Unaudited):
Calculation of EBITDA (2):
Net income (loss)		$	37,592		$	59,833	$	5,131	$	(2,766)	$	(1,550)
Interest expense			4,762			1,736		1,415		285		21
Income tax expense			23,104			38,056		6,529		285		317
Depreciation and amortization			44,241			30,335		9,143		3,695		1,985
EBITDA (2)		$	109,699		$	129,960	$	22,218	$	1,499	$	773
Consolidated Cash Flow Information:
Net cash provided by (used in):
Operating activities		$	82,607		$	93,053	$	3,318	$	2,364	$	(1,914)
Investing activities  (3)			(79,984)			(143,199)		(190,326)		(19,511)		(4,846)
Financing activities			(7,510)			43,715		202,908		16,623		7,798
			As of December 31,
			2007			2006		2005		2004		2003
Consolidated Balance Sheet Information:
Total current assets		$	72,019		$	73,372	$	53,953	$	8,118	$	5,682
Total assets			568,605			482,488		330,520		90,143		71,920
Total debt			68,118			64,727		51,825		18,100		4,300
Total liabilities			172,176			142,503		91,184		39,340		21,218
Total stockholders'/members' equity			396,429			339,985		239,336		50,803		50,702

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(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. 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-GAAP financial measure equal to net income (loss), the most directly comparable Generally Accepted Accounting Principles, or GAAP, financial measure, plus interest expense, income tax expense, and depreciation and amortization. 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 Form 10-K 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.

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

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

Overview

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

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

For the years ended December 31, 2007, 2006 and 2005, our drilling rig utilization rates, revenue days and average number of operating rigs were as follows:

	Year Ended December 31,
	2007	2006	2005
Average number of operating rigs	51	45	17
Revenue days	14,245	15,202	5,781
Utilization Rates	76%	93%	95%

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

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

Market Conditions in Our Industry

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

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

	At December 31,
	2007		2006		2005
Crude oil (Bbl)	$	95.98	$	61.05	$	61.04
Natural gas (Mmbtu)	$	7.48	$	6.30	$	11.23
U.S. Land Rig Count		1,719		1,626		1,391

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

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

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Critical Accounting Policies and Estimates

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Year in Review Highlights

 The following are recent highlights that have impacted our results of operations for the year ended December 31, 2007:

• On January 2, 2007, we purchased an approximately 18,100 square foot building located in Oklahoma City, Oklahoma for a total purchase price of $3.0 million, less an amount equal to one-half of the principal reduction on the seller’s loan secured by the property between the effective date of the purchase agreement and the closing. We paid $1.4 million in cash and assumed existing debt of approximately $1.6 million. Prior to closing, we subleased a total of 9,050 square feet of the building from its tenants until the closing date for a monthly rental of $8,341.

• On January 9, 2007, we completed the acquisition of 31 workover rigs, 24 of which were operating, from Eagle Well and related subsidiaries for $2.6 million in cash, 1,070,390 shares of our common stock and the assumption of debt of $6.5 million, liabilities of $678,000 and additional deferred income taxes of $7.2 million.  We subsequently deployed the remaining rigs and added 28 new rigs to bring our total fleet to 59 workover rigs.

Recent Developments

 On January 4, 2008, Bronco MENA Investments LLC, one of our wholly-owned subsidiaries, closed a transaction with Challenger, a company organized under the laws of the Isle of Man, and certain of its affiliates to acquire a 25% equity interest in Challenger in exchange for six drilling rigs and $5.0 million in cash.  Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with its principal operations in Libya.  In a separate transaction we sold to Challenger four drilling rigs and ancillary equipment for $13.4 million, payable in installments. The transactions were completed on January 4, 2008.  Prior to these transactions, Challenger owned a fleet of 23 rigs.

 On January 23, 2008, we entered into an agreement and plan of merger with Allis-Chalmers and Merger Sub, providing for the acquisition of Bronco by Allis-Chalmers.

 Under the terms of the merger agreement, which was approved by the respective boards of directors of each of the Company, Allis-Chalmers and Merger Sub, Merger Sub will merge with and into the Company, with the Company surviving as a wholly owned subsidiary of Allis-Chalmers.  The merger agreement provides that, at the effective time of the merger, Bronco stockholders will receive merger consideration with an aggregate value of approximately $437.8 million, comprised of (a) an aggregate of $280.0 million in cash and (b) shares of Allis-Chalmers common stock having an aggregate value of approximately $157.8 million. The number of shares issued as merger consideration will be based on the average closing price of Allis-Chalmers common stock for a ten trading day period ending two days prior to the closing.  Allis Chalmers will also assume all of the outstanding debt of Bronco, which totaled $68.1 million at December 31, 2007.

 For more information regarding the merger, please refer to the joint proxy statement/prospectus of Allis-Chalmers and Bronco that is included in the registration statement on Form S-4 (Registration No. 333-149326) filed by Allis-Chalmers with the SEC on February 20, 2008, and other relevant materials that may be filed by us or Allis-Chalmers with the SEC, including any amendments to such registration statement.

Results of Operations

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

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

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

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

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

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

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

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

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

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

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

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

Contract Drilling Expense. Contract drilling expense increased $94.9 million to $139.6 million for the year ended

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

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

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Issuances of Equity.

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

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

Capital Expenditures.

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

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

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

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

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

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

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

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

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

Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments at December 31, 2007 (in thousands):

	Payments Due by Period
Contractual Obligations	Total		Less than 1		1-3 years		4-5 years		More than 5
			year						years
Short and long-term debt	$	68,118	$	1,256	$	63,422	$	1,964	$	1,476
Operating lease obligations		2,366		533		1,101		430		302
Total	$	70,484	$	1,789	$	64,523	$	2,394	$	1,778

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements.

Recent Accounting Pronouncements

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

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

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

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

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

We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. Borrowings under our new revolving credit facility bear interest at a floating rate equal to LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to adjusted EBITDA. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $398,000 annually, based on the $65.0 million outstanding in the aggregate under our credit facility as of February 29, 2008.

Item 8. Financial Statements and Supplementary Data.

Our Financial Statements begin on page 31 of this Form 10-K, Index to Consolidated Financial Statements, and are incorporated herein by this reference.

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

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Control and Procedures.

As of the end of the period covered by this Annual Report on Form 10−K, our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a−15(e) or 15d−15(e) under the Securities Exchange Act of 1934, as amended). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2007 our disclosure controls and procedures are effective.

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

Management's Report on Internal Control over Financial Reporting.

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

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

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

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

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

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, conducted its evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation.  Although there are inherent limitations in the effectiveness of any system of internal controls over financial reporting, based on our evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2007.

The independent registered public accounting firm that audited the Company's financial statements, Grant Thornton LLP, has also audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, as stated in their accompanying report.

Changes in Internal Controls over Financial Reporting.

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

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Report of Independent Registered Public Accounting Firm

Board of Directors

Bronco Drilling Company, Inc.

We have audited Bronco Drilling Company, Inc.’s (the “Company”) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006, and the related consolidated statements of operations, members’/stockholders’equity and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 17, 2008 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 17, 2008

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Item 9B. Other Information.

None.

PART III

Item 10. Directors and Executive Officers and Corporate Governance.

The information relating to this Item 10 is incorporated by reference to the Proxy Statement for our 2008 Annual Meeting of Stockholders, which will be filed with the SEC no later than 120 days after December 31, 2007.

Item 11. Executive Compensation.

 The information relating to this Item 11 is incorporated by reference to the Proxy Statement for our 2008 Annual Meeting of Stockholders, which will be filed with the SEC no later than 120 days after December 31, 2007.

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

The information relating to this Item 12 is incorporated by reference to the Proxy Statement for our 2008 Annual Meeting of Stockholders, which will be filed with the SEC no later than 120 days after December 31, 2007.

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

The information relating to this Item 13 is incorporated by reference to the Proxy Statement for our 2008 Annual Meeting of Stockholders, which will be filed with the SEC no later than 120 days after December 31, 2007.

Item 14. Principal Accounting Fees and Services

The information relating to this Item 14 is incorporated by reference to the Proxy Statement for our 2008 Annual Meeting of Stockholders, which will be filed with the SEC no later than 120 days after December 31, 2007.

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) The following documents are filed as part of this report:

1. Financial Statements

See Index to Consolidated Financial Statements on page 28 of this Form 10-K.

2. Financial Statement Schedules

Schedule II

3. Exhibits:

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The following exhibits are filed as part of this report or, where indicated, were previously filed and are hereby incorporate by reference.

Exhibit No.                                                                Description       

2.1 Merger Agreement, dated as of August 11, 2005, by and among Bronco Drilling Holdings, L.L.C, Bronco Drilling Company, L.L.C. and Bronco Drilling Company, Inc. (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-128861, filed by the Company with the SEC on October 6, 2005).

2.2 Agreement and Plan of Merger by and among the Company, BDC Acquisition Company, Eagle Well Service, Inc. (“Eagle”), and the stockholders of Eagle dated as of January 9, 2007 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 000-51571, filed by the Company with the SEC on January 16, 2007).

2.3 Agreement and Plan of Merger, dated as of January 23, 2008, by and among Allis-Chalmers Energy, Inc., Bronco Drilling Company, Inc. and Elway Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, File No. 000-51471, filed by the Company with the SEC on January 24, 2008).

3.1 Amended and Restated Certificate of Incorporation of the Company, dated August 11, 2005 (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-128861, filed by the Company with the SEC on October 6, 2005).

3.2 Bylaws of the Company (incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-125405, filed by the Company with the SEC on July 14, 2005).

4.1 Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-125405, filed by the Company with the SEC on August 2, 2005).

4.2 Shareholders’ Agreement relating to Challenger Limited dated January 4, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, File No. 000-51471, filed by the Company with the SEC on January 9, 2008).

10.1 Drilling Rigs Purchase and Sale Agreement by and between Bronco Drilling Company, Inc., Hays Trucking, Inc., and Challenger Limited dated January 4, 2008 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, File No. 000-51471, filed by the Company with the SEC on January 9, 2008).

10.2 Promissory Note and Security Agreement by Challenger Limited dated January 4, 2008 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K, File No. 000-51471, filed by the Company with the SEC on January 9, 2008).

10.3 Credit Agreement, dated January 13, 2006, by and between the Company and Fortis Capital Corp. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, File No. 000-51471, filed by the Company with the SEC on January 20, 2006).

+10.4 Consulting Agreement, dated February 28, 2006, by and between the Company and Michael O. Thompson (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K, File No.  000-51471, filed by the Company with the SEC on March 7, 2006).

10.5 Daywork Drilling Contract, dated as of January 26, 2006, by and between Windsor Energy Resources, Inc. and the Company (incorporated by reference to Exhibit 10.20 to Amendment No. 2 to the Registration Statement on Form S-1, filed by the Company with the SEC on March 17, 2006).

+10.6 Bronco Drilling Company, Inc. 2006 Stock Incentive Plan (incorporated by reference to Appendix B to the Company’s Proxy Statement, filed by the Company with the SEC on April 28, 2006).

+10.7 Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 000-51571, filed by the Company with the SEC on June 15, 2006).

+10.8 Form of Stock Option Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 000-51571, filed by the Company with the SEC on June 15, 2006).

+10.9 Employment Agreement, dated effective as of August 8, 2006, by and between the Company and D. Frank Harrison (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 10, 2006).

+10.10 Amendment to Employment Agreement, dated as of August 2, 2007, by and between the Company and D. Frank Harrison (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 3, 2007).

+10.11 Employment Agreement, dated effective as of August 8, 2006, by and between the Company and Zachary M. Graves (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 10, 2006).

+10.12 Amendment to Employment Agreement, dated as of August 2, 2007, by and between the Company and Zachary M. Graves (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 3, 2007).

+10.13 Employment Agreement, dated effective as of August 8, 2006, by and between the Company and Mark Dubberstein(incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 10, 2006).

+10.14 Amendment to Employment Agreement, dated as of August 2, 2007, by and between the Company and Mark Dubberstein (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 3, 2007).

+10.15 Employment Agreement, dated effective as of August 2, 2007, by and between the Company and Larry Bartlett (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 3, 2007).

+10.16 Employment Agreement, dated effective as of August 2, 2007, by and between the Company and Steven Starke (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q, filed by the Company with the Sec on August 3, 2007).

*21.1 List of Company's Subsidiaries

*23.1 Consent of Grant Thornton LLP

*24.1 Power of Attorney (included on signature page).

*31.1 Certification of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

*31.2 Certification of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended

*32.1 Certification of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

*32.2 Certification of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

+ Management contract, compensatory plan or arrangement

      *Filed herewith.

-27-

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

BRONCO DRILLING COMPANY, INC. AND SUBSIDIARIES

	Page
Bronco Drilling Company, Inc. and Subsidiaries
Report of Independent Registered Public Accounting Firm	29
Consolidated Balance Sheets as of December 31, 2007 and 2006	30
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005	31
Consolidated Statements of Members’/Stockholders’ Equity for the years ended December 31, 2005, 2006 and 2007	32
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005	33
Notes to Consolidated Financial Statements	34

-28-

Report of Independent Registered Public Accounting Firm

Board of Directors

Bronco Drilling Company, Inc.

We have audited the accompanying consolidated balance sheets of Bronco Drilling Company, Inc. and Subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, members’/stockholders’equity and cash flows for each of the three years in the period ended December 31, 2007.  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.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Bronco Drilling Company, Inc. and Subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 17, 2008 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 17, 2008

-29-

Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share par value)
		December 31,
		2007		2006
ASSETS
CURRENT ASSETS
	Cash and cash equivalents	$	5,721	$	10,608
	Receivables
	Trade and other, net of allowance for doubtful accounts of
	$1,834 and $400 in 2007 and 2006, respectively		61,499		60,282
	Contract drilling in progress		2,128		1,989
	Income tax receivable		1,191		-
	Current deferred income taxes		775		155
	Prepaid expenses		705		338
	Total current assets		72,019		73,372
PROPERTY AND EQUIPMENT - AT COST
	Drilling rigs and related equipment		510,962		396,499
	Transportation, office and other equipment		41,942		29,928
			552,904		426,427
	Less accumulated depreciation		86,274		44,505
			466,630		381,922
OTHER ASSETS
	Goodwill		23,908		21,280
	Restricted cash and deposit		2,745		2,600
	Intangibles, net, and other		3,303		3,314
			29,956		27,194
		$	568,605	$	482,488
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
	Accounts payable	$	16,715	$	19,677
	Accrued liabilities		19,280		11,767
	Income tax payable		-		3,724
	Current maturities of long-term debt		1,256		636
	Total current liabilities		37,251		35,804
LONG-TERM DEBT,  less current maturities			66,862		64,091
DEFERRED INCOME TAXES			68,063		42,608
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
	Common stock, $.01 par value, 100,000
	shares authorized; 26,031 and 24,938 shares
	issued and outstanding at December 31, 2007 and 2006		262		250
	Additional paid-in capital		298,195		279,355
	Retained earnings		97,972		60,380
	Total stockholders' equity		396,429		339,985
		$	568,605	$	482,488
The accompanying notes are an integral part of these statements.

-30-

Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands, except per share amounts)
		Years Ended December 31,
		2007			2006			2005
REVENUES
	Contract drilling revenues, including 1%, 4% and 3%
	to related parties	$	276,088		$	285,828		$	77,885
	Well service		22,864			-			-
			298,952			285,828			77,885
EXPENSES
	Contract drilling		153,797			139,607			44,695
	Well service		14,299			-			-
	Depreciation and amortization		44,241			30,335			9,143
	General and administrative		22,690			15,709			9,395
			235,027			185,651			63,233
	Income from operations		63,925			100,177			14,652
OTHER INCOME (EXPENSE)
	Interest expense		(4,762	)		(1,736	)		(1,415	)
	Loss from early extinguishment of debt		-			(1,000	)		(2,062	)
	Interest income		1,239			164			432
	Other		294			284			53
			(3,229	)		(2,288	)		(2,992	)
	Income before income taxes		60,696			97,889			11,660
Income tax expense			23,104			38,056			6,529
	NET INCOME	$	37,592		$	59,833		$	5,131
Income per common share-Basic		$	1.45		$	2.43		$	0.32
Income per common share-Diluted		$	1.44		$	2.43		$	0.31
Weighted average number of shares outstanding-Basic			25,996			24,585			16,259
Weighted average number of shares outstanding-Diluted			26,101			24,623			16,306
PRO FORMA INFORMATION (unaudited):
Historical income before income taxes								$	11,660
Pro forma provision for income taxes									4,396
Pro forma income								$	7,264
Pro forma income per common share-Basic and Diluted								$	0.45
Weighted average number of shares outstanding-Basic									16,259
Weighted average number of shares outstanding-Diluted									16,306
The accompanying notes are an integral part of these statements.

-31-

Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF MEMBERS'/STOCKHOLDERS' EQUITY
(Amounts in thousands)
								Additional				Total
	Members'			Common		Common		Paid In		Retained		Stockholders'
	Equity			Shares		Amount		Capital		Earnings		Equity
Balance as of December 31, 2004	$	50,803			-	$	-	$	-	$	-	$	-
Net income through August 15, 2005		4,584			-		-		-		-		-
Conversion to a Delaware corporation		(55,387	)		13,360		134		55,254		-		55,388
Issuance of common stock in initial public offering;
net of related expenses of $1,354		-			5,715		57		88,944		-		89,001
Stock issued in acquisition		-			65		1		1,274		-		1,275
Issuance of common stock in follow-on offering;
net of related expenses of $462		-			4,025		40		86,981		-		87,021
Net income, August 16, 2005 through December 31, 2005		-			-		-		-		547		547
Stock compensation		-			-		-		589		-		589
Capital contributions		-			-		-		5,515		-		5,515
Balance as of December 31, 2005		-			23,165		232		238,557		547		239,336
Stock issued in acquisition		-			73		1		1,815		-		1,816
Issuance of common stock in follow-on offering;
net of related expenses of $577		-			1,700		17		36,212		-		36,229
Net income		-			-		-		-		59,833		59,833
Stock compensation		-			-		-		2,771		-		2,771
Balance as of December 31, 2006		-			24,938		250		279,355		60,380		339,985
Stock issued in acquisition		-			1,070		10		15,114		-		15,124
Net income		-			-		-		-		37,592		37,592
Stock compensation		-			23		2		3,726		-		3,728
Balance as of December 31, 2007	$	-			26,031	$	262	$	298,195	$	97,972	$	396,429
The accompanying notes are an integral part of these statements.

-32-

Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
				Years Ended December 31,
				2007			2006			2005
Cash flows from operating activities:
	Net income			$	37,592		$	59,833		$	5,131
	Adjustments to reconcile net income to net cash
	provided by operating activities:
		Depreciation and amortization			44,826			30,901			9,193
		Bad debt expense			4,370			70			184
		Non-cash compensation expense			-			-			4,000
		Gain on sale of assets			(1,589	)		(2,379	)		-
		Write off of debt issue costs			-			267			799
		Stock compensation			3,728			2,771			589
		Provision for deferred income taxes			17,648			21,237			5,157
		Changes in current assets and liabilities, net of assets and liabilities of business acquired:
			Receivables		(3,920	)		(25,274	)		(28,721	)
			Contract drilling in progress		(139	)		(763	)		177
			Prepaid expenses		(176	)		147			(445	)
			Other assets		(417	)		232			(485	)
			Accounts payable		(15,831	)		(2,309	)		1,827
			Accrued expenses		1,430			5,968			4,540
			Income taxes payable		(4,915	)		2,352			1,372
Net cash provided by operating activities					82,607			93,053			3,318
Cash flows from investing activities:
	Restricted cash account				145			(416	)		(1,515	)
	Business acquisitions, net of cash acquired				(2,431	)		(17,046	)		(135,213	)
	Proceeds from the sale of assets				5,084			4,761			-
	Purchase of property and equipment				(82,782	)		(130,498	)		(53,598	)
Net cash used in investing activities					(79,984	)		(143,199	)		(190,326	)
Cash flows (used in) from financing activities:
	Proceeds from borrowings ($68,000 from affiliates in 2005)				17,000			44,000			119,950
	Payments of debt ($68,000 to affiliates in 2005)				(24,510	)		(34,867	)		(93,706	)
	Debt issue costs				-			(1,647	)		(873	)
	Capital contributions				-			-			1,515
	Proceeds from sale of common stock, net
	of offering costs of $577 and $1,816				-			36,229			176,022
Net cash (used in) provided by financing activities					(7,510	)		43,715			202,908
Net increase (decrease) in cash and cash equivalents					(4,887	)		(6,431	)		15,900
Beginning cash and cash equivalents					10,608			17,039			1,139
Ending cash and cash equivalents				$	5,721		$	10,608		$	17,039
Supplmentary disclosure of cash flow information
	Interest paid, net of amount capitalized			$	3,250		$	1,771		$	1,324
	Income taxes paid				10,373			14,467			-
Supplementary disclosure of non-cash investing and financing:
	Liabilities assumed in acquisition			$	7,867		$	-		$	1,775
	Common stock issued for acquisition				15,124			1,816			1,275
	Note assumed in acquisition				6,527			-			7,000
	Notes issued for acquisition of property and equipment				4,386			3,769			-
	In kind contribution by founder				-			-			4,000
The accompanying notes are an integral part of these statements.

-33-

Bronco Drilling Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

($ Amounts in thousands, except per share amounts)

1. Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

Bronco Drilling Company, Inc. (the “Company”) provides contract land drilling and workover services to oil and natural gas exploration and production companies. The accompanying consolidated financial statements include the Company’s accounts and the accounts of its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

The Company has prepared the consolidated financial statements and related notes in accordance with accounting principles generally accepted in the United States of America. In preparing the financial statements, the Company made various estimates and assumptions that affect the amounts of assets and liabilities the Company reports as of the dates of the balance sheets and amounts the Company reports for the periods shown in the consolidated statements of operations, stockholders’ equity and cash flows. The Company’s actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to the Company’s recognition of revenues and accrued expenses, estimate of the allowance for doubtful accounts, estimate of asset impairments, estimate of deferred taxes and determination of depreciation and amortization expense.

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

Cash and Cash Equivalents

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

The Company maintains its cash and cash equivalents in accounts and instruments that may not be federally insured beyond certain limits. 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.

Revenue Recognition

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

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 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.

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. Revenue from such claims are recorded only to the extent that contract costs relating to the claim have been incurred.  Historically we have not billed any customers for amounts not included in the original contract.

Accounts Receivable

The Company records trade accounts receivable at the amount invoiced to customers. 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 reduce the allowance for doubtful accounts. At December 31, 2007 and 2006, our allowance for doubtful accounts was $1,834 and $400, respectively. The Company continues to accrue additional receivables related to a customer which had $3,556 of receivables past due ninety days or more at December 31, 2007. The Company recognizes interest income related to certain accounts receivable based on the amounts invoiced to customers.

Prepaid Expenses

Prepaid expenses include items such as insurance and fees. The Company routinely expenses these items in the normal course of business over the periods these expenses benefit.

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 Company made an adjustment of $2,066 to reduce depreciation expense in the third quarter of 2007. The adjustment was due to the use of an incorrect depreciable life for certain rig components that were transferred between working rigs and the yard, which resulted in an overstatement of depreciation expense and accumulated depreciation of $1,245 during 2006 and $821 during the first quarter of 2007. The Company does not believe this adjustment was material to the 2006 or 2007 annual financial statements. 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 $61,604 and $57,247 as of December 31, 2007 and 2006, respectively.  Gains and losses on dispositions are included in operating revenues.  Due to immateriality, these amounts are included in contract drilling revenue.

The Company capitalizes interest as a component of the cost of drilling rigs constructed for its own use. For the years ended December 31, 2007 and 2006, the Company capitalized $1,676 and $3,590, respectively, of interest costs incurred during the construction periods of certain drilling rigs.

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.

Goodwill

The Company evaluates the carrying value of goodwill during the fourth quarter of each year and between annual evaluations if events occur or circumstances change that would more likely than not reduce the fair value below its carrying amount. Such circumstances could include, but are not limited to: (1) a significant adverse change in legal factors or in business climate, (2) unanticipated competition, or (3) an adverse action or assessment by a regulator. When evaluating whether goodwill is impaired, the Company compares its fair value to its carrying amount, including goodwill. Fair value is estimated using a combination of income, or discounted cash flows approach and the market approach, which utilizes comparable companies’ data. If the carrying amount exceeds its fair value, then the amount of the impairment loss must be measured. The impairment loss would be calculated by comparing the implied fair value of reporting unit goodwill to its carrying amount. In calculating the implied fair value of goodwill, the fair value of the Company is allocated to all of its other assets and liabilities based on their fair values. The excess of the fair value of the Company over the amount assigned to its other assets and liabilities is the implied fair value of goodwill. An impairment loss would be recognized when the carrying amount of goodwill exceeds its implied fair value. No impairment of goodwill has been required during impairment evaluations. Goodwill recognized during 2007 and 2006 through acquisitions was $2,628 and $380, respectively.

-34-

Intangibles, Net and Other

Intangibles, restricted cash and other assets consist of intangibles related to acquisitions, net of amortization, cash deposits related to the deductibles on our workers compensation insurance policies and debt issue costs, net of amortization. The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangibles” to account for amortizable intangibles. Intangible assets that are acquired either individually or with a group of other assets are recognized based on its fair value and amortized over its useful life.

The Company’s amortizable intangibles consist entirely of customer lists and relationships obtained through acquisitions. Customer lists and relationships are amortized over their estimated benefit period of four years. Depreciation and amortization expense includes amortization of intangibles of $919, $672, and $87 for the years ended December 31, 2007, 2006, and 2005, respectively. Total cost and accumulated amortization of intangibles at December 31, 2007 and 2006 was $3,705 and $1,678 and $2,619 and $759, respectively.

 Estimated amortization expense for each year subsequent to December 31, 2007 is as follows:

2008	$	928
2009		706
2010		203
2011		182
2012		8

 Legal fees and other debt issue costs incurred in obtaining financing are amortized over the term of the debt using a method which approximates the effective interest method. Gross debt issue costs were $1,589 at December 31, 2007 and 2006, respectively. Amortization expense related to debt issue costs was $564, $508, and $53 for years ended December 31, 2007, 2006 and 2005, respectively, and is included in interest expense in the consolidated statements of operations. Accumulated amortization related to loan fees was $1,072 and $508 as of December 31, 2007 and 2006, respectively.  On January 13, 2006, the Company paid off its term note with Merrill Lynch Capital.  The Company incurred a prepayment penalty of $497 and wrote-off debt issue costs of $503, which is included in loss from early extinguishment of debt on the consolidated statement of operations for the year ended December 31, 2006.  On August 29, 2005, the Company paid off its term note with General Electric Capital Corporation. The Company incurred a prepayment penalty of $644 and wrote-off debt issue costs of $349, which is included in loss from early extinguishment of debt on the consolidated statement of operations for the year ended December 31, 2005. On November 2, 2005, the Company paid off its term note with Theta Investors, LLC, formerly Alpha Investors LLC, an entity controlled by Wexford Capital, LLC (“Wexford”), which at that time, was the Company’s equity sponsor and controlled the Company. The Company wrote-off debt issue costs of $1,075, which is included in loss from early extinguishment of debt on the consolidated statement of operations for the year ended December 31, 2005.

Restricted Cash and Deposit

At December 31, 2007 and 2006, the Company had a deposit and restricted cash of $2,745 and $2,600, respectively, at an insurance company and a bank collateralizing letters of credit with the Company’s workers’ compensation insurers.

Income Taxes

Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” the Company follows the asset and liability method of accounting for income taxes, under which the Company recognizes deferred tax assets and liabilities 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 35% (34% in 2005) and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the enacted tax rates for all periods.

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.

 The Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company is continuing its practice of recognizing interest and/or penalties related to income tax matters as income tax expense.  As of December 31, 2007, the tax years ended December 31, 2004 through December 31, 2006 are open for examination by U.S. taxing authorities.

Pro Forma Income Taxes (unaudited)

 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, prior to our initial public offering (“IPO”) on August 15, 2005 except for tax expense (benefit) associated with a taxable subsidiary. As a result of our conversion to a taxable corporation on August 15, 2005, a charge to income tax expense of $4,412 was made to record deferred taxes for the differences between the tax basis and financial reporting basis of our assets and liabilities. Pro forma adjustments are reflected to provide for income taxes in accordance with SFAS 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.

Net income (Loss) Per Common Share

The Company computes and presents net income (loss) per common share in accordance with SFAS No. 128 “Earnings per Share.” This standard requires dual presentation of basic and diluted net income (loss) per share on the face of the Company’s statement of operations. Basic net income (loss) per common share is computed by dividing net income or loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock.

Pro Forma Income (Loss) Per Share (unaudited)

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 prior to our IPO on August 15, 2005.

Stock-based Compensation

The Company has adopted SFAS No. 123(R), “Share-Based Payment” upon granting its first stock options on August 16, 2005. SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the periods during which an employee is required to provide service in exchange for the award.

Recent Accounting Pronouncements

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

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

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

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

2. Acquisitions

In July 2005, the Company acquired all the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. (together “Strata”) and a related rig yard. Included in these acquisitions were two operating rigs, one rig that was 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. 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 the sellers. The Company funded the cash portion of the purchase price with a $13,000 loan from Theta Investors, LLC, formerly Alpha Investors LLC, an entity controlled by Wexford. The outstanding principal balance of this loan was paid in full on August 22, 2005 with proceeds from our initial public offering. This purchase was accounted for as an acquisition of a business, and the results of operations of the acquired business have been included in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment and related assets based on their relative fair values at the date of acquisition.

The $7,000 original aggregate outstanding principal balance of the promissory notes issued to the sellers was automatically reduced by the amount of any costs and expenses the Company paid in connection with the refurbishment of one of the rigs it acquired from the sellers. 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 did not bear any interest other than default interest in the event of a default. In January 2006, the rig was completed to the satisfaction of the Company and title passed at such point. Upon acceptance of the rig the note was paid in full.

In September 2005, the Company acquired all the outstanding common stock of Hays Trucking, Inc. (“Hays Trucking”) for $3,000 in cash, which includes the repayment of $1,900 of debt owed by Hays Trucking, and the issuance of 65,368 shares of common stock with a fair value of $1,274 based on the closing stock price at date of acquisition. In this acquisition, the Company acquired 18 trucks used to mobilize rigs to contracted drilling locations as well as other ancillary equipment. Approximately $286 of the purchase price was allocated to customer lists and is included in intangibles on the balance sheets at December 31, 2006 and December 31, 2005.   Customer lists are being amortized over an expected life of four years.

In October 2005, the Company purchased 12 land drilling rigs from Eagle Drilling, L.L.C., and two of its affiliates (“Eagle”). This acquisition involved five operating rigs, seven inventoried rigs and rig equipment and parts for a purchase price of approximately $50,528. The purchase price of $50,528, which includes approximately $528 of related transaction costs, was funded with a $7,517 from cash on hand and a $43,000 loan from Merrill Lynch Business Financial Services, Inc., as lender (see Note 4). The purchase price has been allocated to property and equipment totaling $33,838, goodwill of $16,037 and customer lists and relationships of $653.  Customer lists are being amortized over an expected life of four years.  The entire amount allocated to goodwill is considered deductible for tax purposes.

In October 2005, the Company purchased 13 land drilling rigs from Thomas Drilling Company (“Thomas”). This acquisition involved nine operating rigs, two rigs being refurbished, two inventoried rigs and rig equipment and parts for a purchase price of approximately $70,737, which includes approximately $2,737 of related transaction costs.  The purchase price was partially funded through a $50,000 loan from Theta Investors LLC, an entity controlled by Wexford. This loan was repaid in full on November 3, 2005 with a portion of the proceeds from the Company’s follow-on common stock offering which closed on November 2, 2005. The purchase price has been allocated to property and equipment totaling $64,708, goodwill of $4,686 and customer lists of $1,166.  Customer lists are being amortized over an expected life of four years.  The entire amount allocated to goodwill is considered deductible for tax purposes.

On January 18, 2006, the Company completed the acquisition of six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling, L.L.C. (“Big A”). The results of Big A’s operations have been included in the consolidated financial statements since that date. The purchase price for the assets consisted of $16,028 in cash and 72,571 shares of our common stock with a fair market value of $1,816. The purchase price has been allocated to property and equipment totaling $17,077, goodwill of $380 and customer lists of $387. Customer lists are being amortized over an expected life of four years. The entire amount allocated to goodwill is considered deductible for tax purposes.

 On January 9, 2007, the Company completed the acquisition of 31 workover rigs, 24 of which were in service at the time of the acquisition, from Eagle Well Service, Inc. (“Well Service”) and related subsidiaries for $2,567 in cash, 1,070,390 shares of our common stock with a fair market value of $15,125, and the assumption of debt of $6,527, liabilities of $678, and additional deferred income taxes of $7,188.  This acquisition provided a platform for the Company to expand into the well service industry.  The Company acquired the stock of Well Service, which was accounted for using the purchase method of accounting.  The deferred tax liability assumed in the acquisition was the main factor that resulted in the Company recording goodwill, all of which is not deductible for tax purposes.  The amortizable intangibles acquired include trade name and customer lists, which will be amortized over two and five years, respectively.  The operations related to the Well Service acquisition are included in the Company’s statement of operations as of the respective closing date.

The following table summarizes the allocation of purchase price to the Company’s significant acquisitions:

	Year Ended December 31,
	2007		2006		2005
	Well Service		Big A		Strata		Eagle		Thomas		Total
Assets acquired:
Cash	$	198	$	-	$	-	$	-	$	-	$	-
Prepaid expenses		227		-		-		-		-		-
Accounts receivable		1,667		-		-		-		-		-
Drilling equipment		-		16,724		11,840		33,838		64,288		109,966
Workover equipment		23,912		-		-		-		-		-
Rig under construction				-		7,000		-		-		7,000
Yard equipment				-		170		-		-		170
Other equipment		244		-		-		-		-		-
Vehicles		1,943		353		18		-		420		438
Buildings				-		729		-		-		729
Land				-		243		-		-		243
Customer lists		910		387		-		653		1,166		1,819
Trade name		190		-		-		-		-		-
Goodwill		2,794		380		-		16,037		4,686		20,723
	$	32,085	$	17,844	$	20,000	$	50,528	$	70,560	$	141,088

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 The following pro forma information gives effect to the Strata, Eagle, Thomas and Big A acquisitions as though they were effective at the beginning of 2005 and the Well Service acquisition as though it was effective at the beginning of 2006. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects the Company’s historical data and historical data from the acquired business for the periods indicated. The pro forma data may not be indicative of the results the Company would have achieved had it completed the acquisition at the beginning of each year presented, or that it may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements. Pro forma income per basic and diluted common share is computed based on the weighted average pro forma number of basic and diluted shares assumed to be outstanding during the period. Pro forma per share information is presented for the year ended December 31, 2005 on the basis of 16,259,000 and 16,306,000 weighted average shares issued basic and diluted, respectively, and 72,571 shares issued in the Big A acquisition. Pro forma per share information is presented for the year ended December 31, 2006 on the basis of 24,585,000 and 24,623,000 weighted average shares issued basic and diluted, respectively, and 1,070,000 shares issued in the Well Service acquisition. Dilutive pro forma effect is given to shares which are issuable upon the exercise of outstanding options under the Company’s employee stock option plan.

	Pro Forma
	(Unaudited)
	Year Ended December 31,
	2006		2005		2004
Total revenues	$	299,964	$	156,090	$	47,960
Net income	$	61,299	$	12,193	$	(6,021	)
Net income per common share:
Basic	$	2.39	$	0.75	$	(0.45	)
Diluted	$	2.39	$	0.75	$	(0.45	)

3. Accrued liabilities

 Accrued liabilities consisted of the following at December 31, 2007 and 2006:

	2007		2006
Salaries, wages, payroll taxes and benefits	$	4,828	$	5,277
Workers' compensation liability		2,959		1,869
Sales, use and other taxes		8,122		945
Health insurance		409		404
Deferred revenue		1,720		2,978
Accrued interest		1,242		294
	$	19,280	$	11,767

The Company made an adjustment during the fourth quarter of 2007 to accrue for sales and use taxes in the amount of $6,237.  The adjustment was due to the Company’s non-payment of taxes upon initial acquisition of equipment.  Included in the adjustment made in the fourth quarter is an accrual of interest in the amount of $634, of which $404, $227 and $3 relate to 2007, 2006 and 2005, respectively.  The fourth quarter adjustment also includes additional depreciation expense in the amount of $1,167, of which $684, $459 and $24 relate to 2007, 2006 and 2005, respectively.  The Company does not believe this adjustment is material to either the 2007, 2006 or 2005 annual financial statements.  The Company expects to settle the liability with the respective tax authorities in April 2008.

4. Long-term Debt

 Long-term debt consists of the following:

	December 31,		December 31,
	2007		2006
Notes payable to De Lage Landen Financial Services, collateralized by cranes,
payable in ninety-six monthly principal and interest installments of $61
Interest on the notes ranges from 6.74% - 7.07%, with various due dates (1)	$	5,120	$	4,167
Revolving credit facility with Fortis Capital Corp., collateralized by the Company's assets,
and matures on January 13, 2009.  Loans under the revolving credit facility
bear interest at variable rates as defined in the credit agreement. (2)		60,000		60,000
Note payable to Ameritas Life Insurance Corp., collateralized by the building, payable in principal and interest installments of $14, interest on the note is 6.0%, maturity date of January 1, 2021. (3)		1,521		-
Notes payable to General Motors Acceptance Corporation, collateralized by trucks, payable in monthly principal and interest installments of $35, various due dates. (4)		1,184		-
Note payable to John Deere Construction & Forestry Company, collaterized by forklifts, in thirty-six monthly installments of $11, due December 1, 2009 (5)		258		393
Note payable to Ford Motor Credit, collateralized by truck,
payable in principal and interest installments of $1
Interest on the note is 2.9%, due November 10, 2010. (6)		35		167
		68,118		64,727
Less current installments		1,256		636
	$	66,862	$	64,091

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(1) On December 7, 2005, January 4, 2006, June 12, 2006 and April 15, 2007, the Company entered into Term Loan and Security Agreements with De Lage Landen Financial Services, Inc. The loans provide for term installments in an aggregate amount not to exceed $6,000. The proceeds of the term loans were used to purchase five cranes.

(2) On January 13, 2006, the Company entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. The initial aggregate revolving commitment of $150.0 million is automatically and permanently reduced by $10.0 million at the end of each fiscal quarter starting September 30, 2006.  The aggregate revolving commitment was $90,000 as of December 31, 2007.  Loans under the revolving credit facility bear interest at LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to “Adjusted EBITDA” as defined in the credit agreement. Borrowings under this revolving credit facility were used to fund a portion of the Big A acquisition and to repay in full all outstanding borrowings under the Company’s term loan with Merrill Lynch Capital and its revolving line of credit with International Bank of Commerce.

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

The revolving credit facility contains customary covenants for facilities of this type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions. The financial covenants are a minimum fixed charge coverage ratio of 1.75 to 1.00 and a maximum total leverage ratio of 2.00 to 1.00. The Company was in compliance with all covenants at December 31, 2007.  The revolving credit facility provides for mandatory prepayments under certain circumstances as more fully discussed in the revolving credit facility.

(3) On January 2, 2007, the Company assumed a term loan agreement with Ameritas Life Insurance Corp. related to the acquisition of a building.  The loan provides for term installments in an aggregate not to exceed $1,590.

(4) On various dates during 2007, the Company entered into term loan agreements with General Motors Acceptance Corporation.  The loans provide for term installments in an aggregate not to exceed $1,277.  The proceeds of the term loans were used to purchase 30 trucks.

(5) On November 21, 2006, the Company entered into term loan agreements with John Deere Credit.  The loans provide for term installments in an aggregate not to exceed $403.  The proceeds of the term loans were used to purchase two forklifts.

(6) On November 9, 2007, the Company entered into a term loan agreement with Ford Credit.  The loan provides for a term installment in an aggregate not to exceed $36.  The proceeds of the term loan were used to purchase a truck.

Long-term debt maturing each year subsequent to December 31, 2007 is as follows:

2008	$	1,256
2009		61,344
2010		1,192
2011		886
2012		949
2013 and thereafter		2,491
	$	68,118

5. Income Taxes

The Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2007, the Company had no unrecognized tax benefits.  The Company is continuing its practice of recognizing interest and/or penalties related to income tax matters as income tax expense.  As of December 31, 2007, the tax years ended December 31, 2004 through December 31, 2006 are open for examination by U.S. taxing authorities.

Income tax expense consists of the following:

	Years Ended December 31,
	2007		2006		2005
Current:
State	$	541	$	2,456	$	205
Federal		4,915		14,363		1,167
Deferred:
State		1,878		2,023		510
Federal		15,770		19,214		4,647
Income tax expense	$	23,104	$	38,056	$	6,529

 Deferred income tax assets and liabilities are as follows:

	Years Ended December 31,
	2007		2006
Deferred tax assets:
Stock option expense	$	2,609	$	1,299
Alternative minimum tax credit carryforward		2,095		-
Other		775		155
Total deferred tax assets		5,479		1,454
Deferred tax liabilities:
Property and equipment, principally due
to differences in depreciation		72,767		42,901
Other		-		1,006
Total deferred tax liabilities		72,767		43,907
Net deferred tax liabilities	$	67,288	$	42,453

 For the year ended December 31, 2006 the Company’s effective tax rate increased approximately 1.0% from that of the prior years due to an increase in taxable income.  This change caused an increase of the deferred tax asset and deferred tax liability amounts of approximately $38 and $1,135, respectively.

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Upon the conversion from a limited liability company to a taxable corporation in conjunction with its initial public offering, the Company incurred a one-time charge to operations in the third quarter of 2005 of approximately $4,412 to record deferred taxes upon change in tax status.

In assessing its ability to realize deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Its ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities and projected future taxable income in making this assessment. The Company believes it is more likely than not that it will realize the benefits of these deductible differences.

The provision for income taxes on continuing operations differs from the amounts computed by applying the federal income tax rate of 35% (34% for 2005) to net income. The differences are summarized as follows:

	Years Ended December 31,
	2007			2006			2005
Expected tax expense (benefit)	$	21,244		$	34,261		$	3,964
State income taxes		2,246			3,622			431
Tax basis adjustment to 35% for prior year deferred tax components		-			562			-
Conversion to a taxable corporation		-			-			4,412
(Income) loss attributable to nontaxable entity		-			-			(2,200	)
Nondeductible officer compensation		98			-			-
Tax exempt interest		-			-			(78	)
Domestic production activities		(83	)		(467	)		-
Nondeductible meals and entertainment		45			47			-
Other		(446	)		31			-
	$	23,104		$	38,056		$	6,529

 6. Workers’ Compensation and Health Insurance

The Company is insured under a large deductible workers’ compensation insurance policy. The policy generally provides for a $1,000 deductible per covered accident. The Company maintains letters of credit in the aggregate amount of $4,835 for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts.  The letters of credit are typically renewed annually.  No amounts have been drawn under the letters of credit. At December 31, 2007 and 2006, the Company had deposits of $2,745 and $2,600, respectively, with an insurance company collateralizing a letter of credit. The deposits are reflected in restricted cash and deposit. Accrued expenses at December 31, 2007 and 2006 included approximately $2,959 and $1,869, respectively, for estimated incurred but not reported costs and premium accruals related to our workers’ compensation insurance.

On November 1, 2005, the Company initiated a self-insurance program for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. The Company provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $100 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at December 31, 2007 and 2006 included approximately $409 and $404, respectively, for our estimate of incurred but not reported costs related to the self-insurance portion of our health insurance.

7. Transactions with Affiliates

Effective April 1, 2005, the Company entered into an administrative services agreement with its then affiliate Gulfport Energy Corporation (“Gulfport”). Under this agreement, Gulfport agreed to provide certain services to the Company, including accounting, human resources, legal and technical support services. In return for the services, the Company 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 leased approximately 1,200 square feet of office space from Gulfport for the Company’s headquarters for an annual rent of $21 payable in equal monthly installments. The services the Company received under the administrative services agreement and the fees for such services could be amended by mutual agreement of the parties. In January 2006, the Company reduced the level of administrative services being provided by Gulfport and increased its office space to approximately 2,500 square feet. As a result, the Company’s annual fee for administrative services was reduced to approximately $150 and its annual rental was increased to approximately $44. The administrative services agreement had a three-year term, and upon expiration of that term the agreement would continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement was 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 party is in material breach of the agreement and such breach had not been cured within 30 days of receipt of written notice of such breach. The Company terminated the administrative services agreement effective April 1, 2006. The Company paid Gulfport approximately $96 and $353 in consideration for these services during 2006 and 2005, respectively.  As the agreement was terminated effective April 1, 2006, no further services were provided to the Company after that date.  At December 31, 2007 and December 31, 2006, $0 was owed to Gulfport.  Prior to entry into this administrative services agreement, 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 spent performing services for the Company.  Gulfport is no longer an affiliate of the Company.

The Company has five operating leases with affiliated entities.  Related rent expense was approximately $130 for the year ended December 31, 2007.

Additionally, the Company provided contract drilling services totaling $2,617, $10,025, and $2,527 to affiliated entities for the years ended December 31, 2007, 2006 and 2005. Effective March 16, 2007, these entities were no longer affiliates of the Company.  The Company had receivables from affiliates of $0 and $1,016 at December 31, 2007 and 2006, respectively.  Certain borrowings for acquisitions (see Note 2) were from affiliates.

8. Commitments and Contingencies

The Company leases twelve service locations under noncancelable operating leases that have various expirations from 2008 to 2015. Related rent expense was $790, $643, and $358 for the years ended December 31, 2007, 2006 and 2005, respectively.

Aggregate future minimum lease payments under the noncancelable operating leases for years subsequent to December 31, 2007 are as follows:

2008	$	533
2009		388
2010		393
2011		320
2012		210
2013 and thereafter		522
	$	2,366

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

9. Business Segments and Concentrations

The Company’s reportable business segments are contract land drilling and well servicing. The Company's only reportable business segment for 2006 was contract land drilling. The contract drilling segment utilizes a fleet of land drilling rigs to provide contract drilling services to oil and natural gas exploration and production companies.  During 2007 our rigs operated in Oklahoma, Texas, Colorado, Montana, North Dakota, Kansas and Louisiana.  The well servicing segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. During 2007 our workover rigs operated in Oklahoma, Texas, Kansas, Colorado and New Mexico.  The accounting policies of the segments are the same as those described in the summary of significant accounting policies.  The Company’s reportable segments are strategic business units that offer different products and services.

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 The following table sets forth certain financial information with respect to the Company’s reportable segments:

	Contract drilling			Well servicing			Total
Year ended December 31, 2007
Operating Revenues	$	276,088		$	22,864		$	298,952
Direct operating costs		(153,797	)		(14,299	)		(168,096	)
Segment profits	$	122,291		$	8,565		$	130,856
Depreciation and amortization	$	40,905		$	3,336		$	44,241
Capital expenditures	$	58,857		$	23,925		$	82,782
Identifiable assets	$	509,814		$	58,791		$	568,605

 The following table reconciles the segment profits above to the operating income as reported in the consolidated statements of operations:

	Year Ended
	December 31, 2007
Segment profits	$	130,856
General and administrative expenses		(22,690	)
Depreciation and amortization		(44,241	)
Operating income	$	63,925

For the year ended December 31, 2007, revenue from one customer was approximately 11% of total revenue, for 2006 no one customer exceeded 10% of total revenue, and for 2005 revenue from one customer was approximately 10% of total revenue.  At December 31, 2007, six customers accounted for approximately 13%, 12%, 9%, 8%, 5%, and 5% of accounts receivable.  At December 31, 2006, four customers accounted for approximately 10%, 7%, 6%, and 6% of accounts receivable.

10. Net Income Per Common Share

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share (“EPS”) and diluted EPS comparisons as required by SFAS No. 128 (amounts in thousands, except per share amounts) :

	Year Ended
	December 31,
	2007		2006		2005
Basic:
Net income	$	37,592	$	59,833	$	5,131
Weighted average shares		25,996		24,585		16,259
Income per share	$	1.45	$	2.43	$	0.32
Diluted:
Net income	$	37,592	$	59,833	$	5,131
Weighted average shares:
Outstanding (thousands)		25,996		24,585		16,259
Restricted Stock and Options (thousands)		105		38		47
		26,101		24,623		16,306
Income per share	$	1.44	$	2.43	$	0.31

 The weighted average number of diluted shares excludes 23,132 shares and 78,218 shares for the years ended December 31, 2007 and 2006, respectively, for options and restricted stock due to their antidilutive effects.

11. Equity Transactions

 Effective January 18, 2006, the Company issued 72,571 shares of common stock to the equity owners of Big A in connection with the Company’s acquisition of the assets of Big A.  (See Note 2)

In March 2006, the Company closed a public offering of 3,450,000 shares of our common stock at a price of $22.75 per share.  In the offering, a total of 1,700,000 shares were sold by the Company and 1,750,000 shares were sold by a selling stockholder.  The offering resulted in net proceeds to the Company of approximately $36,229, excluding offering expenses of $577.  The Company did not receive any proceeds from the sale of shares by the selling stockholder.

Effective January 9, 2007, the Company issued 1,070,390 shares of common stock to the equity owners of Well Service in connection with the Company’s acquisition of Well Service. (See Note 2)

12. Stock Options and Stock Option Plan

The Company’s 2005 Stock Incentive Plan was adopted on July 20, 2005 and amended on November 16, 2005 (the “2005 Plan”) which is described below. The compensation cost that has been charged against income before taxes related to stock options was $1,029 and $2,658 for the years ended December 31, 2007 and December 31, 2006, respectively.  These options are reported as equity instruments and their fair value is amortized to expense using the straight line method over the vesting period. The shares of stock issued upon the exercise of the options will be from authorized but unissued common stock.

The Company receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise price of the options. There have been no stock options exercised under the 2005 Plan.

The purpose of the 2005 Plan was to enable the Company, and any of its affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to its long-range success and to provide incentives which are linked directly to increases in share value which will inure to the benefit of the Company’s stockholders. The 2005 Plan provided a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of the Company’s common stock through the granting of incentive stock options and nonstatutory stock options. Eligible award recipients under the 2005 Plan were employees, consultants and directors of the Company and its affiliates. Incentive stock options under the 2005 Plan could be granted only to employees. Awards other than incentive stock options under the 2005 Plan could be granted to employees, consultants and directors. The shares that may be issued upon exercise of the options will be from authorized but unissued common stock, and the maximum aggregate amount of such common stock which could be issued upon exercise of all awards under the plan, including incentive stock options, could not exceed 1,000,000 shares, subject to adjustment to reflect certain corporate transactions or changes in the Company’s capital structure.

The Company’s board of directors and a majority of the Company’s stockholders approved the Company’s 2006 Stock Incentive Plan (the “2006 Plan,” and together with the 2005 Plan, the “Plans”), effective April 20, 2006.  No further awards will be made under the 2005 Plan.  The purpose of the 2006 Plan is to provide a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of the Company’s common stock through the granting of one or more of the following awards: (1) incentive stock options, (2) nonstatutory stock options, (3) restricted awards, (4) performance awards and (5) stock appreciation rights.  The maximum aggregate amount of the Company’s common stock which may be issued upon exercise of all awards under the 2006 Plan, may not exceed 2,500,000 shares, less shares underlying options granted to employees under the 2005 Plan prior to the adoption of the 2006 Plan.  There have been no stock options exercised under the 2006 Plan.

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On April 20, 2007, the Company filed a Tender Offer Statement on Schedule TO relating to the Company’s offer to twenty-five eligible directors, officers, employees and consultants to exchange certain outstanding options to purchase shares of the Company’s common stock for restricted stock awards consisting of the right to receive restricted shares of the Company’s common stock (the “Restricted Stock Awards”). The offer expired on May 21, 2007. Pursuant to the offer, the Company accepted for cancellation eligible options to purchase 729,000 shares of the Company’s common stock tendered by directors, officers, employees and consultants eligible to participate in the offer.  Subject to the terms and conditions of the offer, on May 21, 2007 the Company granted one Restricted Stock Award in exchange for every two shares of common stock underlying the eligible options tendered.  The Restricted Stock Awards will vest in equal amounts on January 1, 2008 and January 1, 2009, subject to earlier vesting or forfeiture in certain circumstances. The Company granted the Restricted Stock Awards under the 2006 Plan.

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

The fair value of each option award is estimated on the date of grant using a Black-Scholes valuation model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of a selected peer. The majority of the Company’s options were held by employees that made up one group with similar expected exercise behavior for valuation purposes. The expected term of options granted is estimated based on an average of the vesting period and the contractual period. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.

Under the 2005 Plan, employee stock options become exercisable in equal monthly installments over a three-year period, and all options generally expire ten years after the date of grant. Under the 2006 Plan, employee stock options become exercisable to the extent the options have become vested pursuant to the vesting schedule set forth in the applicable stock option award certificate, and all options generally expire ten years after the date of grant.  The Plans provide that all options must have an exercise price not less than the fair market value of the Company’s common stock on the date of the grant. The following table summarizes the assumptions used in the Black-Scholes option-pricing model for the year ended December 31, 2006.  The Company did not grant any options during the year ended December 31, 2007.

	December 31,
	2006
Expected volatility	48%
Expected life in years	5.77
Weighted average risk free interest rate	4.65%

The Company has not declared dividends since it became a public company and does not anticipate doing so in the foreseeable future, and thus did not use a dividend yield. Expected life has been determined using the permitted simplified method.  In each case, the actual value that will be realized, if any, will depend on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black–Scholes model. The following table provides information relating to activity in the 2005 and 2006 Plans during the years ended December 31, 2007 and 2006:

				Weighted		Weighted
				Average		Average Remaining		Aggregate
				Exercise Price		Contractual		Intrinsic
	Shares			per Share		Life		Value
Options outstanding at December 31, 2005		574,500		$	18.08
Granted		445,500			23.37
Exercised		-
Forfeited/expired		(188,333	)		20.38
Options outstanding at December 31, 2006		831,667		$	20.39		8.91	$	(2,632	)
Granted		-			-
Exercised		-			-
Converted		(769,000	)		20.14
Forfeited/expired		(42,667	)		22.23
Options outstanding at December 31, 2007		20,000		$	26.14		8.30	$	(227	)
Options fully vested and exercisable at December 31, 2007		10,681		$	26.14		8.30	$	(124	)

				Weighted Average		Aggregate
				Grant Date		Grant Date
	Shares			Fair Value		Fair Value
Options nonvested at December 31, 2005		511,446		$	10.05	$	5,140
Granted		445,500			11.93		5,313
Vested		(255,520	)		10.90		(2,785	)
Forfeited/expired		(188,333	)		10.45		(1,968	)
Options nonvested at December 31, 2006		513,093		$	11.11	$	5,700
Granted		-			-		-
Vested		(97,397	)		11.19		(985	)
Converted		(382,423	)		11.02		(4,321	)
Forfeited/expired		(23,954	)		11.40		(273	)
Options nonvested at December 31, 2007		9,319		$	13.34	$	121

As of December 31, 2007, there was $121 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the 2005 and 2006 Plans. That cost is expected to be recognized over a weighted-average period of 1.0 year.

13. Restricted Stock

Under the terms of all outstanding restricted stock awards, shares were issued when granted and nonvested shares are subject to forfeiture for failure to fulfill service conditions.  Restricted stock awards are valued at the grant date market value of the underlying common stock and are being amortized to operations over the respective vesting period.  Compensation expense for the years ended December 31, 2007 and 2006 related to shares of restricted stock was $2,699 and $113, respectively.  Restricted stock activity for the years ended December 31, 2007 and 2006 was as follows:

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				Weighted Average
				Grant Date
	Shares			Fair Value
Outstanding at December 31, 2005		-			-
Granted		66,667		$	20.25
Vested		-			-
Forfeited/expired		-			-
Outstanding at December 31, 2006		66,667			20.25
Granted		125,000			15.47
Converted		384,500			16.58
Vested		(22,222	)		20.25
Forfeited/expired		(500	)		16.69
Outstanding at December 31, 2007		553,445		$	16.64

There was $6,211 of total unrecognized compensation cost related to nonvested restricted stock awards to be recognized over a weighted-average period of 1.36 years as of December 31, 2007.

14. Fair Value of Financial Instruments

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

The carrying amounts of our cash and cash equivalents, trade receivables, payables and short-term debt approximate their fair values due to the short-term nature of these instruments.

Long-term debt

The carrying amount of our long-term debt approximates its fair value, as supported by the recent issuance of the debt and because the rates and terms currently available to us approximate the rates and terms of the existing debt.

15. Employee Benefit Plans

The Company implemented a new 401(k) retirement plan for its eligible employees during 2006. Under the plan, the Company matches 100% of employees’ contributions up to 5% of eligible compensation.  Employee and employer contributions vest immediately.  The Company’s contributions for the years ended December 31, 2007 and 2006 were $1,030, and $698, respectively.

16. Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for our years ended December 31, 2007 and 2006;

Bronco Drilling Company Inc.
Quarterly Results
Year Ended December 31, 2007
(Amounts in thousands except per share amounts)
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter (1)		Quarter (2)
2007
Revenues	$	78,981	$	74,720	$	76,286	$	68,965
Income from operations		19,643		14,633		18,648		11,001
Income tax expense		7,101		5,428		7,009		3,566
Net income		11,386		8,714		11,068		6,424
Income per share:
Basic		0.44		0.33		0.43		0.25
Diluted		0.44		0.33		0.42		0.25
2006
Revenues	$	56,387	$	67,151	$	79,814	$	82,476
Income from operations		19,252		23,598		28,403		28,924
Income tax expense		6,915		8,747		10,527		11,867
Net income		11,347		14,729		17,405		16,352
Income per share:
Basic		0.48		0.59		0.70		0.66
Diluted		0.48		0.59		0.70		0.66

(1) The Company made an adjustment of $2,066 to reduce depreciation expense in the third quarter of 2007. The adjustment was due to the use of an incorrect depreciable life for certain rig components that were transferred between working rigs and the yard, which resulted in an overstatement of depreciation expense and accumulated depreciation of $1,245 during 2006 and $821 during the first quarter of 2007.

(2) The Company made an adjustment during the fourth quarter of 2007 to accrue for sales and use tax in the amount of $6,237. The adjustment was due to the Company's non-payment of taxes upon initial acquistion of equipment. Included in the adjustment made in the fourth quarter is an accrual for interest in the amount of $634, of which $404, $227 and $3 relate to 2007, 2006 and 2005, respectively. The fourth quarter adjustment also includes additional depreciation expense in the amount of $1,167, of which $684, $459, and $24 relate to 2007, 2006 and 2005, respectively.

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17. Valuation and Qualifying Accounts

The Company’s valuation and qualifying accounts for the years ended December 31, 2007, 2006 and 2005 are as follows:

	Valuation and Qualifying Accounts
	Balance		Charged
	at		to Costs		Deductions			Balance
	Beginning		and		from			at
	of Year		Expenses		Accounts			Year End
Year ended December 31, 2005
Allowance for doubtful receivables	$	146	$	184	$	-		$	330
Year ended December 31, 2006
Allowance for doubtful receivables	$	330	$	70	$	-		$	400
Year ended December 31, 2007
Allowance for doubtful receivables	$	400	$	4,370	$	(2,936	)	$	1,834

18. Subsequent Events (Unaudited)

On January 4, 2008, Bronco MENA Investments LLC, one of the Company’s wholly-owned subsidiaries closed a transaction with Challenger Limited, which the Company refers to as Challenger, a company organized under the laws of the Isle of Man, and certain of its affiliates to acquire a 25% equity interest in Challenger in exchange for six drilling rigs and $5.0 million in cash.  Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with principal operations in Libya.  In a separate transaction the Company sold to Challenger four drilling rigs and ancillary equipment for $12.0 million, payable in installments. The transactions were completed on January 4, 2008.  Prior to these transactions, Challenger owned a fleet of 23 rigs.

On January 24, 2008, the Company announced that we had entered into an agreement and plan of merger, dated January 23, 2008 with Allis-Chalmers, Bronco and Elway Merger Sub, providing for the acquisition of Bronco by Allis-Chalmers.

Under the terms of the merger agreement, which was approved by the respective boards of directors of each of the Company, Allis-Chalmers and Merger Sub, Merger Sub will merge with and into the Company, with the Company surviving as a wholly owned subsidiary of Allis-Chalmers.  The merger agreement provides that, at the effective time of the merger, Bronco stockholders will receive merger consideration with an aggregate value of approximately $437.8 million, comprised of (a) an aggregate of $280.0 million in cash and (b) shares of Allis-Chalmers common stock having an aggregate value of approximately $157.8 million. The number of shares issued as merger consideration will be based on the average closing price of Allis-Chalmers common stock for a ten trading day period ending two days prior to the closing.  Allis Chalmers will also assume all of the outstanding debt of Bronco, which totaled $68.1 million at December 31, 2007. The affirmative vote of a majority of the votes cast on this matter is required to consummate the merger.

Three of the Company’s stockholders have separately filed complaints seeking class action status relating to the merger.  Two actions were filed in the District Court of Oklahoma County in the State of Oklahoma on January 29, 2008 and February 28, 2008, respectively.  The defendants named in the first Oklahoma complaint are Bronco, the Bronco board of directors, Allis-Chalmers and Merger Sub while the defendants named in the second Oklahoma complaint are Bronco, the Bronco board of directors and Allis-Chalmers.  The third action was filed in the Court of Chancery in the State of Delaware on January 29, 2008.  The defendants named in the Delaware complaint are Bronco, the Bronco board of directors and Allis-Chalmers.  The plaintiff in the first Oklahoma complaint has filed a motion for expedited discovery.  The complaints generally allege that the merger consideration is inadequate and that the Bronco board of directors has breached its fiduciary duties.  The second Oklahoma complaint also alleges that the joint proxy statement/prospectus included as part of Allis-Chalmers’ registration statement on Form S-4 filed with the SEC on February 20, 2008 contains materially incomplete and misleading information. The actions generally seek to enjoin the merger, cause the Bronco board of directors to undertake an auction for Bronco or otherwise take action to maximize stockholder value, award monetary damages to the stockholders of Bronco and, in the case of the two Oklahoma complaints, rescind the transaction (to the extent that it is consummated).  The claims against Allis-Chalmers seek monetary damages.  Answers to the complaints are not yet due, although a motion to dismiss the first Oklahoma proceeding has been filed by Bronco.  Bronco intends to vigorously defend these actions.  As of this time, no order has been issued in either proceeding that would preclude the consummation of the merger.  Each of Allis-Chalmers and Bronco has the right to terminate the merger agreement in the event a court enjoins the consummation of the merger.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Bronco Drilling Company, Inc. has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

	BRONCO DRILLING COMPANY, INC.
Date: March 17, 2008	By:	/S/    D. FRANK HARRISON
		D. Frank Harrison Chief Executive Officer

Power of Attorney

Each of the persons whose signature appears below hereby constitutes and appoints D. Frank Harrison, Zachary M. Graves and Mark Dubberstein, and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, from such person and in each person’s name, place and stead, in any and all capacities, to sign the Form 10-K filed herewith and any and all amendments to said Form 10-K, with all exhibits thereto and all documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of Bronco Drilling Company, Inc. and in the capacities and on the dates indicated.

Name	Title	Date
/S/    D. FRANK HARRISON         D. Frank Harrison	Chief Executive, President and Director (Principal Executive Officer)	March 17, 2008
/S/    ZACHARY M. GRAVES         Zachary M. Graves	Chief Financial Officer (Principal Accounting and Financial Officer)	March 17, 2008
/S/    MIKE LIDDELL         Mike Liddell	Director	March 17, 2008
/S/    DAVID L. HOUSTON         David L. Houston	Director	March 17, 2008
/S/    GARY HILL Gary Hill	Director	March 17, 2008
/S/    WILLIAM R. SNIPES         William R. Snipes	Director	March 17, 2008

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