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, 2008




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 RegisteredCommon
      Stock $0.01 Par Value per Share
            
            The
      Nasdaq Stock Market LLCSecurities
      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 (based on the closing price on the Nasdaq Stock Market on June 30, 2008)
was approximately $480,662,493.




As of
February 27, 2009, 27,217,459 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 2009 Annual Meeting of our stockholders
which will be filed with the Securities and Exchange Commission not later than
120 days after December 31, 2008.





-2-
 Table of Contents







BRONCO
DRILLING COMPANY, INC.




INDEX


Item
              No.
            
            Form
              10-K
              Report
              PageCautionary Note Regarding Forward-Looking
      Statements
            4PART I1.
            Business
            41A.
            Risk Factors
            91B.
            Unresolved Staff Comments
            142.
            Properties
            143.
            Legal Proceedings
            154.
            Submission of Matters to a Vote of Security
      Holders
            15PART II5.
            Market for Registrant’s Common Equity, Related Stockholder
      Matters and Issuer Purchases of Equity Securities
            156.
            Selected Financial Data
            167.
            Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
            177A.
            Quantitative and Qualitative Disclosures About Market
      Risk
            248.
            Financial Statements and Supplementary
    Data
            249.
            Changes in and Disagreements with Accountants on Accounting
      and Financial Disclosure
            249A.
            Controls and Procedures
            249B.
            Other Information
            26PART III10.
            Directors and Executive Officers and Corporate
      Governance
            2611.
            Executive Compensation
            2612.
            Security Ownership of Certain Beneficial Owners and
      Management and Related Stockholder Matters
            2613.
            Certain Relationships and Related Transactions, and
      Director Independence
            2614.
            Principal Accounting Fees and Services
            26PART IV2715.
            Exhibits and Financial Statement
    Schedules





-3-
 Table of Contents





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 independent and major oil and
natural gas exploration and production companies throughout the United States
and internationally in Mexico.   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 2008. 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 two 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.  As of February 28, 2009, we also owned a fleet of 63 trucks
used to transport our rigs.




We currently
conduct our operations through two operating segments: our contract land
drilling and our well servicing segments.  The following is a
description of these two segments.




Contract Land
Drilling – Our contract land drilling segment provides contract land
drilling services with its fleet of 56 drilling rigs.  As of February
28, 2009, we owned a fleet of 56 land drilling rigs, of which 45 drilling rigs
were marketed, and 11 drilling rigs were held in inventory.  We
currently operate our drilling rigs in Oklahoma, Texas, Colorado, Utah, North
Dakota,  Louisiana, and Mexico.  A majority of the wells we
drill for our customers are drilled in unconventional basins also known as
resource plays.  These plays are generally characterized by complex
geologic formations that often require higher horsepower, premium rigs and
experienced crews to reach targeted depths. Our current fleet of 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 and have the capability of drilling horizontal and
directional 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.




Well Servicing
– Our 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.  As of February 28, 2009 we owned a fleet of 61
workover rigs, of which 52 workover rigs were marketed, and nine rigs were
undergoing refurbishment.  Our workover rigs are currently operating
in Oklahoma, Texas, Kansas, Colorado, Louisiana, and New Mexico.





Financial
information about our operating segments is included in Note 10, Business Segments and
Concentrations, of the Notes to Consolidated Financial
Statements.




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





In May 2002,
we purchased seven drilling rigs ranging in size from 400 to 950 horsepower,
associated spare parts and equipment, drill pipe, haul trucks and vehicles from
Bison Drilling L.L.C. and Four Aces Drilling L.L.C.







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




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




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




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




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


-4-
 Table of Contents





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:


ApproximateDrillingRig
            
            Design
            Depth
      (ft)
            Type
            Horsepower3
            
            Cabot
      900
            10,000
            Mechanical
            95018
            
            Gardner
      Denver 1500E
            25,000
            Electric
            2,00019
            
            Mid
      Continent U-1220 EB
            25,000
            Electric
            2,00038
            
            National
      1320
            25,000
            Electric
            2,00093
            
            National
      T-32
            8,000
            Mechanical
            50096
            
            Ideco
      H-35
            8,000
            Mechanical
            400


In a separate
transaction, we sold to Challenger four additional drilling rigs and ancillary
equipment for $13.0 million, payable in installments over thirty-six
months.  The general specifications of the sold rigs are as
follows:





ApproximateDrillingRig
            
            Design
            Depth
      (ft)
            Type
            Horsepower91
            
            Ideco
      H-35
            8,000
            Mechanical
            45092
            
            Weiss
      45
            8,000
            Mechanical
            50094
            
            Unit
      U-15
            9,000
            Mechanical
            65095
            
            Emsco
      GB800
            12,000
            Mechanical
            1,000




We reviewed
our investment in Challenger at December 31, 2008 for impairment based on the
guidance of APB Opinion No. 18, The Equity Method of Accounting for
Investments in Common Stock,which states that a loss in value of an
investment which is an other than temporary decline should be
recognized.  Evidence of a loss in value might include the absence of
an ability to recover the carrying amount of the investment or inability of the
investee to sustain an earnings capacity which would justify the carrying amount
of the investment.  A current fair value of an investment that is less
than its carrying amount may indicate a loss in value of the
investment.  Due to the recent volatility and decline in oil and
natural gas prices, a deteriorating global economic environment and the
anticipated future earnings of Challenger, we deemed it necessary to test the
investment for impairment. Fair value of the investment was estimated using a
combination of income, or discounted cash flows approach and the market
approach, which utilizes comparable companies’ data.  The analysis
resulted in a fair value of $62.9 million related to our investment in
Challenger, which was below the carrying value of the investment and resulted in
a non-cash impairment charge in the amount of $14.4 million.




Overview
of Our Segments




Contract
Land Drilling




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




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




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




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




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




As of
February 28, 2009, our drilling rig fleet consisted of 56 drilling rigs, of
which 45 were marketed, and 11 were held in inventory.  Fifteen of our
drilling rigs were operating on term contracts ranging from one to two
years.  Thirty-two of these drilling rigs have undergone significant
refurbishment since October 2003 by us or the parties from which the rigs were
purchased.  The following table sets forth information regarding
utilization for our fleet of marketed drilling rigs:





Year
      Ended December 31,2008
            
            
            2007
            
            
            2006Average
      number of operating drilling rigs
            
            
            44
            
            
            
            51
            
            
            
            45Revenue
      days
            
            
            12,712
            
            
            
            14,245
            
            
            
            15,202Utilization
      Rates
            
            
            79
            %
            
            
            76
            %
            
            
            93
            %




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.  We also own
a fleet of 63 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.




-5-
 Table of Contents





As a provider
of contract land drilling services, our business and the profitability of our
operations depend on the level of drilling activity by oil and natural gas
exploration and production companies operating in the geographic markets where
we operate. The oil and natural gas exploration and production industry is a
historically cyclical industry characterized by significant changes in the
levels of exploration and development activities. Oil and gas prices have
declined significantly during recent months in a deteriorating national and
global economic environment.  The current economic environment and the
recent decline in commodity prices has caused us to reduce our overall
level of drilling activity and spending.  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.  During the fourth quarter of 2008, the Company recorded $3.6
million of contract drilling revenue related to terminated
contracts.




The following
table presents, by type of contract, information about the total number of wells
we completed for our customers during the years ended December 31, 2008,
2007 and 2006.





Years
      Ended December 31,2008
            
            
            2007
            
            
            2006Daywork
      Contracts
            
            
            378
            
            
            
            430
            
            
            
            449Footage
      Contracts
            
            
            -
            
            
            
            3
            
            
            
            1Turnkey
      Contracts
            
            
            -
            
            
            
            -
            
            
            
            -Total
            
            
            378
            
            
            
            433
            
            
            
            450


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.





Well
Servicing




Our well
servicing segment encompasses a full range of services performed with a drilling
rig; mobile well servicing rig, also commonly referred to as a workover rig; and
ancillary equipment. Our rigs and personnel provide the means for hoisting
equipment and tools into and out of the well bore, and our well servicing
equipment and capabilities are essential to facilitate most other services
performed on a well. Our well servicing segment services, which are performed to
maintain and improve production throughout the productive life of an oil and gas
well, include:





·
              Maintenance
      work involving removal, repair and replacement of down-hole equipment and
      returning the well to production after these operations are
      completed;


·
              Hoisting
      tools and equipment required by the operation into and out of the well, or
      removing equipment from the well bore, to facilitate specialized
      production enhancement and well repair operations performed by other
      oilfield service companies;


·
              Plugging
      and abandonment services when a well has reached the end of its productive
      life; and


·
              Completion
      work involving selectively perforating the well casing at the depth of
      discrete producing zones, stimulating and testing these zones and
      installing down-hole
equipment.


·


We generally
charge our customers an hourly rate for these services, which varies based on a
number of considerations including market conditions in each region, the type of
rig and ancillary equipment required, and the necessary
personnel.


Our fleet
includes 61 well servicing rigs as of February 28, 2009, including 37
newbuilds since January 2007. Our well servicing rigs operate in Oklahoma,
Texas, Kansas, Colorado, Louisiana, and New Mexico.


Maintenance.  Regular
maintenance is generally required throughout the life of a well to sustain
optimal levels of oil and gas production. We believe regular maintenance
comprises the largest portion of our work in this business segment. We provide
well service rigs, equipment and crews for these maintenance services.
Maintenance services are often performed on a series of wells in proximity to
each other. These services consist of routine mechanical repairs necessary to
maintain production, such as repairing inoperable pumping equipment in an oil
well or replacing defective tubing in a gas well, and removing debris such as
sand and paraffin from the well. Other services include pulling the rods,
tubing, pumps and other downhole equipment out of the well bore to identify and
repair a production problem. These downhole equipment failures are typically
caused by the repetitive pumping action of an oil well. Corrosion, water cut,
grade of oil, sand production and other factors can also result in frequent
failures of downhole equipment.


The need for
maintenance activity does not directly depend on the level of drilling activity,
although it is impacted by fluctuations in oil and gas prices. Additionally,
demand for our maintenance services is affected by changes in the total number
of producing oil and gas wells in our geographic service
areas.


Our regular
well maintenance services involve relatively low-cost, short-duration jobs which
are part of normal well operating costs. Demand for well maintenance is driven
primarily by the production requirements of the local oil or gas fields and, to
a lesser degree, the actual prices received for oil and gas. Well operators
cannot delay all maintenance work without a significant impact on production.
Operators may, however, choose to temporarily shut in producing wells when oil
or gas prices are too low to justify additional expenditures, including
maintenance.


Workover.  In
addition to periodic maintenance, producing oil and gas wells occasionally
require major repairs or modifications called workovers, which are typically
more complex and more time consuming than maintenance operations. Workover
services include extensions of existing wells to drain new formations either
through perforating the well casing to expose additional productive zones not
previously produced, deepening well bores to new zones or the drilling of
lateral well bores to improve reservoir drainage patterns. Our workover rigs are
also used to convert former producing wells to injection wells through which
water or carbon dioxide is then pumped into the formation for enhanced oil
recovery operations. Workovers also include major subsurface repairs such as
repair or replacement of well casing, recovery or replacement of tubing and
removal of foreign objects from the well bore. These extensive workover
operations are normally performed by a workover rig with additional specialized
auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud
tanks and fishing tools, depending upon the particular type of workover
operation. Most of our well servicing rigs are designed to perform complex
workover operations. A workover may require a few days to several weeks and
generally requires additional auxiliary equipment. The demand for workover
services is sensitive to oil and gas producers’ intermediate and long-term
expectations for oil and gas prices. As oil and gas prices increase, the level
of workover activity tends to increase as oil and gas producers seek to increase
output by enhancing the efficiency of their wells. Exploration and Production
companies tend to reduce their budgets during a declining commodity price
environment, similarly to what we are experiencing currently, which can result
in a significant reduction in demand for our workover
services.


-6-
 Table of Contents
 
 New Well
Completion.  New well completion services involve the
preparation of newly drilled wells for production. The completion process may
involve selectively perforating the well casing in the productive zones to allow
oil or gas to flow into the well bore, stimulating and testing these zones and
installing the production string and other downhole equipment. We provide well
service rigs to assist in this completion process. Newly drilled wells are
frequently completed by well servicing rigs to minimize the use of higher cost
drilling rigs in the completion process. The completion process typically
requires a few days to several weeks, depending on the nature and type of the
completion, and generally requires additional auxiliary equipment. Accordingly,
completion services require less well-to-well mobilization of equipment and
generally provide higher operating margins than regular maintenance work. The
demand for completion services is directly related to drilling activity levels,
which are sensitive to expectations relating to and changes in oil and gas
prices.  Oil and natural gas producers attempt to maximize the
productivity of their wells in a higher priced environment.


Plugging and
Abandonment.  Well servicing rigs are also used in the process
of permanently closing oil and gas wells no longer capable of producing in
economic quantities. Plugging and abandonment work can be performed with a well
servicing rig along with wireline and cementing equipment; however, this service
is typically provided by companies that specialize in plugging and abandonment
work. Many well operators bid this work on a “turnkey” basis, requiring the
service company to perform the entire job, including the sale or disposal of
equipment salvaged from the well as part of the compensation received, and
complying with state regulatory requirements. Plugging and abandonment work can
provide favorable operating margins and is less sensitive to oil and gas pricing
than drilling and workover activity since well operators must plug a well in
accordance with state regulations when it is no longer productive. We perform
plugging and abandonment work throughout our core areas of operation in
conjunction with equipment provided by other service
companies.




Our well
servicing rig fleet has increased from a weighted average number of 24 rigs in
the first quarter of 2007 to 61 in the fourth quarter of 2008 due to
newbuild purchases.  We gauge activity levels in our well servicing rig
operations based on rig utilization rate. We compute operating workover rig
utilization rates by dividing revenue hours by total available hours during a
period. Total available hours are the number of hours during the period that we
have owned the operating workover rig based on a 50-hour work week per
rig.




For the years
ended December 31, 2008 and 2007, our workover rig utilization rates,
revenue hours and average number of operating workover rigs were as
follows:


Year
      Ended December 31,2008
                
                
                2007Average
      number of operating workover rigs
                
                
                52
                
                
                
                33Revenue
      hours
                
                
                91,591
                
                
                
                63,746Utilization
      Rates
                
                
                68
                %
                
                
                78
                %
 Customers
and Marketing
  We market our
drilling and workover rigs to a number of major and independent oil and gas
companies that are active in the geographic areas in which we operate. The
following table shows our customers that accounted for more than 5% of our total
revenue for each of our last three years.   In the opinion of
management, the loss of any of our customers individually would not have a
material adverse effect on our business.


Customer
            
            Total
      Revenue Percentage2008Antero
      Resources
            
            
            11
            %XTO
      Energy
            
            
            7
            %JMA
      Energy Company, LLC
            
            
            5
            %Pablo
      Energy II, LLC
            
            
            5
            %2007Antero
      Resources
            
            
            11
            %Chesapeake
      Energy Corporation
            
            
            8
            %Comstock
      Oil and Gas
            
            
            7
            %XTO
      Energy
            
            
            6
            %Pablo
      Energy II, LLC
            
            
            5
            %2006Chesapeake
      Energy Corporation
            
            
            7
            %Comstock
      Oil and Gas
            
            
            5
            %




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





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





Competition




Contract
Land Drilling




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




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


-7-
 Table of Contents




•
            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.





Well
      Servicing


The market
for well servicing is highly competitive.  Competition is influenced
by such factors as price, capacity, availability of work crews, type and
condition of equipment and reputation and experience of the service
provider.  We believe that pricing is generally the primary factor in
determining which service provider is awarded the work.  Our
competition includes small regional contractors as well as larger companies with
international operations. Our principal competitors are Key Energy Services,
Nabors Industries and Complete Production Services. These competitors operate in
most of the large oil and gas producing regions in the U.S.  In
addition, there are numerous smaller companies that compete in our well service
markets.


Raw
Materials




The materials
and supplies we use in our drilling and well service operations include fuels to
operate our drilling and well service 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 and well servicing business, including the risks of:




•
            blowouts;




•
            fires
      and explosions;




•
            loss
      of well control;




•
            collapse
      of the borehole;




•
            lost
      or stuck drill strings; and




•
            damage
      or loss from natural disasters.




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




•
            suspension
      of drilling operations;




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




•
            personal
      injury and loss of life;




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




•
            environmental
      damage.




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




Our insurance
coverage includes property insurance on our rigs, drilling equipment and real
property. Our insurance coverage for property damage to our rigs and to our
drilling equipment is based on a third party estimate of the appraised value of
the rigs and drilling equipment. The policy provides for a deductible on
drilling rigs of $1.0 million per occurrence and $50,000 per occurrence for
workover rigs. Our umbrella liability insurance coverage is $25.0 million per
occurrence and in the aggregate, with a deductible of $10,000 per occurrence. We
believe that we are adequately insured for public liability and property damage
to others with respect to our operations. However, such insurance may not be
sufficient to protect us against liability for all consequences of well
disasters, extensive fire damage or damage to the environment.




Employees




As of
February 27, 2009, we had 1,059 employees. Approximately 222 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 can occur in
our industry. If we should suffer any material loss of personnel to competitors
or be unable to employ additional or replacement personnel with the requisite
level of training and experience to adequately operate our equipment, our
operations could be materially and adversely affected. While we believe our wage
rates are competitive and our relationships with our employees are satisfactory,
a significant increase in the wages paid by other employers could result in a
reduction in our workforce, increases in wage rates, or both. The occurrence of
either of these events for a significant period of time could have a material
and adverse effect on our financial condition and results of
operations.




Governmental
Regulation




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


-8-
 Table of Contents





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




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




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




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




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




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




Available
Information




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




Item 1A. Risk Factors




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




Risks
Relating to the Oil and Natural Gas Industry




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




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




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




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




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




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




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




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




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




•
            economic
      conditions in the United States and
elsewhere;




•
            governmental
      regulations, both domestic and
foreign;




•
            domestic
      and foreign tax policy;




•
            weather
      conditions in the United States and
elsewhere;




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




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




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




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




•
            our
      revenues, cash flows and
profitability;


-9-
 Table of Contents




•
            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.




During 2008,
the monthly average market price of natural gas peaked in June at $13.06 per Mcf
before rapidly declining to an average of $5.99 per Mcf in
December.  In January 2009, the average market price of natural gas
declined further to $5.40 per Mcf.  This decline in the market price
of natural gas has resulted in our customers significantly reducing their
drilling and well servicing activities beginning in the fourth quarter of 2008
and continuing into 2009.  This reduction in demand combined with the
reactivation and construction of new land drilling and workover rigs in the
United States during the last several years has resulted in excess capacity
compared to demand.  Tightening credit markets have also reduced our
customer’s ability to fund drilling programs.  As a result of these
factors, our average number of operating drilling and workover rigs has recently
declined significantly.  We expect oil and natural gas prices to
continue to be volatile and to affect our financial condition, operations and
ability to access sources of capital.  Continued low market prices for
natural gas and economic conditions that have eroded residential and commercial
demand for oil and natural gas will likely result in further decreases in demand
for our drilling and workover rigs and adversely affect our operating
results.




Risks
Relating to Our Business





Global
economic conditions may adversely affect our operating results.




Oil and
natural gas prices, and market expectations of potential changes in these
prices, significantly impact the level of worldwide drilling and well servicing
activities.  During recent months, there has been a significant
decline in oil and natural gas prices.  During this time there has
also been a significant deterioration in the global economic
environment.  As part of this deterioration, there has been
significant uncertainty in the capital markets and access to financing has been
reduced.  As a result of these conditions, customers have recently
started reducing or curtailing their drilling and well servicing programs, which
is resulting in a significant decrease in demand for our
services.  Furthermore, these factors could result in certain of our
customers experiencing an inability to pay suppliers, including us, if they are
not able to access capital to fund their operations.  These conditions
could have a material adverse effect on our business, financial condition, cash
flows and results of operations.  The following table depicts the
prices for near month delievery contracts for crude oil and natural gas as
traded on the NYMEX.




Natural
      Gas Priceper
      Mcf
            
            
            Oil
      Price per BblQuarter
            
            High
            
            
            Low
            
            
            High
            
            
            Low2009:First
      (through February 27, 2009)
            
            $
            6.07
            
            
            $
            4.01
            
            
            $
            48.81
            
            
            $
            33.982008:Fourth
            
            $
            7.73
            
            
            $
            5.29
            
            
            $
            98.53
            
            
            $
            33.87Third
            
            $
            13.58
            
            
            $
            7.22
            
            
            $
            145.29
            
            
            $
            95.71Second
            
            $
            13.35
            
            
            $
            9.32
            
            
            $
            140.21
            
            
            $
            100.98First
            
            $
            10.23
            
            
            $
            7.62
            
            
            $
            110.33
            
            
            $
            86.99




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




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




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




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




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




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




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




•
            an
      increase in our expenses and working capital
  requirements.




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




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




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




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


-10-
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Our
indebtedness could restrict our operations and make us more vulnerable to
adverse economic conditions.




As of
December 31, 2008, our total debt was approximately $117.5
million.




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




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








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




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




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




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






•
            increasing
      our vulnerability to rising interest
    rates.






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




•
            refinancing
      or restructuring our
  debt;




•
            selling
      assets;




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




•
            seeking
      to raise additional
  capital.






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




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




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




•
            limitations
      on the incurrence of additional
      indebtedness;




•
            restrictions
      on investments, mergers or consolidations, asset dispositions,
      acquisitions, transactions with affiliates and other transactions without
      lenders’ consent;
  and




•
            limitation
      on dividends and
    distributions.






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




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.


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


We currently
have rigs operating internationally in Mexico and a 25% investment in
Challenger, an Isle of Man company with its principal operations in
Libya.  Risks associated with our international operations and
Challenger’s contract land drilling and workover operations
include:




•
            terrorist
      acts, war and civil
      disturbances;


-11-
 Table of Contents




•
            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.




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




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




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





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




The fact that
drilling and workover rigs are mobile and can be moved from one market to
another in response to market conditions heightens the competition in the
industry.




The contracts
we compete for are usually awarded on the basis of competitive bids or direct
negotiations with customers. We believe pricing and quality of equipment are the
primary factors our potential customers consider in determining which service
provider to select. In addition, we believe the following factors are also
important:




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




•
            the
      mobility and efficiency of the
      rigs;




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




•
            the
      offering of ancillary services;
      and




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




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




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




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




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




•
            better
      withstand industry
      downturns;




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




•
            retain
      skilled rig personnel;
      and




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




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




For the years
ended December 31, 2008 and 2007, less than 1% of our total revenues were
derived from footage contracts. Under footage contracts, we are paid a fixed
amount for each foot drilled, regardless of the time required or the problems
encountered in drilling the well. We typically pay more of the out-of-pocket
costs associated with footage contracts as compared to daywork contracts. The
risks to us on a footage contract are greater because we assume most of the
risks associated with drilling operations generally assumed by the operator in a
daywork contract, including the risk of blowout, loss of hole, stuck drill pipe,
machinery breakdowns, abnormal drilling conditions and risks associated with
subcontractors’ services, supplies, cost escalation and personnel. The
occurrence of uninsured or under-insured losses or operating cost overruns on
our footage jobs could have a negative impact on our profitability. Similar to
our footage contracts, under turnkey contacts drilling companies assume most of
the risks associated with drilling operations that the operator generally
assumes under a daywork contract. Although we historically have not entered into
turnkey contracts, if we were to enter into a turnkey contract or acquire such a
contract in connection with future acquisitions, the occurrence of uninsured or
under-insured losses or operating cost overruns on such a job could negatively
impact our profitability.




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




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




•
            blowouts;




•
            fires
      and
      explosions;




•
            loss
      of well
      control;




•
            collapse
      of the
      borehole;




•
            lost
      or stuck drill strings;
      and




•
            damage
      or loss from natural
      disasters.


-12-
 Table of Contents





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




•
            suspension
      of
      operations;




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




•
            personal
      injury and loss of
      life;




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




•
            environmental
      damage.





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




We
face increased exposure to operating difficulties because we 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 can occur in our industry. As a result of
the volatility of the oil and natural gas industry and the demanding nature of
the work, potential employees may choose to pursue employment in fields that
offer a more desirable work environment at wage rates that are competitive with
ours. If we should suffer any material loss of personnel to competitors or be
unable to employ additional or replacement personnel with the requisite level of
training and experience to adequately operate our equipment, our operations
could be materially and adversely affected. With a reduced pool of workers, it
is possible that we will have to raise wage rates to attract workers from other
fields and to retain our current employees. If we are not able to increase our
service rates to our customers to compensate for wage-rate increases, our
profitability and other results of operations may be adversely
affected.


-13-
 Table of Contents




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
Select Market, we cannot assure you that an active public market will continue
to exist for our common stock or that our common stock will continue to trade in
the public market at or above current prices. If an active public market for our
common stock does not continue, the trading price and liquidity of our common
stock will be materially and adversely affected.  If there is a thin
trading market or “float” for our stock, the market price for our common stock
may fluctuate significantly more than the stock market as a
whole.  Without a large float, our common stock is less liquid than
the stock of companies with broader public ownership and, as a result, the
trading price of our common stock may be more volatile.  In addition,
in the absence of an active public trading market, investors may be unable to
liquidate their investment in us.  In addition, the stock market is
subject to significant price and volume fluctuations, and the price of our
common stock could fluctuate widely in response to several factors,
including:




•
            our
      quarterly operating
      results;




•
            changes
      in our earnings
      estimates;




•
            additions
      or departures of key
      personnel;




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




•
            changes
      in general market or economic conditions;
      and




•
            announcements
      of legislative or regulatory
      change.






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




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




If a large
number of shares of our common stock is sold in the open market, the trading
price of our common stock could decrease. As of December 31, 2008, we had
an aggregate of 71,491,671 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.




•
            announcements
      of legislative or regulatory
      change.






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




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




Item 1B. Unresolved Staff Comments




None.




Item 2. Property




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


-14-
 Table of Contents




Item 3. Legal Proceedings




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




On November
17, 2008, our annual meeting of stockholders was held in Duncan,
Oklahoma.  A total of 23,658,458 of our shares of common stock were
present or represented by proxy at the annual meeting.  This
represented more than 88% of our shares outstanding on the record
date.  At the meeting, our stockholders voted on the election of five
persons to serve as our directors.  Each of the five nominees, D.
Frank Harrison, , Gary C. Hill, David W. House, David L. Houston and William R.
Snipes, was elected as a director to serve until our next annual meeting of
stockholders and until his successor is duly elected and
qualified.  The results of the tabulation of the votes cast at our
annual meeting are as follows:





Proposal
      – Election of Directors
              
              Name
            
            For
      (#)
            
            Withheld
      (#)D.
      Frank Harrison
            
            22,658,654
            
            999,804Dr.
      Gary C. Hill
            
            22,620,803
            
            1,037,655David
      W. House
            
            22,979,073
            
            679,385David
      L. Houston
            
            22,620,338
            
            1,038,120William
      R. Snipes
            
            22,407,406
            
            1,251,052








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 Select 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
            
            
            LowYear
      Ending December 31, 2005:Third
      Quarter (since August 16, 2005)
            
            $
            30.00
            
            
            $
            18.00Fourth
      Quarter
            
            $
            29.10
            
            
            $
            20.97Year
      Ending December 31, 2006:First
      Quarter
            
            $
            32.00
            
            
            $
            22.50Second
      Quarter
            
            $
            29.57
            
            
            $
            17.50Third
      Quarter
            
            $
            21.41
            
            
            $
            16.01Fourth
      Quarter
            
            $
            19.69
            
            
            $
            15.25Year
      Ending December 31, 2007:First
      Quarter
            
            $
            17.20
            
            
            $
            13.53Second
      Quarter
            
            $
            19.21
            
            
            $
            15.37Third
      Quarter
            
            $
            16.67
            
            
            $
            13.58Fourth
      Quarter
            
            $
            16.04
            
            
            $
            13.10Year
      Ending December 31, 2008:First
      Quarter
            
            $
            16.25
            
            
            $
            11.21Second
      Quarter
            
            $
            18.69
            
            
            $
            16.04Third
      Quarter
            
            $
            18.60
            
            
            $
            9.80Fourth
      Quarter
            
            $
            10.32
            
            
            $
            3.63Year
      Ending December 31, 2009:First
      Quarter (through February 27, 2009)
            
            $
            6.68
            
            
            $
            4.05




On February
27, 2009, the last reported sale price of our common stock on The Nasdaq Global
Select Market was $4.06 and we had approximately 30,000 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, 2008 with respect to shares of our
common stock that may be issued under on our equity compensation
plan:


Number
      of securitiesremaining
      available forNumber
      of securities to be
            
            Weighted-average
            
            future
      issuance under equityissued
      upon exercise of
            
            exercise
      price per share
            
            compensation
      plansoutstanding
      options,
            
            of
      outstanding options,
            
            (excluding
      securitiesPlan
      category
            
            warrants
      and rights
            
            warrants
      and rights
            
            reflected
      in column (a))(a)
            
            (b)
            
            (c)Equity
      compensation plans approvedby
      security holdersEquity
      compensation plans not approvedby
      security holders
            
            -
            
            -
            
            --
            
            $                                        -
            
            -


-15-
 Table of Contents




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 2008, 2007, 2006, 2005, and 2004 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)2008
            
            2007
            
            
            2006
            
            
            2005
            
            2004Consolidated
      Statements of OperationsInformation:Contract
      drilling revenues
            
            $
            247,829
            
            
            $
            276,088
            
            
            $
            285,828
            
            
            $
            77,885
            
            $           21,873Well
      service
            
            
            33,284
            
            
            
            22,864
            
            
            
            -
            
            
            
            -
            
            -Gain
      on Challenger transactions
            
            
            3,138
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            -284,251
            
            
            
            298,952
            
            
            
            285,828
            
            
            
            77,885
            
            21,873Costs
      and expenses:Contract
      drilling
            
            
            148,866
            
            
            
            153,797
            
            
            
            139,607
            
            
            
            44,695
            
            18,670Well
      service
            
            
            24,478
            
            
            
            14,299
            
            
            
            -
            
            
            
            -
            
            -Depreciation
      and amortization
            
            
            50,388
            
            
            
            44,241
            
            
            
            30,335
            
            
            
            9,143
            
            3,695General
      and administrative
            
            
            33,771
            
            
            
            22,690
            
            
            
            15,709
            
            
            
            9,395
            
            1,714Impairment
      of goodwill
            
            
            24,328
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            -Total
      operating costs and expenses
            
            
            281,831
            
            
            
            235,027
            
            
            
            185,651
            
            
            
            63,233
            
            24,079Income
      (loss) from operations
            
            
            2,420
            
            
            
            63,925
            
            
            
            100,177
            
            
            
            14,652
            
            (2,206)Other
      income (expense):Interest
      expense
            
            
            (4,171)
            
            
            
            (4,762)
            
            
            
            (1,736)
            
            
            
            (1,415)
            
            (285)Loss
      from early extinguishment of debt
            
            
            (155)
            
            
            
            -
            
            
            
            (1,000)
            
            
            
            (2,062)
            
            -Interest
      income
            
            
            1,058
            
            
            
            1,239
            
            
            
            164
            
            
            
            432
            
            10Equity
      in income of Challenger
            
            
            2,186
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            -Impairment
      of investment in Challenger
            
            
            (14,442)
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            -Other
      income (expense):
            
            
            (300)
            
            
            
            294
            
            
            
            284
            
            
            
            53
            
            -Total
      other income (expense)
            
            
            (15,824)
            
            
            
            (3,229)
            
            
            
            (2,288)
            
            
            
            (2,992)
            
            (275)Income
      (loss) before income taxes
            
            
            (13,404)
            
            
            
            60,696
            
            
            
            97,889
            
            
            
            11,660
            
            (2,481)Income
      tax expense (benefit)
            
            
            (5,161)
            
            
            
            23,104
            
            
            
            38,056
            
            
            
            6,529
            
            285Net
      income (loss)
            
            $
            (8,243)
            
            
            $
            37,592
            
            
            $
            59,833
            
            
            $
            5,131
            
            $           (2,766)Income
      (loss) per common share-Basic
            
            $
            (0.31)
            
            
            $
            1.45
            
            
            $
            2.43
            
            
            $
            0.32Income
      (loss) per common share-Diluted
            
            $
            (0.31)
            
            
            $
            1.44
            
            
            $
            2.43
            
            
            $
            0.31Weighted
      average number of shares outstanding-Basic
            
            
            26,293
            
            
            
            25,996
            
            
            
            24,585
            
            
            
            16,259Weighted
      average number of shares outstanding-Diluted
            
            
            26,293
            
            
            
            26,101
            
            
            
            24,623
            
            
            
            16,306Pro
      Forma C Corporation Data (Unaudited): (1)Historical
      income (loss)before
      income taxes
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            11,660
            
            $           (2,481)Pro
      forma provision (benefit) for incometaxes
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            4,396
            
            (935)Pro
      forma income (loss)
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            7,264
            
            $           (1,546)Pro
      forma income (loss) per common share basic and diluted
            
            
            
            
            
            
            
            
            
            
            
            
            
            $
            0.45
            
            $             (0.12)Weighted
      average pro forma shares outstanding-Basic
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            16,259
            
            13,360Weighted
      average pro forma shares outstanding-Diluted
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            16,306
            
            13,360Other
      Financial Data (Unaudited):Calculation
      of EBITDA (2):Net
      income (loss)
            
            $
            (8,243)
            
            
            $
            37,592
            
            
            $
            59,833
            
            
            $
            5,131
            
            $           (2,766)Interest
      expense
            
            
            4,171
            
            
            
            4,762
            
            
            
            1,736
            
            
            
            1,415
            
            285Income
      tax expense
            
            
            (5,161)
            
            
            
            23,104
            
            
            
            38,056
            
            
            
            6,529
            
            285Depreciation
      and amortization
            
            
            50,388
            
            
            
            44,241
            
            
            
            30,335
            
            
            
            9,143
            
            3,695Impairment
      of goodwill
            
            
            24,328
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            -Impairment
      of investment in Challenger
            
            
            14,442
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            -EBITDA
      (2)
            
            $
            79,925
            
            
            $
            109,699
            
            
            $
            129,960
            
            
            $
            22,218
            
            $             1,499Consolidated
      Cash Flow Information:Net
      cash provided by (used in):Operating
      activities
            
            $
            59,100
            
            
            $
            82,607
            
            
            $
            93,053
            
            
            $
            3,318
            
            $             2,364Investing
      activities
            
            
            (82,795)
            
            
            
            (79,984)
            
            
            
            (143,199)
            
            
            
            (190,326)
            
            (19,511)Financing
      activities
            
            
            44,650
            
            
            
            (7,510)
            
            
            
            43,715
            
            
            
            202,908
            
            16,623As
      of December 31,2008
            
            2007
            
            
            2006
            
            
            2005
            
            2004Consolidated
      Balance Sheet Information:Total
      current assets
            
            $
            107,821
            
            
            $
            72,019
            
            
            $
            73,372
            
            
            $
            53,953
            
            $             8,118Total
      assets
            
            
            612,354
            
            
            
            568,605
            
            
            
            482,488
            
            
            
            330,520
            
            90,143Total
      debt
            
            
            117,547
            
            
            
            68,118
            
            
            
            64,727
            
            
            
            51,825
            
            18,100Total
      liabilities
            
            
            218,343
            
            
            
            172,176
            
            
            
            142,503
            
            
            
            91,184
            
            39,340Total
      stockholders'/members' equity
            
            
            394,011
            
            
            
            396,429
            
            
            
            339,985
            
            
            
            239,336
            
            50,803


-16-
 Table of Contents


(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,
      depreciation, amortization and impairment. 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 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.




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




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




Overview




We
provide contract land drilling and workover services to independent and major
oil and gas exploration and production companies throughout the United States
and internationally in Mexico. We commenced operations in 2001 with the purchase
of one stacked 650-horsepower drilling rig that we reburbished 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 2008. 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 two
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.  As of February 28, 2009, we also owned a fleet
of 63 trucks used to transport our rigs.




Business
Segments




We currently
conduct our operations through two operating segments: our Contract Land
Drilling segment and our Well Servicing segment.  The following is a
description of these two operating segments.  Financial information
about our operating segments is included in Note 10, Business Segments and
Concentrations , of the Notes to Consolidated Financial Statements,
included in Part II, Item 8, Financial Statements and
Supplementary Data,of this Annual Report on Form 10-K.




Contract Land
Drilling -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 15 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 that we use to evaluate this segment is operating rig
utilization. We compute operating drilling rig utilization rates by dividing
revenue days by total available days during a period. Total available days are
the number of calendar days during the period that we have owned the operating
rig. Revenue days for each operating rig are days when the rig is earning
revenues under a contract, i.e. when the rig begins moving to the drilling
location until the rig is released from the contract. On daywork contracts,
during the mobilization period we typically receive a fixed amount of revenue
based on the mobilization rate stated in the contract. We begin earning our
contracted daywork rate and mobilization revenue when we begin drilling the
well. Occasionally, in periods of increased demand, we will receive a percentage
of the contracted dayrate during the mobilization period. We account for these
revenues as mobilization fees.




For the years
ended December 31, 2008, 2007, and 2006, our drilling rig utilization
rates, revenue days and average number of operating drilling rigs were as
follows:





Year
      Ended December 31,2008
            
            
            2007
            
            
            2006Average
      number of operating drilling rigs
            
            
            44
            
            
            
            51
            
            
            
            45Revenue
      days
            
            
            12,712
            
            
            
            14,245
            
            
            
            15,202Utilization
      Rates
            
            
            79
            %
            
            
            76
            %
            
            
            93
            %




The decrease
in the number of revenue days in 2008 is attributable to the decrease in the
average number of operating rigs due to the rigs contributed and sold to
Challenger.  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. We devote
substantial resources to maintaining, upgrading and expanding our rig fleet. We
substantially completed the refurbishment of three drilling rigs in 2007 and 12
drilling rigs in 2006.


Well Servicing –Our well servicing segment provides a broad range of well services to oil
and gas drilling and producing companies, including maintenance, workover, new
well completion and plugging and abandonment.  We provide
maintenance-related services as part of the normal, periodic upkeep of producing
oil and gas wells. Maintenance-related services represent a relatively
consistent component of our business. Workover and completion services generate
more revenue per hour than maintenance work due to the use of auxiliary
equipment, but demand for workover and completion services fluctuates more with
the overall activity level in the industry.




The Company
earns well servicing revenue based on purchase orders, contracts or other
persuasive evidence of an arrangement with the customer, such as a master
service agreement, that include fixed or determinable prices.  We
generally charge our customers an hourly rate for these services, which varies
based on a number of considerations including market conditions in each region,
the type of rig and ancillary equipment required, and the necessary
personnel.




Our well
servicing rig fleet has increased from a weighted average number of 24 rigs in
the first quarter of 2007 to 61 in the fourth quarter of 2008 due to
newbuild purchases.  We gauge activity levels in our well servicing rig
operations based on rig utilization rate. We compute operating workover rig
utilization rates by dividing revenue hours by total available hours during a
period. Total available hours are the number of hours during the period that we
have owned the operating workover rig based on a 50-hour work week per
rig.




For the years
ended December 31, 2008 and 2007, our workover rig utilization rates,
revenue hours and average number of operating workover rigs were as
follows:





Year
      Ended December 31,2008
            
            
            2007Average
      number of operating workover rigs
            
            
            52
            
            
            
            33Revenue
      hours
            
            
            91,591
            
            
            
            63,746Utilization
      Rates
            
            
            68
            %
            
            
            78
            %





Market
Conditions in Our Industry




The United
States contract land drilling and well servicing industry is highly cyclical.
Volatility in oil and natural gas prices can produce wide swings in the levels
of overall drilling and well servicing activity in the markets we serve and
affect the demand for our drilling and workover services and the revenue rates
we can charge for our drilling and workover rigs. The availability of financing
sources, past trends in oil and natural gas prices and the outlook for future
oil and natural gas prices strongly influence the capital expenditure budgets of
exploration and production companies.


-17-
 Table of Contents





Our business
environment has been adversely affected by the recent volatility and decline in
oil and natural gas prices and the deteriorating global economic
environment.  As part of this deterioration, there has been
significant uncertainty in the capital markets and access to financing has been
reduced.  As a result of these conditions, our customers have
curtailed their exploration budgets, which is resulting in a significant
decrease in demand for our services, a reduction in revenue rates and
utilization.  During the fourth quarter of 2008, the Company recorded
$3.6 million of contract drilling revenue related to terminated
contracts.  Due to the current economic environment, certain customers
may not be able to pay suppliers, including us, if they are not able to access
capital to fund their business operations.




On February
27, 2009, the closing prices for near month delivery contracts for crude oil and
natural gas as traded on the NYMEX were $44.76 per barrel and $4.08 per MMbtu,
respectively. The Baker Hughes domestic land drilling rig count as of February
28, 2009 was 1,191.  Baker Hughes is a large oil field services firm
that has issued the rotary rig counts as a service to the petroleum industry
since 1944.




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





At
      December 31,2008
            
            
            2007
            
            
            2006Crude
      oil (Bbl)
            
            $
            44.60
            
            
            $
            95.98
            
            
            $
            61.05Natural
      gas (Mmbtu)
            
            $
            5.62
            
            
            $
            7.48
            
            
            $
            6.30U.S.
      Land Rig Count
            
            
            1,653
            
            
            
            1,719
            
            
            
            1,626




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




The recent
decline in oil and natural gas prices and the deteriorating global economic
environment will lead to reductions in our rig utilization and revenue rates in
2009.  Our near-term strategy is to maintain a strong balance sheet
and ample liquidity. Management has initiated certain cost reduction measures
including workforce and wage rate reductions that will reduce operating expenses
during the downturn in the industry. Budgeted capital expenditures for 2009
represent a substantial reduction from historical levels and consist of routine
capital expenditures necessary to maintain our equipment in safe and efficient
working order and limited discretionary capital expenditures of new equipment or
upgrades of existing equipment.




Critical
Accounting Policies and Estimates




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




Revenue and Cost
Recognition—Our Contract Land Drilling segment earns revenues by drilling
oil and natural gas wells for our customers 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 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 jobs 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, 2008 and 2007. At December 31, 2008 and 2007, our
unbilled receivables totaled $2.9 million and $2.1 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 $3.8 million and $1.8 million at December 31, 2008
and 2007, 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.


-18-
 Table of Contents





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





In the fourth
quarter of 2008, oil and natural gas prices decreased significantly and the
general economic conditions worsened.  We considered this a triggering
event that required us to perform an assessment with respect to impairment of
long-lived assets, including property and equipment and intangible assets, in
our contract land drilling and well servicing segments.  We estimated
future undiscounted cash flows over the expected life of the long-lived assets
and determined that expected cash flows exceeded the carrying value of the
long-lived assets.  Based on the analysis performed, no impairment was
indicated.




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




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




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




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, 2008 and 2007, we capitalized
approximately $1.3 million and $1.7 million, respectively.




We reviewed
our investment in Challenger at December 31, 2008 for impairment based on the
guidance of APB Opinion No. 18, The Equity Method of Accounting for
Investments in Common Stock,which states that a loss in value of an
investment which is other than a temporary decline should be
recognized.  Evidence of a loss in value might include the absence of
an ability to recover the carrying amount of the investment or inability of the
investee to sustain an earnings capacity which would justify the carrying amount
of the investment.  A current fair value of an investment that is less
than its carrying amount may indicate a loss in value of the
investment.  Due to the recent volatility and decline in oil and
natural gas prices, a deteriorating global economic environment and the
anticipated future earnings of Challenger, we deemed it necessary to test the
investment for impairment.




Fair value of
the investment was estimated using a combination of income, or discounted cash
flows approach and the market approach, which utilizes comparable companies’
data.  In developing these fair value estimates, certain key
assumptions included an assumed discount rate of 16.5%, a control premium of
30.0% and a long-term growth rate of 4.0%.  The analysis resulted in a
fair value of $62.9 million related to our investment in Challenger, which was
below the carrying value of the investment and resulted in a non-cash impairment
charge in the amount of $14.4 million.




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 $5.8 million, $3.7 million, and
$2.8 million for 2008, 2007 and 2006, respectively.




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




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




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




On April 20,
2007, we filed a Tender Offer Statement on Schedule TO relating to our offer to
eligible directors, officers, employees and consultants to exchange certain
outstanding options to purchase shares of our common stock for restricted stock
awards consisting of the right to receive restricted shares of our common stock,
which we refer to as the “restricted stock awards.” The offer expired on May 21,
2007. Pursuant to the offer, we accepted for cancellation eligible options to
purchase 729,000 shares of our common stock tendered by directors, officers,
employees and consultants eligible to participate in the
offer.  Subject to the terms and conditions of the offer, on May 21,
2007 we granted one restricted stock award in exchange for every two shares of
common stock underlying the eligible options tendered.  Half of the
restricted stock awards vested on January 1, 2008 and the balance vested on
January 1, 2009. 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 being 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.  Deferred tax assets are reduced by a valuation
allowance if, based on available evidence, it is more likely than not that some
portion or all of the deferred tax assets will not be realized.




Equity Method
Investments---Investee companies that are not consolidated, but over
which we exercise significant influence, are accounted for under the equity
method of accounting. Whether or not we exercise significant influence with
respect to an Investee depends on an evaluation of several factors including,
among others, representation on the Investee company’s board of directors and
ownership level, which is generally a 20% to 50% interest in the voting
securities of the Investee company. Under the equity method of accounting, an
Investee company’s accounts are not reflected within our Consolidated Balance
Sheets and Statements of Operations; however, our share of the earnings or
losses of the Investee company is reflected in the caption “Equity in income of
Challenger” in the Consolidated Statements of Operations. Our carrying value in
an equity method Investee company is reflected in the caption “Investment in
Challenger” in our Consolidated Balance Sheets.
 -19-
 Table of Contents





Other Accounting
Estimates—Our other accrued expenses as of December 31, 2008 and
December 31, 2007 included accruals of approximately $4.3 million and $3.0
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
$10.0 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, 2008 and 2007, we had deposits of $0 and
$2.7 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, 2008:





On January 4,
2008, Bronco MENA Investments LLC, one of our wholly-owned subsidiaries, closed
a transaction with Challenger Limited, or 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 valued at $72.9
million and $5.1 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.  We also sold to
Challenger four drilling rigs and ancillary equipment for $13.0 million, payable
in installments.  We recorded a net gain of $3.1 million relating to
the exchange and sale of rigs and equipment to Challenger.  Prior to
these transactions, Challenger owned a fleet of 23 rigs.  We recorded
equity in income of Challenger of $2.2 million for the year ended December 31,
2008 related to our equity investment in Challenger.









On January
23, 2008, we entered into an Agreement and Plan of Merger, as amended by the
First Amendment thereto, dated as of June 1, 2008, which together we refer to as
the merger agreement, with Allis-Chalmers and Merger Sub, 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),
Bronco would merge with and into Merger Sub, a wholly-owned subsidiary of
Allis-Chalmers, and Merger Sub would survive the merger and simultaneously
change its name to “Bronco Drilling Company LLC”.  The merger
agreement was approved by our board of directors and by the respective boards of
directors of Allis-Chalmers and Merger Sub.  In light of shareholder
opposition, the proposed merger was terminated mutually by us and Allis-Chalmers
on August 8, 2008.  We incurred $6.0 million in expense during the
third quarter related to the proposed merger.




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


Natural
      Gas Priceper
      Mcf
            
            
            Oil
      Price per BblQuarter
            
            High
            
            
            Low
            
            
            High
            
            
            Low2009:First
      (through February 27, 2009)
            
            $
            6.07
            
            
            $
            4.01
            
            
            $
            48.81
            
            
            $
            33.982008:Fourth
            
            $
            7.73
            
            
            $
            5.29
            
            
            $
            98.53
            
            
            $
            33.87Third
            
            $
            13.58
            
            
            $
            7.22
            
            
            $
            145.29
            
            
            $
            95.71Second
            
            $
            13.35
            
            
            $
            9.32
            
            
            $
            140.21
            
            
            $
            100.98First
            
            $
            10.23
            
            
            $
            7.62
            
            
            $
            110.33
            
            
            $
            86.992007:Fourth
            
            $
            6.45
            
            
            $
            5.84
            
            
            $
            91.96
            
            
            $
            83.13Third
            
            $
            6.07
            
            
            $
            5.21
            
            
            $
            76.09
            
            
            $
            69.88Second
            
            $
            7.02
            
            
            $
            6.44
            
            
            $
            65.23
            
            
            $
            60.73First
            
            $
            6.88
            
            
            $
            5.80
            
            
            $
            58.69
            
            
            $
            50.792006:Fourth
            
            $
            6.72
            
            
            $
            4.50
            
            
            $
            58.23
            
            
            $
            56.15Third
            
            $
            6.74
            
            
            $
            5.55
            
            
            $
            72.49
            
            
            $
            61.56Second
            
            $
            6.06
            
            
            $
            5.46
            
            
            $
            69.67
            
            
            $
            67.26First
            
            $
            7.99
            
            
            $
            6.13
            
            
            $
            62.39
            
            
            $
            57.58




As noted in
the table, oil and natural gas prices have declined significantly during recent
months in a deteriorating national and global economic
environment.  The current economic environment and the recent decline
in commodity prices is causing exploration and production companies to reduce
their overall level of drilling activity and spending.  When drilling
activity and spending decline for any sustained period of time or dayrates and
utilization rates also tend to decline.  In addition, lower commodity
prices for any sustained period of time could impact the liquidity condition of
some of our customers, which, in turn, might limit their ability to meet their
financial obligations to us.




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




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




•
            In
      December 2008, we incurred an impairment charge to our investment in
      Challenger of $14.4 million due to the fair value of the investment
      being less than its carrying
      value.




•
            We
      have reduced our total 2009 estimated capital expenditures for our
      business segments by approximately 69% compared to 2008, excluding
      acquisitions, in order to focus on keeping our capital expenditures within
      anticipated internally generated cash
      flow.




•
            Due
      to declining commodity prices of oil and natural gas, several of our
      customers have significantly reduced their drilling budgets from 2009,
      resulting in a significant reduction in the average utilization of our
      drilling and workover rig fleet. Our average utilization was approximately
      83% for the three months ended December 31, 2008, 76% for the month of
      January and 55% for the month of February
      2009.




Results
of Operations





Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007




Contract Drilling
Revenue. For the year ended December 31, 2008, we reported contract
drilling revenues of approximately $247.8 million, a 10% decrease from revenues
of $276.1 million for 2007. The decrease is primarily due to decreases in total
revenue days, average operating rigs, and average dayrates for the year ended
December 31, 2008 as compared to 2007. Revenue days decreased 11% to 12,712
days for the year ended December 31, 2008 from 14,245 days during
2007.   Our average number of operating drilling rigs decreased
to 44 from 51, or 14%, for the year ended December 31, 2008, as compared to
2007.  Average dayrates for our drilling services decreased $239, or
1%, to $17,637 for the year ended December 31, 2008 from $17,876 in 2007.
The decrease in the number of revenue days for the year ended December 31,
2008 as compared to 2007 is attributable to the decrease in the size of our
drilling fleet due to the contribution and sale of 10 rigs to Challenger during
2008.  During the fourth quarter of 2008, the Company recorded $3.6
million of contract drilling revenue related to terminated
contracts.




-20-
 Table of Contents





Well Service
Revenue.For the year ended December 31, 2008, we
reported well service revenues of approximately $33.3 million, a 46% increase
from revenues of $22.9 million for 2007.  This increase is primarily
due to an increase in revenue hours and average revenue per hour for the year
ended December 31, 2008 as compared to 2007.  Revenue hours increased
44% to 91,591 hours for the year ended December 31, 2008 from 63,746 for
2007.  Our average revenue per hour increased 1% to $359 from $356,
for the year ended December 31, 2008 as compared to 2007.  The
increase in revenue hours and the size of our operating workover rig fleet is
due to additional workover rigs purchased during 2008 and 2007.




Equity in Income of
Challenger.Equity in income of Challenger was $2.2 million
for the year ended December 31, 2008 related to our investment in
Challenger.  The equity in income of Challenger represents our 25%
share of Challenger’s income for 2008.  For the year ended December
31, 2008, Challenger had operating revenues of $71.8 million and operating costs
of $38.5 million.




Contract Drilling
Expense. Contract drilling expense decreased $4.9 million to $148.9
million for the year ended December 31, 2008 from $153.8 million in 2007.
This 3% decrease is primarily due to the decrease in the average number of
operating drilling rigs in our fleet to 44 for the year ended December 31,
2008 as compared to 51 in 2007. As a percentage of contract drilling revenue,
drilling expense increased to 60% for the year ended December 31, 2008 from
56% in 2007 due primarily to a wage increase for field personnel and general
increase in the cost of supplies and materials.





Well Service
Expense. Well service expense increased $10.2 million to $24.5 million
for the year ended December 31, 2008 from $14.3 million for the same period in
2007.  This 71% increase is primarily due to the increase in revenue
hours and the average hourly operating expense for the year ended December 31,
2008 as compared to the same period in 2007.





Depreciation and
Amortization Expense. Depreciation and amortization expense increased
$6.2 million to $50.4 million for the year ended December 31, 2008 from
$44.2 million in 2007.  This increase is primarily due to the 1%
increase in fixed assets and an entry to credit depreciation expense in the
third quarter of 2007 for $2.1 million related to a change in the depreciable
life of certain rig components that moved between working rigs and the
yard.




General and
Administrative Expense. General and administrative expense increased
$11.1 million, or 50%, to $33.8 million for the year ended December 31,
2008 from $22.7 million in 2007. This increase is primarily attributed to the
termination fee of $4.5 million paid to Allis-Chalmers upon termination of the
proposed merger.  Professional fees increased $1.4 million and
consulting fees expense increased $749,000 primarily due to the terminated
merger.  The remaining increase is due to an increase in
administrative salaries of $2.2 million and stock compensation expense of $2.1
million.  The increases in administrative salaries and stock
compensation expense are partially due to the grant of additional shares of
restricted stock in 2008 and due to the termination of our employment agreement
with Larry Bartlett, our former Senior Vice President of Rig Operations, during
the third quarter of 2008.





Impairments.In
connection with our annual goodwill impairment assessment performed as of
December 31, 2008, we performed an impairment test of our contract drilling and
well servicing reporting units under the provisions of SFAS No. 142, Goodwill and Other Intangible
Assets.  Based on the results of the first step on the
impairment test, impairment was indicated in both reporting
units.  Management performed the second step of the analysis of our
drilling and well servicing reporting units, allocating the estimated fair value
to the indentifiable tangible and intangible assets and liabilities of these
reporting units based on their respective values.  This allocation
indicated no residual value for goodwill, and accordingly we recorded an
impairment charge of $24.3 million in our December 31, 2008 statement of
operations.   This impairment charge is not expected to have an
impact on our liquidity or debt covenants; however, it is a reflection of the
overall downturn in our industry and decline in our projected cash
flows.




We reviewed
our investment in Challenger at December 31, 2008 for impairment based on the
guidance of APB Opinion No. 18, The Equity Method of Accounting for
Investments in Common Stock,which states that a loss in value of an
investment which is other than a temporary decline should be
recognized.  Fair value of the investment was estimated using a
combination of income, or discounted cash flows approach and the market
approach, which utilizes comparable companies’ data.  The analysis
resulted in a fair value of $62.9 million related to our investment in
Challenger, which was below the carrying value of the investment and resulted in
a non-cash impairment charge in the amount of $14.4 million.




Interest
Expense. Interest expense decreased $591,000 to $4.2 million for the year
ended December 31, 2008 from $4.8 million in 2007. The decrease is due to
the waiver of interest in the amount of $1.0 million related to our use tax
liability recorded in 2007 and a decrease in the average interest rate on our
revolving credit facility partially offset by a higher outstanding balance on
our revolving credit facility and a decrease in the capitalization of interest
expense related to our rig refurbishment program. We capitalized $1.3 million of
interest for the year ended December 31, 2008 as compared to $1.7 million for
the same period in 2007 as part of our rig refurbishment program.




Income Tax
Expense. We recorded an income tax benefit of $5.2 million for the year
ended December 31, 2008. This compares to an income tax expense of $23.1
million in 2007. This decrease is primarily due to a $74.1 million decrease in
pre-tax income to a pre-tax loss of $13.4 million for the year ended December
31, 2008 from pre-tax income of $60.7 million in 2007.





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.




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.




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




General and
Administrative Expense. General and administrative expense increased $7.0
million, or 44%, to $22.7 million for the year ended December 31, 2007 from
$15.7 million in 2006. This primarily resulted from a $4.2 million increase in
accounts receivable write-offs, a $1.4 million increase in payroll costs, a
$959,000 increase in stock compensation expense, a $502,000 increase in yard
expense, and a $388,000 increase in rent expense.  These increases
were partially offset by a decrease in severance expense of
$565,000.  The increase in bad debt expense is due to the
identification of additional accounts receivable deemed
uncollectible.  The increase in payroll costs is due to our increased
administrative employee count and related wage increases during 2007. The
increase in stock compensation expense is attributed to grants of restricted
stock during 2007.  The increases in yard and rent expense are due to
additional locations added in 2007.  The decrease in severance expense
of $565,000 is due to one-time payments made to our former Chief Operating
Officer, Karl Benzer, upon termination of his employment in 2006.




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




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


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 Table of Contents




Liquidity
and Capital Resources




Operating
Activities. Net
cash provided by operating activities was $59.1 million in 2008, $82.6 million
in 2007 and $93.1 million in 2006. The decrease of $23.5 million from 2007 to
2008 and $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.




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 $82.8 million for 2008 as compared to approximately
$80.0 million for 2007, and $143.2 million for 2006. In 2008, approximately $5.1
million was used to obtain a 25% interest in Challenger, $87.3 million was used
to purchase property and equipment, which amounts were partially offset by $6.6
million received from the sale of assets and $2.9 million received from a
restricted cash account.  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
received 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 received from the sale of assets.




Financing
Activities. Our
cash flows provided by financing activities were $44.7 million for 2008 as
compared to $7.5 million used in financing activities for 2007 and $43.7 million
provided by financing for 2006.  Our net cash provided by financing
for 2008 related to borrowings of $51.1 million under our credit facility with
Fortis, partially offset by $2.9 million paid to other finance companies and
$3.5 million in debt issuance costs.  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.




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





Debt Financing.  On
January 13, 2006, we entered into a $150.0 million revolving credit facility
with Fortis Capital Corp., as administrative agent, lead arranger and sole book
runner, and a syndicate of lenders.  On September 29, 2008, we amended
and restated this revolving credit facility.  This $150.0 million
amended and restated credit facility is with Fortis Bank SA/NV, New York Branch,
as administrative agent, joint lead arranger and sole bookrunner, and a
syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT
Group/Business Credit, Inc., The Prudential Insurance Company of America, Legacy
Bank, Natixis and Caterpillar Financial Services Corporation. The revolving
credit facility matures on September 29, 2013.  Loans under the
revolving credit facility bear interest at LIBOR plus a 4.0% margin or, at our
option, the prime rate plus a 3.0% margin.  The Company had $111.1
million borrowed against the facility at December 31, 2008.




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, 2008 and 2007 were $406,000 and $257,000,
respectively.  Our domestic 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
equity interests 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 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 1.05 to 1.00 for the four consecutive
quarters ending March 31, 2009, 1.10 to 1.00 for the four consecutive quarters
ending June 30, 2009 and 1.15 to 1.00 for the four consecutive quarters ending
September 30, 2009 and each quarter thereafter and a maximum total leverage
ratio of 2.00 to 1.00. We are in compliance with all covenants at December 31,
2008.  The revolving credit facility provides for mandatory
prepayments under certain circumstances including the following:




·
            Asset
      dispositions


·
            Reduction
      of revolving commitments


·
            Deficiency


·
            Equity
      issuance


·
            Debt
      incurrence; and


·
            Event
      of default




We are party
to term installment loans for an aggregate principal amount of approximately
$4.5 million. These term loans are payable in 96 monthly installments, mature in
2013 and 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 Drilling 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 2008, we
incurred aggregate refurbishment costs of  $54.4 million related to
newbuilds, enhancements and refurbishments of rigs related to our
international expansion in Libya and Mexico and new plays domestically. We
also incurred $5.1 million in costs related to the purchase and 
refurbishments of workover rigs.




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.


-22-
 Table of Contents




Working
Capital.Our working capital was $71.6 million at December 31,
2008, compared to $34.8 million at December 31, 2007.  Our current
ratio, which we calculate by dividing our current assets by our current
liabilites, was 3.0 at December 31, 2008 compared to 1.9 at December 31,
2007.




We
believe that the liquidity shown on our balance sheet as of December 31, 2008,
which includes approximately $71.6 million in working capital (including $26.7
million in cash) and availability under our $150.0 million credit facility with
$111.1 million outstanding at December 31, 2008, together with cash expected to
be generated from operations, provides us with sufficient ability to fund our
operations for at least the next twelve months.  However, additional
capital may be required for future rig acquisitions.  While we would
expect to fund such acquisitions with additional borrowings and the issuance of
debt and equity securities, we cannot assure you that such funding will be
available or, if available, that it will be on terms acceptable to
us.  The changes in the components of our working capital were as
follows (amounts in thousands):




December
      31,2008
            
            
            2007
            
            
            ChangeCash
      and cash equivalents
            
            $
            26,676
            
            
            $
            5,721
            
            
            $
            20,955Trade
      and other receivables
            
            
            65,817
            
            
            
            61,499
            
            
            
            4,318Unbilled
      receivables
            
            
            2,940
            
            
            
            2,128
            
            
            
            812Income
      tax receivable
            
            
            2,072
            
            
            
            1,191
            
            
            
            881Current
      deferred income taxes
            
            
            2,844
            
            
            
            775
            
            
            
            2,069Current
      maturities of note receivable
            
            
            6,900
            
            
            
            -
            
            
            
            6,900Prepaid
      expenses
            
            
            572
            
            
            
            705
            
            
            
            (133
            )Current
      assets
            
            
            107,821
            
            
            
            72,019
            
            
            
            35,802Current
      debt
            
            
            1,464
            
            
            
            1,256
            
            
            
            208Accounts
      Payable
            
            
            18,473
            
            
            
            16,715
            
            
            
            1,758Accrued
      liabilities and deferred revenues
            
            
            16,249
            
            
            
            19,280
            
            
            
            (3,031
            )Current
      liabilities
            
            
            36,186
            
            
            
            37,251
            
            
            
            (1,066
            )Working
      capital
            
            $
            71,635
            
            
            $
            34,768
            
            
            $
            36,868


The increase
in cash and cash equivalents was primarily due to $44.7 million of cash provided
by financing activities including $51.1 million related to borrowings under our
credit facility with Fortis, partially offset by $2.9 million paid to other
finance companies.




The
increase in receivables and current maturities of notes receivable at December
31, 2008 as compared to December 31, 2007 was due to receivables of $4.9 million
that relate to rigs sold and services provided to Challenger during
2008.  On January 4, 2008, we sold to Challenger four drilling rigs
and ancillary equipment for $13.0 million, payable in
installments.  We also provide services to Challenger such as labor
and management services.




The
decrease in accrued liabilities was due to the pay down during 2008 of
approximately $6.2 million in use taxes that were accrued as of December 31,
2007.  This was partially offset by an increase in our workers
compensation accrual of $1.3 million and an increase in deferred revenue of
approximately $2.3 million due to the additional deferral of mobilization
revenue and prepayments from operators.




Contractual
and Commercial Commitments




The following
table summarizes our contractual obligations and commercial commitments at
December 31, 2008 (in thousands):




Payments
      Due by PeriodContractual
      Obligations
              
              Total
              
              
              Less
      than 1
              
              
              1-3
      years
              
              
              4-5
      years
              
              
              More
      than 5year
              
              
              
              
              
              
              
              
              yearsShort
      and long-term debt
              
              $
              117,546
              
              
              $
              1,464
              
              
              $
              3,002
              
              
              $
              112,219
              
              
              $
              862Interest
      on long-term debt
              
              
              38,740
              
              
              
              8,144
              
              
              
              23,996
              
              
              
              6,432
              
              
              
              168Operating
      lease obligations
              
              
              4,084
              
              
              
              1,073
              
              
              
              2,321
              
              
              
              615
              
              
              
              75Total
              
              $
              160,370
              
              
              $
              10,681
              
              
              $
              29,319
              
              
              $
              119,266
              
              
              $
              1,105
  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, or 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 to 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 adoption of the
provisions of SFAS 157 did not have a material impact on our financial
statements.




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 elected not to measure certain assets and
liabilities at fair value. The adoption of the provisions of SFAS 159 did not
have a material impact on our financial statements.




In December
2007, the FASB issued SFAS No. 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 No. 141R
applies prospectively to business combinations for which the acquisition date is
on or after the beginning of the first annual reporting period beginning on or
after December 15, 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 No. 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 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 fiscal years, and interim periods within those fiscal years, beginning on or
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 March
2008, the FASB issued SFAS No. 161, or SFAS 161, “Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement No.
133.”  SFAS 161 requires enhanced disclosures for derivative
instruments and hedging activities that include how and why an entity uses
derivatives, how instruments and the related hedged items are accounted for
under FAS 133 and related interpretations, and how derivative instruments and
related hedged items affect the entity’s financial position, results of
operations and cash flows.  SFAS 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008. We do not expect the adoption of SFAS 161 to have a material impact on
our financial position or results of operations.


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 Table of Contents


In May 2008,
the FASB issued SFAS No. 162 or SFAS 162, “The Hierarchy of Generally Accepted
Accounting Principles.”  This statement identifies the sources
of accounting principles and the framework for selecting the principles to be
used in the preparation of financial statements in conformity with generally
accepted accounting principles (GAAP) in the United States. This statement is
effective 60 days following the SEC’s approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, “The Meaning ofPresent Fairly
in Conformity With Generally Accepted Accounting Principles”. The adoption of
SFAS No. 162 did not have a material impact on our financial position or results
of operations





In June 2008,
the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions are Participating
Securities.This FSP provides that unvested share-based
payment awards that contain nonforfeitable rights to dividends are participating
securities and shall be included in the computation of earnings per share
pursuant to the two class method.  This FSP is effective for financial
statements issued for fiscal years beginning after December 15, 2008 and interim
periods within those years.  We do not expect the adoption of this FSP
to have a material impact on our financial position or results of
operation.





In September
2008, the FASB issued EITF 08-6, Equity Method Investment Accounting
Considerations.The purpose of this issue is to resolve
several accounting issues that arise in applying the equity method of
accounting. Most of these issues arise or become more prevalent upon the
effective date of FASB Statement No. 141 (Revised 2007), Business Combinations, and
(or) FASB Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements. This is because the literature that is
being replaced or amended by Statements 141R and 160 has been used by analogy in
addressing certain aspects of applying the equity method of
accounting.  The EITF concluded that the effective date for this issue
should coincide with the effective date of Statements 141R and 160 and that it
should be applied prospectively. As such, the guidance in this issue would be
applied to transactions that occur in fiscal years, and interim periods within
those fiscal years, beginning on or after December 15, 2008. Early adoption
would not be permitted.  We are currently evaluating the potential
impact, if any, of the adoption of EITF 08-6 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 of 4.0%
or, at our option, the prime rate plus a margin of 3%. An increase or decrease
of 1% in the interest rate would have a corresponding decrease or increase in
our net income (loss) of approximately $681,000 annually, based on the $111.1
million outstanding in the aggregate under our credit facility as of February
28, 2009.




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, 2008 our disclosure controls and procedures are
effective.




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





Management's
Report on Internal Control over Financial Reporting.




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





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





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





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





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





Management,
with the participation of our Chief Executive Officer and Chief Financial
Officer, conducted its evaluation of the effectiveness of internal control over
financial reporting based on the framework in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. This evaluation included review of the documentation of
controls, evaluation of the design effectiveness of controls, testing of the
operating effectiveness of controls and a conclusion on this
evaluation.  Although there are inherent limitations in the
effectiveness of any system of internal controls over financial reporting, based
on our evaluation, management has concluded that our internal control over
financial reporting was effective as of December 31, 2008.





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





Changes
in Internal Controls over Financial Reporting.





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


-24-
 Table of Contents








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, 2008, 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, 2008, based on criteria
established in Internal
Control - Integrated Frameworkissued 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, 2008 and 2007, and the related consolidated statements of
operations, stockholders’equity and cash flows for each of the three years in
the period ended December 31, 2008 and our report dated March 16, 2009 expressed
an unqualified opinion.














/s/ GRANT
THORNTON LLP





Oklahoma
City, Oklahoma


March 16,
2009


-25-
 Table of Contents




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 2009 Annual Meeting of Stockholders, which will be filed
with the SEC no later than 120 days after December 31, 2008.




Item 11. Executive Compensation.




The
information relating to this Item 11 is incorporated by reference to the
Proxy Statement for our 2009 Annual Meeting of Stockholders, which will be filed
with the SEC no later than 120 days after December 31, 2008.


Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matter
  The
information relating to this Item 12 is incorporated by reference to the
Proxy Statement for our 2009 Annual Meeting of Stockholders, which will be filed
with the SEC no later than 120 days after December 31,
2008.




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 2009 Annual Meeting of Stockholders, which will be filed
with the SEC no later than 120 days after December 31, 2008.




Item 14. Principal Accounting Fees and
Services




The
information relating to this Item 14 is incorporated by reference to the
Proxy Statement for our 2009 Annual Meeting of Stockholders, which will be filed
with the SEC no later than 120 days after December 31, 2008.







-26-
 Table of Contents





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 29 of this Form 10-K.




2.
            Financial Statement
      Schedules




Schedule
II




3.
            Exhibits:








-27-
 Table of Contents




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).




2.4
            First
      Amendment, dated as of June 1, 2008, to Agreement and Plan of Merger
      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 June 2, 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).





10.1
            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).





10.2
            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).





10.3
            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).




10.4
              Mutual
      Termination and Release Agreement, dated August 8, 2008, by and among
      Allis-Chalmers Energy, Inc., Bronco Drilling Company, Inc., and Elway
      Merger Sub, LLC (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 August 8, 2008).
 
 10.5
              Amended
      and Restated Credit Agreement, dated as of September 29, 2008, among
      Bronco Drilling Company, Inc., as Borrower, certain subsidiaries thereof,
      as Guarantors, the lenders from time to time party thereto, as Lenders,
      Fortis Bank SA/NV, New York Branch, as Administrative Agent, Joint Lead
      Arranger and Sole Bookrunner, The Royal Bank of Scotland plc, as Joint
      Lead Arranger and Co-Syndication Agent, the Prudential Insurance Company
      of America, as Co-Syndication Agent, and The CIT Group/Business Credit,
      Inc. and Caterpillar Finance Services Corporation, as Co-Documentation
      Agents (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
      September 29, 2008).
 
 10.6
              Seperation
      Agreement, dated effective as of September 10, 2008, by and between the
      Company and Larry Bartlett.
 
 10.7
              Form
      of Director and Officer Indemnification
  Agreement.
 
 +10.8
              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).
 
 +10.9
              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).
 
 +10.10
              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).
  *21.1
              List
      of the 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.


-28-
 Table of Contents




INDEX
TO CONSOLIDATED FINANCIAL STATEMENTS




BRONCO
DRILLING COMPANY, INC. AND SUBSIDIARIES




PageBronco
      Drilling Company, Inc. and SubsidiariesReport
      of Independent Registered Public Accounting Firm
            30Consolidated
      Balance Sheets as of December 31, 2008 and 2007
            31Consolidated
      Statements of Operations for the years ended December 31, 2008, 2007
      and 2006
            32Consolidated
      Statements of Stockholders’ Equity for the years ended December 31,
      2006, 2007 and 2008
            33Consolidated
      Statements of Cash Flows for the years ended December 31, 2008, 2007
      and 2006
            34Notes
      to Consolidated Financial Statements
            35







-29-
 Table of Contents








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, 2008 and 2007, and the
related consolidated statements of operations, stockholders’equity and cash
flows for each of the three years in the period ended December 31,
2008.  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, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2008, 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, 2008, 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 16, 2009 expressed an
unqualified opinion.














/s/ GRANT
THORNTON LLP





Oklahoma
City, Oklahoma


March 16,
2009








-30-
 Table of Contents





Bronco
      Drilling Company, Inc. and SubsidiariesCONSOLIDATED BALANCE SHEETS(Amounts
      in thousands, except share par value)December
      31,2008
            
            
            2007ASSETSCURRENT
      ASSETSCash
      and cash equivalents
            
            $
            26,676
            
            
            $
            5,721ReceivablesTrade
      and other, net of allowance for doubtful accounts of$3,830
      and $1,834 in 2008 and 2007, respectively
            
            
            65,817
            
            
            
            61,499Unbilled
      receivables
            
            
            2,940
            
            
            
            2,128Income
      tax receivable
            
            
            
            2,072
            
            
            
            1,191Current
      deferred income taxes
            
            
            2,844
            
            
            
            775Current
      maturities of note receivable from affiliate
            
            
            6,900
            
            
            
            -Prepaid
      expenses
            
            
            572
            
            
            
            705Total
      current assets
            
            
            107,821
            
            
            
            72,019PROPERTY
      AND EQUIPMENT - AT COSTDrilling
      rigs and related equipment
            
            
            512,158
            
            
            
            510,962Transportation,
      office and other equipment
            
            
            43,912
            
            
            
            41,942556,070
            
            
            
            552,904Less
      accumulated depreciation
            
            
            123,915
            
            
            
            86,274432,155
            
            
            
            466,630OTHER
      ASSETSGoodwill
            
            
            
            
            -
            
            
            
            23,908Note
      receivable from affiliate, less current maturities
            
            
            3,451
            
            
            
            -Investment
      in Challenger
            
            
            62,875
            
            
            
            -Restricted
      cash and deposit
            
            
            -
            
            
            
            2,745Intangibles,
      net, and other
            
            
            6,052
            
            
            
            3,30372,378
            
            
            
            29,956$
            612,354
            
            
            $
            568,605LIABILITIES
      AND STOCKHOLDERS' EQUITYCURRENT
      LIABILITIESAccounts
      payable
            
            $
            18,473
            
            
            $
            16,715Accrued
      liabilities
            
            
            16,249
            
            
            
            19,280Current
      maturities of long-term debt
            
            
            1,464
            
            
            
            1,256Total
      current liabilities
            
            
            36,186
            
            
            
            37,251LONG-TERM
      DEBT,  less current maturities
            
            
            116,083
            
            
            
            66,862DEFERRED
      INCOME TAXES
            
            
            66,074
            
            
            
            68,063COMMITMENTS
      AND CONTINGENCIES (Note 9)STOCKHOLDERS'
      EQUITYCommon
      stock, $.01 par value, 100,000shares
      authorized; 26,346 and 26,031 sharesissued
      and outstanding at December 31, 2008 and 2007
            
            
            267
            
            
            
            262Additional
      paid-in capital
            
            
            304,015
            
            
            
            298,195Retained
      earnings
            
            
            89,729
            
            
            
            97,972Total stockholders' equity
            
            
            394,011
            
            
            
            396,429$
            612,354
            
            
            $
            568,605The
      accompanying notes are an integral part of these
    statements.




-31-
 Table of Contents





Bronco
      Drilling Company, Inc. and SubsidiariesCONSOLIDATED
      STATEMENTS OF OPERATIONS(Amounts
      in thousands, except per share amounts)Years
      Ended December 31,2008
            
            
            2007
            
            
            2006REVENUESContract
      drilling revenues, including 2%, 1% and 4%to
      related parties
            
            
            247,829
            
            
            
            276,088
            
            
            $
            285,828Well
      service, including 1% and 0% to related parties
            
            
            33,284
            
            
            
            22,864
            
            
            
            -Gain
      on Challenger transactions
            
            
            3,138
            
            
            
            -
            
            
            
            -284,251
            
            
            
            298,952
            
            
            
            285,828EXPENSESContract
      drilling
            
            
            148,866
            
            
            
            153,797
            
            
            
            139,607Well
      service
            
            
            24,478
            
            
            
            14,299
            
            
            
            -Depreciation
      and amortization
            
            
            50,388
            
            
            
            44,241
            
            
            
            30,335General
      and administrative
            
            
            33,771
            
            
            
            22,690
            
            
            
            15,709Impairment
      of goodwill
            
            
            24,328
            
            
            
            -
            
            
            
            -281,831
            
            
            
            235,027
            
            
            
            185,651Income
      from operations
            
            
            2,420
            
            
            
            63,925
            
            
            
            100,177OTHER
      INCOME (EXPENSE)Interest
      expense
            
            
            (4,171
            )
            
            
            (4,762
            )
            
            
            (1,736
            )Loss
      from early extinguishment of debt
            
            
            (155
            )
            
            
            -
            
            
            
            (1,000
            )Interest
      income
            
            
            1,058
            
            
            
            1,239
            
            
            
            164Equity
      in income of Challenger
            
            
            2.186
            
            
            
            -
            
            
            
            -Impairment
      of investment in Challenger
            
            
            (14,442
            )
            
            
            -
            
            
            
            -Other
            
            
            (300
            )
            
            
            294
            
            
            
            284(15,824
            )
            
            
            (3,229
            )
            
            
            (2,288
            )Income
      (loss) before income taxes
            
            
            (13,404
            )
            
            
            60,696
            
            
            
            97,889Income
      tax (benefit) expense
            
            
            (5,161
            )
            
            
            23,104
            
            
            
            38,056NET
      INCOME (LOSS)
            
            $
            (8,243
            )
            
            $
            37,592
            
            
            $
            59,833Income
      (loss) per common share-Basic
            
            $
            (0.31
            )
            
            $
            1.45
            
            
            $
            2.43Income
      (loss) per common share-Diluted
            
            $
            (0.31
            )
            
            $
            1.44
            
            
            $
            2.43Weighted
      average number of shares outstanding-Basic
            
            
            26,293
            
            
            
            25,996
            
            
            
            24,585Weighted
      average number of shares outstanding-Diluted
            
            
            26,293
            
            
            
            26,101
            
            
            
            24,623The
      accompanying notes are an integral part of these
    statements.




-32-
 Table of Contents





Bronco Drilling Company, Inc. and
      SubsidiariesCONSOLIDATED
      STATEMENT OF STOCKHOLDERS' EQUITY(Amounts
      in thousands)Additional
            
            
            
            
            
            TotalCommon
            
            
            Common
            
            
            Paid
      In
            
            
            Retained
            
            
            Stockholders'Shares
            
            
            Amount
            
            
            Capital
            
            
            Earnings
            
            
            EquityBalance
      as of December 31, 2005
            
            
            23,165
            
            
            
            232
            
            
            
            238,557
            
            
            
            547
            
            
            
            239,336Stock
      issued in acquisition
            
            
            73
            
            
            
            1
            
            
            
            1,815
            
            
            
            -
            
            
            
            1,816Issuance
      of common stock in follow-on offering;net
      of related expenses of $577
            
            
            1,700
            
            
            
            17
            
            
            
            36,212
            
            
            
            -
            
            
            
            36,229Net
      income
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            59,833
            
            
            
            59,833Stock
      compensation
            
            
            -
            
            
            
            -
            
            
            
            2,771
            
            
            
            -
            
            
            
            2,771Balance
      as of December 31, 2006
            
            
            24,938
            
            
            
            250
            
            
            
            279,355
            
            
            
            60,380
            
            
            
            339,985Stock
      issued in acquisition
            
            
            1,070
            
            
            
            10
            
            
            
            15,114
            
            
            
            -
            
            
            
            15,124Net
      income
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            37,592
            
            
            
            37,592Stock
      compensation
            
            
            23
            
            
            
            2
            
            
            
            3,726
            
            
            
            -
            
            
            
            3,728Balance
      as of December 31, 2007
            
            
            26,031
            
            
            
            262
            
            
            
            298,195
            
            
            
            97,972
            
            
            
            396,429Net
      loss
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (8,243
            )
            
            
            (8,243
            )Stock
      compensation
            
            
            315
            
            
            
            5
            
            
            
            5,820
            
            
            
            -
            
            
            
            5,825Balance
      as of December 31, 2008
            
            
            26,346
            
            
            $
            267
            
            
            $
            304,015
            
            
            $
            89,729
            
            
            $
            394,011The
      accompanying notes are an integral part of these
    statements.


-33-
 Table of Contents





Bronco Drilling Company, Inc. and
      SubsidiariesCONSOLIDATED
      STATEMENTS OF CASH FLOWS(Amounts
      in thousands)Years
      Ended December 31,2008
              
              
              2007
              
              
              2006Cash
      flows from operating activities:Net
      income (loss)
              
              $
              (8,243
              )
              
              $
              37,592
              
              
              $
              59,833Adjustments
      to reconcile net income (loss) to net cashprovided
      by operating activities:Depreciation
      and amortization
              
              
              51,044
              
              
              
              44,826
              
              
              
              30,901Bad
      debt expense
              
              
              3,745
              
              
              
              4,370
              
              
              
              70Loss
      (gain) on sale of assets
              
              
              426
              
              
              
              (1,589
              )
              
              
              (2,379
              )Gain
      on Challenger transactions
              
              
              (3,138
              )
              
              
              -
              
              
              
              -Equity
      in income of Challenger
              
              
              (2,186
              )
              
              
              -
              
              
              
              -Write
      off of debt issue costs
              
              
              155
              
              
              
              -
              
              
              
              267Stock
      compensation
              
              
              5,825
              
              
              
              3,728
              
              
              
              2,771Impairment
      of goodwill
              
              
              24,328
              
              
              
              -
              
              
              
              -Impairment
      of investment in Challenger
              
              
              14,442
              
              
              
              -
              
              
              
              -Provision
      for deferred income taxes
              
              
              (4,122
              )
              
              
              17,648
              
              
              
              21,237Changes
      in current assets and liabilities, net of assets and liabilities of
      business acquired:Receivables
              
              
              (9,274
              )
              
              
              (3,920
              )
              
              
              (25,274
              )Unbilled
      receivables
              
              
              (813
              )
              
              
              (139
              )
              
              
              (763
              )Prepaid
      expenses
              
              
              131
              
              
              
              (176
              )
              
              
              147Other
      assets
              
              
              720
              
              
              
              (417
              )
              
              
              232Accounts
      payable
              
              
              (9,673
              )
              
              
              (15,831
              )
              
              
              (2,309
              )Accrued
      expenses
              
              
              (3,030
              )
              
              
              1,430
              
              
              
              5,968Income
      taxes receivable
              
              
              (1,237
              )
              
              
              (4,915
              )
              
              
              2,352Net
      cash provided by operating activities
              
              
              59,100
              
              
              
              82,607
              
              
              
              93,053Cash
      flows from investing activities:Restricted
      cash account
              
              
              2,899
              
              
              
              145
              
              
              
              (416
              )Business
      acquisitions, net of cash acquired
              
              
              (5,063
              )
              
              
              (2,431
              )
              
              
              (17,046
              )Proceeds
      from the sale of assets
              
              
              6,643
              
              
              
              5,084
              
              
              
              4,761Purchase
      of property and equipment
              
              
              (87,274
              )
              
              
              (82,782
              )
              
              
              (130,498
              )Net
      cash used in investing activities
              
              
              (82,795
              )
              
              
              (79,984
              )
              
              
              (143,199
              )Cash
      flows from financing activities:Proceeds
      from borrowings
              
              
              51,100
              
              
              
              17,000
              
              
              
              44,000Payments
      of debt
              
              
              (2,949
              )
              
              
              (24,510
              )
              
              
              (34,867
              )Debt
      issue costs
              
              
              (3,501
              )
              
              
              -
              
              
              
              (1,647
              )Proceeds
      from sale of common stock, netof
      offering costs of $577 in 2006
              
              
              -
              
              
              
              -
              
              
              
              36,229Net
      cash provided by (used in) financing activities
              
              
              44,650
              
              
              
              (7,510
              )
              
              
              43,715Net
      increase (decrease) in cash and cash equivalents
              
              
              20,955
              
              
              
              (4,887
              )
              
              
              (6,431
              )Beginning
      cash and cash equivalents
              
              
              5,721
              
              
              
              10,608
              
              
              
              17,039Ending
      cash and cash equivalents
              
              $
              26,676
              
              
              $
              5,721
              
              
              $
              10,608Supplmentary
      disclosure of cash flow informationInterest
      paid, net of amount capitalized
              
              $
              2,704
              
              
              $
              3,250
              
              
              $
              1,771Income
      taxes paid
              
              
              198
              
              
              
              10,373
              
              
              
              14,467Supplementary
      disclosure of non-cash investing and financing:Liabilities
      assumed in acquisition
              
              $
              -
              
              
              $
              7,867
              
              
              $
              -Common
      stock issued for acquisition
              
              
              -
              
              
              
              15,124
              
              
              
              1,816Debt
      assumed in acquisition
              
              
              -
              
              
              
              6,527
              
              
              
              -Notes
      issued for acquisition of property and equipment
              
              
              1,277
              
              
              
              4,386
              
              
              
              3,769Assets
      exchanged/sold for equity interest and note receivable
              
              
              72,503
              
              
              
              -
              
              
              
              -Common
      stock received for payment of receivable
              
              
              1,900
              
              
              
              -
              
              
              
              -Purchase
      of property and equipment in accounts payable
              
              
              11,430
              
              
              
              -
              
              
              
              -The
      accompanying notes are an integral part of these
    statements.


-34-
 Table of Contents





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




Contract Land
Drilling Segment -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.





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.




Well Servicing Segment –The
Company earns well servicing revenue based on purchase orders, contracts or
other persuasive evidence of an arrangement with the customer, such as a master
service agreement, that include fixed or determinable prices.  The
well servicing revenues are recognized when the services have been rendered and
collectability is reasonably assured.




The asset
“unbilled receivables” represents revenues we have recognized in excess of
amounts billed on drilling contracts and well servicing in
progress.




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,
2008 and 2007, our allowance for doubtful accounts was $3,830 and $1,834,
respectively.





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 and
workover rigs and related equipment are three to 15 years.  The
depreciable life of other equipment is three years. Depreciation is not
commenced until acquired rigs are placed in service. Once placed in service,
depreciation continues when rigs are being repaired, refurbished or between
periods of deployment. Assets not placed in service and not being depreciated
were $34,293 and $61,604 as of December 31, 2008 and 2007,
respectively.  Gains and losses on dispositions are included in
operating revenues.  Due to immateriality, gains and losses on
dispositions with the exception of the Challenger transactions are included in
contract drilling and well service revenues.




The Company
capitalizes interest as a component of the cost of drilling and workover rigs
constructed for its own use. For the years ended December 31, 2008 and
2007, the Company capitalized $1,256 and $1,676, respectively, of interest costs
incurred during the construction periods of certain drilling and workover
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.




In light
of adverse market conditions affecting the Company beginning in the fourth
quarter of 2008 and continuing into 2009, including a substantial decrease in
the operating levels of its business segments, a significant decline in oil and
natural gas commodity prices, and the preliminary results of the Company’s
annual goodwill impairment tests, management deemed it necessary to assess the
recoverability of long-lived assets within its contract land drilling and well
servicing segments.




Management
performed its impairment assessment under the provisions of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, using the undiscounted cash flows for each
segment, using assumptions and methods consistent with those used in its
assessment of the carrying values of goodwill for its contract land drilling and
well servicing segments.  Based on the results of these impairment
tests, the carrying amounts of long-lived assets in the contract drilling and
well servicing segements were determined to be recoverable.


-35-
 Table of Contents




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.




In connection
with the goodwill impairment assessment performed as of December 31, 2008, the
Company performed an impairment test of its contract drilling and well servicing
reporting units under the provisions of SFAS No. 142, Goodwill and Other Intangible
Assets.  In completing its first step of the analysis,
management used a five-year projection of discounted cash flows, plus a terminal
value determined using a constant growth method to estimate the fair value of
its reporting units.  In developing these fair value estimates,
certain key assumptions included an assumed discount rate of 11.0% and 14.0% for
our contract land drilling and well servicing segments, respectively, and an
assumed long-term growth rate of 2.0% for both reporting units.




Based on the
results of the first step on the impairment test, impairment was indicated in
both reporting units.  Management performed the second step of the
analysis of its drilling and well servicing reporting units, allocating the
estimated fair value to the indentifiable tangible and intangible assets and
liabilities of these reporting units based on their respective
values.  This allocation indicated no residual value for goodwill, and
accordingly the Company recorded an impairment charge of $24,328 in its December
31, 2008 statement of operations.




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 $974, $919, and
$672 for the years ended December 31, 2008, 2007, and 2006, respectively.
Total cost and accumulated amortization of intangibles at December 31, 2008 and
2007 was $3,705 and $2,652 and $3,705 and $1,678, respectively.





The Company
evaluates for potential impairment of long-lived assets and intangible assets
subject to amortization when indicators of impairment are present, as defined in
SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets.In light of
adverse market conditions affecting the Company beginning in the fourth quarter
of 2008 and continuing into 2009, including a substantial decrease in the
operating levels of its business segments, a significant decline in oil and
natural gas commodity prices, and the preliminary results of the Company’s
annual goodwill impairment tests, management deemed it necessary to assess the
recoverability of long-lived assets and intangibles within its contract land
drilling and well servicing segments.




Management
performed its impairment assessment under the provisions of SFAS No. 144 using
the undiscounted cash flows for each segment, using assumptions and methods
consistent with those used in its assessment of the carrying values of goodwill
for its contract land drilling and well servicing segments.  Based on
the results of these impairment tests, the carrying amounts of intangible assets
in the contract land drilling and well servicing segments were determined to be
recoverable.




Estimated
amortization expense for each year subsequent to December 31, 2008 is as
follows:




2009.......................
            $               7062010.......................
            2032011.......................
            1442012.......................
            -2013.......................
            -




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 $3,501 and $1,589 at December 31, 2008
and 2007, respectively. Amortization expense related to debt issue costs was
$571, $564, and $508 for years ended December 31, 2008, 2007, and 2006,
respectively, and is included in interest expense in the consolidated statements
of operations. Accumulated amortization related to loan fees was $175 and $1,028
as of December 31, 2008 and 2007, respectively.  On September 29,
2008 the Company refinanced its revolving debt facility and incurred $3,501 of
debt issuance costs.  The Company wrote-off debt issue costs of $155,
which is included in loss from early extinguishment of debt on the consolidated
statement of operations for the year ended December 31, 2008.  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.




Restricted
Cash and Deposit




At
December 31, 2008 and 2007, the Company had a deposit and restricted cash
of $0 and $2,745, 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, 2008, the tax years ended December 31, 2005 through December 31, 2007 are
open for examination by U.S. taxing authorities.




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.




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.


-36-
 Table of Contents




Equity
Method Investments
  Investee companies that are not consolidated,
but over which the Company exercises significant influence, are accounted for
under the equity method of accounting. Whether or not the Company exercises
significant influence with respect to an Investee depends on an evaluation of
several factors including, among others, representation on the Investee
company’s board of directors and ownership level, which is generally a 20% to
50% interest in the voting securities of the Investee company. Under the equity
method of accounting, an Investee company’s accounts are not reflected within
the Company’s Consolidated Balance Sheets and Statements of Operations; however,
the Company’s share of the earnings or losses of the Investee company is
reflected in the caption “Equity in income of Challenger” in the Consolidated
Statements of Operations. The Company’s carrying value in an equity method
Investee company is reflected in the caption “Investment in Challenger”in the
Company’s Consolidated Balance Sheets. The Company reviews its equity method
investment when changes in facts and circumstances indicate a loss in value has
occurred, which is other than a temporary decline.
  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 to 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 elected not to
measure certain assets and liabilities at fair value. The adoption of the
provisions of SFAS 157 did not have a material impact on the Company’s financial
statements.





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 adoption of the provisions of SFAS 159 did
not have a material impact on the Company’s financial statements.




In December
2007, the FASB issued SFAS No. 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 No. 141R
applies prospectively to business combinations for which the acquisition date is
on or after the beginning of the first annual reporting period beginning on or
after December 15, 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 No. 160 (“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 fiscal years, and interim periods within those fiscal years, beginning on or
after December 15, 2008.  The Company is currently evaluating the
potential impact, if any, of the adoption of SFAS 160 on its consolidated
financial statements.




In March
2008, the FASB issued SFAS No. 161 (“SFAS 161”), “Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement No.
133.”  SFAS 161 requires enhanced disclosures for derivative
instruments and hedging activities that include how and why an entity uses
derivatives, how instruments and the related hedged items are accounted for
under FAS 133 and related interpretations, and how derivative instruments and
related hedged items affect the entity’s financial position, results of
operations and cash flows.  SFAS 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008. The Company does not expect the adoption of SFAS 161 to have a
material impact on its financial position or results of operations.




In May 2008,
the FASB issued SFAS No. 162 (“SFAS 162”), “The Hierarchy of Generally Accepted
Accounting Principles.”  This statement identifies the sources
of accounting principles and the framework for selecting the principles to be
used in the preparation of financial statements in conformity with generally
accepted accounting principles (GAAP) in the United States. This statement is
effective 60 days following the SEC’s approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, “The Meaning ofPresent Fairly
in Conformity With Generally Accepted Accounting Principles”. The adoption of
SFAS No. 162 did not have a material impact on its financial position or results
of operations.




In June 2008,
the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions are Participating
Securities.This FSP provides that unvested share-based
payment awards that contain nonforfeitable rights to dividends are participating
securities and shall be included in the computation of earnings per share
pursuant to the two class method.  This FSP is effective for financial
statements issued for fiscal years beginning after December 15, 2008 and interim
periods within those years.  The Company does not expect the adoption
of this FSP to have a material impact on our financial position or results of
operation.




In September
2008, the FASB issued EITF 08-6, Equity Method Investment Accounting
Considerations.The purpose of this issue is to resolve
several accounting issues that arise in applying the equity method of
accounting. Most of these issues arise or become more prevalent upon the
effective date of FASB Statement No. 141 (Revised 2007), Business Combinations, and
(or) FASB Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements. This is because the literature that is
being replaced or amended by Statements 141R and 160 has been used by analogy in
addressing certain aspects of applying the equity method of
accounting.  The EITF concluded that the effective date for this issue
should coincide with the effective date of Statements 141R and 160 and that it
should be applied prospectively. As such, the guidance in this issue would be
applied to transactions that occur in fiscal years, and interim periods within
those fiscal years, beginning on or after December 15, 2008. Early adoption
would not be permitted.  The Company is currently evaluating the
potential impact, if any, of the adoption of EITF 08-6 on our financial
condition or results of operations.




2.
Acquisitions




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
$7,608.  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 four
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.


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 Table of Contents





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




Year
      Ended December 31,2007
                
                
                2006Well
      Service
                
                
                Big
      AAssets Acquired:Cash
                
                $
                198
                
                
                $
                -Prepaid
      expenses
                
                
                227
                
                
                
                -Accounts
      receivable
                
                
                1,667
                
                
                
                -Drilling
      equipment
                
                
                -
                
                
                
                16,724Workover
      equipment
                
                
                23,912
                
                
                
                -Other
      equipment
                
                
                244
                
                
                
                -Vehicles
                
                
                1,943
                
                
                
                353Customer
      lists
                
                
                910
                
                
                
                387Trade
      name
                
                
                190
                
                
                
                -Goodwill
                
                
                3,214
                
                
                
                380$
                32,505
                
                
                $
                17,844


The following
pro forma information gives effect to the Big A acquisition as though it was
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 1,070,390 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
            
            
            2005Total
      revenues
            
            $
            299,964
            
            
            $
            156,090Net
      income
            
            $
            61,299
            
            
            $
            12,193Net
      income per common share:Basic
            
            $
            2.39
            
            
            $
            0.75Diluted
            
            $
            2.39
            
            
            $
            0.75


3.
Investment in Challenger




On
January 4, 2008, we acquired a 25% equity interest in Challenger Limited
(“Challenger”), in exchange for six drilling rigs valued at $72,937 and $5,063
in cash.  The Company’s 25% interest at December 31, 2008 was based on
64,957,265 shares outstanding.  The Company recorded equity in income
of Challenger of $2,186 for the year ended December 31, 2008 related to its
equity investment in Challenger.  Challenger is an international
provider of contract land drilling and workover services to oil and natural gas
companies with its principal operations in Libya.  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:


ApproximateDrillingRig
            
            Design
            Depth
      (ft)
            Type
            Horsepower3
            
            Cabot
      900
            10,000
            Mechanical
            95018
            
            Gardner
      Denver 1500E
            25,000
            Electric
            2,00019
            
            Mid
      Continent U-1220 EB
            25,000
            Electric
            2,00038
            
            National
      1320
            25,000
            Electric
            2,00093
            
            National
      T-32
            8,000
            Mechanical
            50096
            
            Ideco
      H-35
            8,000
            Mechanical
            400


The Company
also sold to Challenger four drilling rigs and ancillary
equipment.  The sales price of $12,990 consisted of $1,950 in cash,
installment receivable of $1,500 and a term note of $9,540.  The term
note bears interest at 8.5%.  Interest and principal payments of $909
on the note are due quarterly until maturity at December 31,
2010.  The note receivable is collateralized by the assets sold to
Challenger.  The note receivable from Challenger at December 31, 2008
was $10,351, of which $6,900 was classified as current and $3,451 was classified
as long-term.




The Company
recorded a net gain of $3,138 relating to the contribution and sale of rigs and
equipment to Challenger.  The transactions were completed on January
4, 2008.  Prior to these transactions, Challenger owned a fleet of 23
rigs.




On February
20, 2008, the Company entered into a Management Services Agreement and Master
Services Agreement with Challenger.  The Company agreed to make
available to Challenger certain available employees of the Company for the
purpose of providing land drilling services, certain business consulting
services and managerial support to Challenger.  The Company invoices
Challenger monthly for the services provided.  The Company had
accounts receivable from Challenger of $3,387 at December 31, 2008 related to
these services provided.




At
December 31, 2008, the book value of our ordinary share investment in
Challenger was $62,875.  The Company’s 25% share of the net assets of
Challenger was estimated to be $37,037.  The basis difference between the
Company’s ordinary share investment in Challenger and the Company’s 25% share of
the net assets of Challenger partially consists of certain property, plant and
equipment in the amount of $5,004 and amortizable intangibles including customer
lists and trade name in the amount of $9,770 and $1,313,
respectively.  These amounts are being amortized against the Company’s
share of Challenger’s net income over the useful lives of the assets including
15 years for the property, plant and equipment, 11 years for customer lists and
20 years for trade name.  The remaining excess of $9,751 is accounted
for as equity method goodwill.




The Company
reviewed its investment in Challenger at December 31, 2008 for impairment based
on the guidance of APB Opinion No. 18, The Equity Method of Accounting for
Investments in Common Stock,which states that a loss in value of an
investment which is other than temporary decline should be
recognized.  Evidence of a loss in value might include the absence of
an ability to recover the carrying amount of the investment or inability of the
investee to sustain an earnings capacity which would justify the carrying amount
of the investment.  A current fair value of an investment that is less
than its carrying amount may indicate a loss in value of the
investment.  Due to the recent volatility and decline in oil and
natural gas prices, a deteriorating global economic environment and the
anticipated future earnings of Challenger, the Company deemed it necessary to
test the investment for impairment. Fair value of the investment was estimated
using a combination of income, or discounted cash flows approach and the market
approach, which utilizes comparable companies’ data.  The analysis
resulted in a fair value of $62,875 related to our investment in Challenger,
which was below the carrying value of the investment and resulted in a non-cash
impairment charge in the amount of $14,442.


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Summarized
financial information of Challenger is presented below:


December
      31,2008Condensed
      statement of operations:Revenues
                
                $
                71,840Gross
      margin
                
                $
                33,372Net
      Income
                
                $
                10,076Condensed
      balance sheet:Current
      assets
                
                $
                50,837Noncurrent
      assets
                
                
                141,558Total
      assets
                
                $
                192,395Current
      liabilities
                
                $
                26,944Noncurrent
      liabilities
                
                
                17,304Equity
                
                
                148,147Total
      liabilities and equity
                
                $
                192,395
  4.
Accrued liabilities




Accrued
liabilities consisted of the following at December 31, 2008 and
2007:


2008
            
            
            2007Salaries,
      wages, payroll taxes and benefits
            
            $
            3,122
            
            
            $
            4,828Workers'
      compensation liability
            
            
            4,288
            
            
            
            2,959Sales,
      use and other taxes
            
            
            1,566
            
            
            
            8,122Health
      insurance
            
            
            1,773
            
            
            
            409Deferred
      revenue
            
            
            4,048
            
            
            
            1,720Accrued
      interest
            
            
            1,452
            
            
            
            1,242$
            16,249
            
            
            $
            19,280


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 2007 was an accrual of
interest in the amount of $634, of which $404, $227 and $3 related to 2007, 2006
and 2005, respectively.  The 2007 adjustment also included additional
depreciation expense in the amount of $1,167, of which $684, $459 and $24
related to 2007, 2006 and 2005, respectively.  The Company determined
this adjustment was not material to either the 2007, 2006 or 2005 annual
financial statements.


-39-
 Table of Contents




5.
Long-term Debt




Long-term
debt consists of the following:





December
      31,
            
            
            December
      31,2008
            
            
            2007Notes
      payable to De Lage Landen Financial Services, collateralized by
      cranes,payable
      in ninety-six monthly principal and interest installments of
      $61Interest
      on the notes ranges from 6.74% - 7.07%, with various due dates
      (1)
            
            $
            3,234
            
            
            $
            5,120Revolving
      credit facility with Fortis Capital Corp., collateralized by the Company's
      assets,and
      matures on September 29, 2013.  Loans under the revolving credit
      facilitybear
      interest at variable rates as defined in the credit agreement.
      (2)
            
            
            111,100
            
            
            
            60,000Note
      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)
            
            
            1,442
            
            
            
            1,521Notes
      payable to General Motors Acceptance Corporation, collateralized by
      trucks, payable
              in
      monthly principal and interest installments of $65, various due dates.
      (4)
            
            
            1,623
            
            
            
            1,184Note
      payable to John Deere Construction & Forestry Company, collaterized by
      forklifts,
              payable
      in thirty-six monthly installments of $11, due December 1, 2009
      (5)
            
            
            124
            
            
            
            258Note
      payable to Ford Motor Credit, collateralized by truck, payable in
      principal and interestinstallments
      of $1 Interest
      on the note is 2.9%, due November 10, 2010. (6)
            
            
            24
            
            
            
            35117,547
            
            
            
            68,118Less
      current installments
            
            
            1,464
            
            
            
            1,256$
            116,083
            
            
            $
            66,862


(1)
            On
      December 7, 2005, January 4, 2006, and June 12, 2006, 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 $4,512. The proceeds of the term loans were
      used to purchase four 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 book runner, and a syndicate of lenders.  On
      September 29, 2008, the Company amended and restated this revolving credit
      facility.  This $150.0 million amended and restated credit
      facility is with Fortis Bank SA/NV, New York Branch, as administrative
      agent, joint lead arranger and sole bookrunner, and a syndicate of
      lenders, which include The Royal Bank of Scotland plc, The CIT
      Group/Business Credit, Inc., The Prudential Insurance Company of America,
      Legacy Bank, Natixis and Caterpillar Financial Services Corporation. The
      revolving credit facility matures on September 29, 2013.  Loans
      under the revolving credit facility bear interest at LIBOR plus a 4.0%
      margin or, at our option, the prime rate plus a 3.0%
      margin.   The Company incurred $3,501 in debt issue costs
      related to the amended and restated credit
  facility.





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, 2008 and 2007 were $405 and $257,
respectively.  The Company’s domestic 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 equity interests 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 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 1.05 to 1.00 for the four
consecutive quarters ending March 31, 2009, 1.10 to 1.00 for the four
consecutive quarters ending June 30, 2009 and 1.15 to 1.00 for the four
consecutive quarters ending September 30, 2009 and each quarter thereafter and a
maximum total leverage ratio of 2.00 to 1.00. The Company was in compliance with
all covenants at December 31, 2008.  The revolving credit facility
provides for mandatory prepayments under certain circumstances.





(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 and 2008, the Company entered into term loan
      agreements with General Motors Acceptance Corporation.  The
      loans provide for term installments in an aggregate not to exceed
      $2,282.  The proceeds of the term loans were used to purchase 57
      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, 2008 is as
follows:


2009
            
            $
            1,4642010
            
            
            1,3442011
            
            
            8892012
            
            
            7692013
            
            
            111,9072014
      and thereafter
            
            
            1,174$
            117,547


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 Table of Contents




6. 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, 2008, 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, 2008, the tax years ended December 31,
2005 through December 31, 2007 are open for examination by U.S. taxing
authorities.




Income
tax expense (benefit) consists of the following


Years
      Ended December 31,2008
            
            
            2007
            
            
            2006Current:State
            
            $
            (165
            )
            
            $
            541
            
            
            $
            2,456Federal
            
            
            (874
            )
            
            
            4,915
            
            
            
            14,363Deferred:State
            
            
            (415
            )
            
            
            1,878
            
            
            
            2,023Federal
            
            
            (3,707
            )
            
            
            15,770
            
            
            
            19,214Income
      tax expense (benefit)
            
            $
            (5,161
            )
            
            $
            23,104
            
            
            $
            38,056


Deferred
income tax assets and liabilities are as follows:





Years
      Ended December 31,2008
            
            
            2007Deferred
      tax assets:Stock
      option expense
            
            $
            3,170
            
            
            $
            2,609Alternative
      minimum tax credit carryforward
            
            
            2,225
            
            
            
            2,095Net
      operating loss carryforwards
            
            
            3,441
            
            
            
            -Accounts
      receivable allowance
            
            
            1,481
            
            
            
            -Tax
      credits
            
            
            875
            
            
            
            -Employee
      benefits and insurance accruals
            
            
            488
            
            
            
            -Other
            
            
            484
            
            
            
            775Total
      deferred tax assets
            
            
            12,164
            
            
            
            5,479Deferred
      tax liabilities:Property
      and equipment, principally dueto
      differences in depreciation and impairments
            
            
            75,330
            
            
            
            72,767Other
            
            
            64
            
            
            
            -Total
      deferred tax liabilities
            
            
            75,394
            
            
            
            72,767Net
      deferred tax liabilities
            
            $
            63,230
            
            
            $
            67,288


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% to net income. The differences are
summarized as follows:







Years
      Ended December 31,2008
            
            
            2007
            
            
            2006Expected
      tax expense (benefit)
            
            $
            (4,692
            )
            
            $
            21,244
            
            
            $
            34,261State
      income taxes (benefit)
            
            
            (345
            )
            
            
            2,246
            
            
            
            3,622Tax
      basis adjustment to 35% for prior year deferred tax
    components
            
            
            -
            
            
            
            -
            
            
            
            562Nondeductible
      officer compensation
            
            
            330
            
            
            
            98
            
            
            
            -Nondeductible
      meals and entertainment
            
            
            68
            
            
            
            45
            
            
            
            47Domestic
      production activities
            
            
            -
            
            
            
            (83
            )
            
            
            (467
            )Goodwill
      impairment
            
            
            1,125
            
            
            
            -
            
            
            
            -Foreign
      tax credit
            
            
            (832
            )
            
            
            -
            
            
            
            -Prior
      year estimate adjustment
            
            
            (295
            )
            
            
            -
            
            
            
            -Other
            
            
            (520
            )
            
            
            (446
            )
            
            
            31$
            (5,161
            )
            
            $
            23,104
            
            
            $
            38,056





7. 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 $10,030 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, 2008 and 2007, the Company had deposits of $0 and $2,745,
respectively, with an insurance company collateralizing a letter of credit. The
deposits are reflected in restricted cash and deposit. Accrued expenses at
December 31, 2008 and 2007 included approximately $4,288 and $2,959,
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, 2008 and 2007 included approximately $1,773 and $409,
respectively, for our estimate of incurred but not reported costs related to the
self-insurance portion of our health insurance.




8.
Transactions with Affiliates




The Company
has six operating leases with affiliated entities.  Related rent
expense was approximately $572 and $130 for the years ended December 31, 2008
and 2007.


-41-
 Table of Contents





The Company
provided contract drilling services totaling $4,571, $2,617, and $10,025 to
affiliated entities for the years ended December 31, 2008, 2007, and
2006.   The Company provided workover services totaling $765 for
the year ended December 31, 2008.  The Company had receivables from
affiliates of $3,387 and $0 at December 31, 2008 and 2007,
respectively.  Additional information about our transactions with
affiliates is included in Note 3, Investment in
Challenger.




9.
Commitments and Contingencies




The Company
leases sixteen service locations under noncancelable operating leases that have
various expirations from 2009 to 2015. Related rent expense was $1,064, $790,
and $643 for the years ended December 31, 2008, 2007, and 2006,
respectively.




Aggregate
future minimum lease payments under the noncancelable operating leases for years
subsequent to December 31, 2008 are as follows:


2009
            
            $
            1,0732010
            
            
            9872011
            
            
            7992012
            
            
            5352013
            
            
            3892014
      and thereafter
            
            
            301$
            4,084




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




10.
Business Segments and Concentrations




The Company’s
reportable business segments are contract land drilling and well
servicing.  The contract land drilling segment utilizes a fleet of
land drilling rigs to provide contract drilling services to oil and natural gas
exploration and production companies.  During 2008 our rigs operated
in Oklahoma, Texas, Colorado, Montana, Utah, North Dakota, Louisiana, Wyoming,
and Mexico.  The well servicing segment encompasses a full range of
services performed with mobile well servicing rigs, 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 2008 our workover rigs
operated in Oklahoma, Texas, Kansas, Colorado, Louisiana, Arkansas, Wyoming, 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.




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


Contract
      land drilling
            
            
            Well
      servicing
            
            
            TotalYear
      ended December 31, 2008Operating
      Revenues
            
            $
            247,829
            
            
            $
            33,284
            
            
            $
            281,113Direct
      operating costs
            
            
            (148,866
            )
            
            
            (24,478
            )
            
            
            (173,344
            )Impairments
      of goodwill
            
            
            (21,115
            )
            
            
            (3,213
            )
            
            
            (24,328
            )Segment
      profits
            
            $
            77,848
            
            
            $
            5,593
            
            
            $
            83,441Depreciation
      and amortization
            
            $
            44,419
            
            
            $
            5,969
            
            
            $
            50,388Capital
      expenditures
            
            $
            79,136
            
            
            $
            8,138
            
            
            $
            87,274Identifiable
      assets
            
            $
            551,575
            
            
            $
            60,779
            
            
            $
            612,354Year
      ended December 31, 2007Operating
      Revenues
            
            $
            276,088
            
            
            $
            22,864
            
            
            $
            298,952Direct
      operating costs
            
            
            (153,797
            )
            
            
            (14,299
            )
            
            
            (168,096
            )Segment
      profits
            
            $
            122,291
            
            
            $
            8,565
            
            
            $
            130,856Depreciation
      and amortization
            
            $
            40,905
            
            
            $
            3,336
            
            
            $
            44,241Capital
      expenditures
            
            $
            58,857
            
            
            $
            23,925
            
            
            $
            82,782Identifiable
      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
      EndedDecember
      31, 2008
            
            
            December
      31, 2007Segment
      profits
            
            $
            83,441
            
            
            $
            130,856General
      and administrative expenses
            
            
            (33,771
            )
            
            
            (22,690
            )Depreciation
      and amortization
            
            
            (50,388
            )
            
            
            (44,241
            )Gain
      on Challenger transactions
            
            
            3,138
            
            
            
            -Operating
      income
            
            $
            2,420
            
            
            $
            63,925


For the year
ended December 31, 2008, revenue from one customer was approximately 11% of
total revenue, for 2007 revenue from one customer was approximately 11% of total
revenue, and for 2006 no one customer exceeded 10% of total
revenue.  At December 31, 2008, six customers accounted for
approximately 8%, 7%, 5%, 5%, 5%, and 5% of accounts receivable.  At
December 31, 2007, six customers accounted for approximately 13%, 12%, 9%, 8%,
5%, and 5% of accounts receivable.




Financial
instruments, which potentially subject the Company to concentrations of credit
risk, consist primarily of demand deposits, temporary cash investments and trade
receivables.




The Company
believes it has placed its demand deposits and temporary cash investments with
high credit-quality financial institutions.  At December 31, 2008, the
Company’s demand deposits and temporary cash investments consisted of the
following (in thousands):


2008
              
              
              2007Deposits
      in FDIC-insured institutions under insurance limits
              
              $
              905
              
              
              $
              540Deposits
      in FDIC-insured institutions over insurance limits
              
              
              30,082
              
              
              
              6,606Deposits
      in Foreign Banks
              
              
              281
              
              
              
              -31,268
              
              
              
              7,146Less
      outstanding checks and other reconciling items
              
              
              (4,592
              )
              
              
              (1,425
              )Cash
      and cash equivalents
              
              $
              26,676
              
              
              $
              5,721


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 Table of Contents




11.
Net Income (Loss) 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:


Year
      EndedDecember
      31,2008
            
            
            2007
            
            
            2006Basic:Net
      income (loss)
            
            $
            (8,243
            )
            
            $
            37,592
            
            
            $
            59,833Weighted
      average shares (thousands)
            
            
            26,293
            
            
            
            25,996
            
            
            
            24,585Income
      (loss) per share
            
            $
            (0.31
            )
            
            $
            1.45
            
            
            $
            2.43Diluted:Net
      income (loss)
            
            $
            (8,243
            )
            
            $
            37,592
            
            
            $
            59,833Weighted
      average shares:Outstanding
      (thousands)
            
            
            26,293
            
            
            
            25,996
            
            
            
            24,585Restricted
      Stock and Options (thousands)
            
            
            -
            
            
            
            105
            
            
            
            3826,293
            
            
            
            26,101
            
            
            
            24,623Income
      (loss) per share
            
            $
            (0.31
            )
            
            $
            1.44
            
            
            $
            2.43


The weighted
average number of diluted shares excludes 82,962 shares and 23,132 shares for
the years ended December 31, 2008 and 2007, respectively, for options and
restricted stock due to their antidilutive effects.




12.
Equity Transactions




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)




13.
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 $0, $1,029 and $2,658 for the years ended December 31,
2008, 2007 and 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 exercised 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.




On April 20,
2007, the Company filed a Tender Offer Statement on Schedule TO relating to the
Company’s offer to 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.  Half of the Restricted Stock Awards vested  on
January 1, 2008, and the balance of the Restricted Stock Awards vested
on January 1, 2009. 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
Company did not have any outstanding options at December 31, 2008. The Company
did not grant any options for the years ended December 31, 2007 and 2008. The
following table summarizes the assumptions used in the Black-Sholes
option-pricing model for the year ended December 31, 2006.


December
      31,2006Expected
      volatility
                
                48
                %Expected
      life in years
                
                5.77Weighted
      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, 2008, 2007 and 2006:


-43-
 Table of Contents




Weighted
              
              
              WeightedAverage
              
              
              Average
      Remaining
              
              
              AggregateExercise
      Price
              
              
              Contractual
              
              
              IntrinsicShares
              
              
              per
      Share
              
              
              Life
              
              
              ValueOptions
      outstanding at December 31, 2005
              
              
              574,500
              
              
              $
              18.08Granted
              
              
              445,500
              
              
              
              23.37Exercised
              
              
              -Forfeited/expired
              
              
              (188,333
              )
              
              
              20.38Options
      outstanding at December 31, 2006
              
              
              831,667
              
              
              $
              20.39
              
              
              
              8.91
              
              
              $
              (2,632
              )Granted
              
              
              -
              
              
              
              -Exercised
              
              
              -
              
              
              
              -Converted
              
              
              (769,000
              )
              
              
              20.14Forfeited/expired
              
              
              (42,667
              )
              
              
              22.23Options
      outstanding at December 31, 2007
              
              
              20,000
              
              
              $
              26.14
              
              
              
              8.30
              
              
              $
              (227
              )Granted
              
              
              -
              
              
              
              -Exercised
              
              
              -
              
              
              
              -Converted
              
              
              -
              
              
              
              -Forfeited/expired
              
              
              (20,000
              )
              
              
              26.14Options
      outstanding at December 31, 2008
              
              
              -
              
              
              $
              -
              
              
              
              -
              
              
              $
              -Options
      fully vested and exercisable at December 31, 2008
              
              
              -
              
              
              $
              -
              
              
              
              -
              
              
              $
              -


Weighted
      Average
              
              
              AggregateGrant
      Date
              
              
              Grant
      DateShares
              
              
              Fair
      Value
              
              
              Fair
      ValueOptions
      nonvested at December 31, 2005
              
              
              511,446
              
              
              $
              10.05
              
              
              $
              5,140Granted
              
              
              445,500
              
              
              
              11.93
              
              
              
              5,313Vested
              
              
              (255,520
              )
              
              
              10.90
              
              
              
              (2,785
              )Forfeited/expired
              
              
              (188,333
              )
              
              
              10.45
              
              
              
              (1,968
              )Options
      nonvested at December 31, 2006
              
              
              513,093
              
              
              $
              11.11
              
              
              $
              5,700Granted
              
              
              -
              
              
              
              -
              
              
              
              -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
              
              
              $
              121Granted
              
              
              -
              
              
              
              -
              
              
              
              -Vested
              
              
              -
              
              
              
              -
              
              
              
              -Converted
              
              
              -
              
              
              
              -
              
              
              
              -Forfeited/expired
              
              
              (9,319
              )
              
              
              13.34
              
              
              
              (121
              )Options
      nonvested at December 31, 2008
              
              
              -
              
              
              $
              -
              
              
              $
              -


As of
December 31, 2008, there was no unrecognized compensation cost related to
nonvested share-based compensation arrangements granted under the 2005 and 2006
Plans.




14.
Restricted Stock




Under all
restricted stock awards to date, 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, 2008, 2007 and 2006 related to shares of
restricted stock was $5,825, $2,699 and
$113 respectively.  Restricted stock activity for the years ended
December 31, 2008, 2007 and 2006 was as follows:


Weighted
      AverageGrant
      DateShares
              
              
              Fair
      ValueOutstanding
      at December 31, 2005
              
              
              -
              
              
              
              -Granted
              
              
              66,667
              
              
              $
              20.25Vested
              
              
              -
              
              
              
              -Forfeited/expired
              
              
              -
              
              
              
              -Outstanding
      at December 31, 2006
              
              
              66,667
              
              
              $
              20.25Granted
              
              
              125,000
              
              
              
              15.47Converted
              
              
              384,500
              
              
              
              16.58Vested
              
              
              (22,222
              )
              
              
              20.25Forfeited/expired
              
              
              (500
              )
              
              
              16.69Outstanding
      at December 31, 2007
              
              
              553,445
              
              
              $
              16.64Granted
              
              
              232,874
              
              
              
              13.98Vested
              
              
              (321,889
              )
              
              
              16.40Forfeited/expired
              
              
              (750
              )
              
              
              16.69Outstanding
      at December 31, 2008
              
              
              463,680
              
              
              $
              15.45


There was
$2,426 of total unrecognized compensation cost related to nonvested restricted
stock awards to be recognized over a weighted-average period of 1.06 years as of
December 31, 2008.


-44-
 Table of Contents




15.
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.




16.
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, 2008, 2007 and 2006 were $1,093, $1,030 and $698, respectively.




17.
Quarterly Results of Operations (unaudited)




The following
table summarizes quarterly financial data for our years ended December 31,
2008 and 2007:





Bronco
      Drilling Company Inc.Quarterly
      ResultsYear
      Ended December 31, 2008(Amounts
      in thousands except per share amounts)First
            
            
            Second
            
            
            Third
            
            
            FourthQuarter
            
            
            Quarter
            
            
            Quarter
      (1)
            
            
            Quarter
      (2)2008Revenues
            
            
            $
            67,003
            
            
            $
            68,307
            
            
            $
            72,920
            
            
            $
            76,021Income
      (loss) from operations
            
            
            
            11,206
            
            
            
            7,642
            
            
            
            (609
            )
            
            
            (15,819
            )Income
      tax expense (benefit)
            
            
            
            4,552
            
            
            
            2,655
            
            
            
            (60
            )
            
            
            (12,308
            )Net
      income (loss)
            
            
            
            8,148
            
            
            
            4,339
            
            
            
            (917
            )
            
            
            (19,813
            )Income
      (loss) per share:Basic
            
            
            
            0.31
            
            
            
            0.17
            
            
            
            (0.03
            )
            
            
            (0.75
            )Diluted
            
            
            
            0.31
            
            
            
            0.16
            
            
            
            (0.03
            )
            
            
            (0.75
            )(1)
      Includes
      $6,000 of failed merger costs.(2)
      Includes
      $24,328 and $14,442 of impairments of goodwill and Challenger
      investment.2007Revenues
            
            
            $
            78,981
            
            
            $
            74,720
            
            
            $
            76,286
            
            
            $
            68,965Income
      from operations
            
            
            
            19,643
            
            
            
            14,633
            
            
            
            18,648
            
            
            
            11,001Income
      tax expense
            
            
            
            7,101
            
            
            
            5,428
            
            
            
            7,009
            
            
            
            3,566Net
      income
            
            
            
            11,386
            
            
            
            8,714
            
            
            
            11,068
            
            
            
            6,424Income
      per share:Basic
            
            
            
            0.44
            
            
            
            0.33
            
            
            
            0.43
            
            
            
            0.25Diluted
            
            
            
            0.44
            
            
            
            0.33
            
            
            
            0.42
            
            
            
            0.25


-45-
 Table of Contents




18.
Valuation and Qualifying Accounts





The Company’s
valuation and qualifying accounts for the years ended December 31, 2008,
2007 and 2006 are as follows:




Valuation
      and Qualifying AccountsBalance
            
            
            Chargedat
            
            
            to
      Costs
            
            
            Deductions
            
            
            BalanceBeginning
            
            
            and
            
            
            from
            
            
            atof
      Year
            
            
            Expenses
            
            
            Accounts
            
            
            Year
      EndYear
      ended December 31, 2006Allowance
      for doubtful receivables
            
            $
            330
            
            
            $
            70
            
            
            $
            -
            
            
            $
            400Year
      ended December 31, 2007Allowance
      for doubtful receivables
            
            $
            400
            
            
            $
            4,370
            
            
            $
            (2,936
            )
            
            $
            1,834Year
      ended December 31, 2008Allowance
      for doubtful receivables
            
            $
            1,834
            
            
            $
            3,745
            
            
            $
            (1,749
            )
            
            $
            3,830


-46-
 Table of Contents


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 16, 2009
            By:
            /S/   D. FRANK
      HARRISOND.
      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 16, 2009/S/    ZACHARY M. GRAVES
                Zachary
      M. Graves
            Chief
      Financial Officer
              (Principal
      Accounting and Financial Officer)
            March 16, 2009/S/    David
      House
              David
      House
            Director
            March 16, 2009/S/    DAVID L. HOUSTON
                David
      L. Houston
            Director
            March 16, 2009/S/    GARY
      HILL
                Gary
      Hill
            Director
            March 16, 2009/S/    WILLIAM R. SNIPES
                William
      R. Snipes
            Director
            March 16,
2009


-47-