UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549


















FORM
10-Q


















(Mark
One)


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





For
the quarterly period ended June 30, 2009







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


Edmond,
OK 73013


(Address
of principal executive offices) (Zip Code)







(405)
242-4444


(Registrant’s
telephone number, including area code)









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





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, non-accelerated filer or a smaller reporting company. See the
definitions of “accelerated filer,” “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





As of
July 31, 2009, 27,217,459 shares of common stock were outstanding.








BRONCO
DRILLING COMPANY, INC.





INDEX




PagePART
      I—FINANCIAL INFORMATIONItem 1.
            
            Financial
      StatementsBronco
      Drilling Company, Inc.:Consolidated
      Balance Sheets as of June 30, 2009 (unaudited) and December 31,
      2008
            
            3Consolidated
      Statements of Operations for the three and six months ended June 30, 2009
      and 2008 (unaudited)
            
            4Consolidated
      Statement of Stockholders’ Equity for the six months ended June
      30,  2009 (unaudited)
            
            5Consolidated
      Statements of Cash Flows for the six months ended June 30, 2009 and 2008
      (unaudited)
            
            6Notes to
      Consolidated Financial Statements (unaudited)
            
            7Item 2.
            
            Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
            
            11Item 3.
            
            Quantitative
      and Qualitative Disclosures about Market Risks
            
            17Item 4.
            
            Controls
      and Procedures
            
            17PART
      II—OTHER INFORMATION
            
            18Item 1.
            
            Legal
      Proceedings
            
            18Item 1A.
            
            Risk
      Factors
            
            18Item 2.
            
            Unregistered Sale of Equity
      Securities and Use of Proceeds
            
            18Item 3.
            
            Defaults
      Upon Senior Securities
            
            18Item 4.
            
            Submission of Matters to Vote of
      Security Holders
            
            18Item 5.
            
            Other
      Information
            
            18Item 6.
            
            Exhibits
            
            19Signatures





-2-
 Table of Contents




Bronco Drilling Company, Inc. and
    SubsidiariesCONSOLIDATED BALANCE SHEETS(Amounts
      in thousands, except share par value)June
      30,
              
              
              December
      31,2009
              
              
              2008ASSETS
              
              (Unaudited)CURRENT
      ASSETSCash
      and cash equivalents
              
              $
              46,365
              
              
              $
              26,676ReceivablesTrade
      and other, net of allowance for doubtful accounts of$3,140
      and $3,830 in 2009 and 2008, respectively
              30,038
              
              
              
              65,817Unbilled
      receivables
              386
              
              
              
              2,940Income tax receivable
              1,550
              
              
              
              2,072Current
      deferred income taxes
              
              
              2,249
              
              
              
              2,844Current
      maturities of note receivable from affiliate
              
              
              1,932
              
              
              
              6,900Prepaid
      expenses
              
              
              1,213
              
              
              
              572Total
      current assets
              
              
              83,733
              
              
              
              107,821PROPERTY
      AND EQUIPMENT - AT COSTDrilling
      rigs and related equipment
              
              
              524,227
              
              
              
              512,158Transportation,
      office and other equipment
              
              
              43,504
              
              
              
              43,912567,731
              
              
              
              556,070Less
      accumulated depreciation
              
              
              147,412
              
              
              
              123,915420,319
              
              
              
              432,155OTHER
      ASSETSNote
      receivable from affiliate, less current maturities
              
              
              1,521
              
              
              
              3,451Investment
      in Challenger
              
              
              62,318
              
              
              
              62,875Intangibles,
      net, and other
              
              
              4,757
              
              
              
              6,05268,596
              
              
              
              72,378$
              572,648
              
              
              $
              612,354LIABILITIES
      AND STOCKHOLDERS' EQUITYCURRENT
      LIABILITIESAccounts
      payable
              
              $
              3,628
              
              
              $
              18,473Accrued
      liabilities
              
              
              8,788
              
              
              
              16,249Current
      maturities of long-term debt
              
              
              86
              
              
              
              1,464Total
      current liabilities
              
              
              12,502
              
              
              
              36,186LONG-TERM
      DEBT,  less current maturities
              
              
              112,415
              
              
              
              116,083DEFERRED
      INCOME TAXES
              
              
              60,980
              
              
              
              66,074COMMITMENTS
      AND CONTINGENCIES (Note 6)STOCKHOLDERS'
      EQUITYCommon
      stock, $.01 par value, 100,000shares
      authorized; 26,657 and 26,346 sharesissued
      and outstanding at June 30, 2009 and December 31, 2008
              
              
              268
              
              
              
              267Additional
      paid-in capital
              
              
              305,622
              
              
              
              304,015Retained
      earnings
              
              
              80,861
              
              
              
              89,729Total
      stockholders' equity
              
              
              386,751
              
              
              
              394,011$
              572,648
              
              
              $
              612,354The
      accompanying notes are an integral part of these
    statements.
 
   -3-
 Table of Contents
 Bronco Drilling Company, Inc. and
      SubsidiariesCONSOLIDATED STATEMENTS OF OPERATIONS(Amounts
      in thousands, except per share amounts)Three
      Months Ended June 30,
                
                
                Six
      Months Ended June 30,2009
                
                
                2008
                
                
                2009
                
                
                2008(Unaudited)
                
                
                (Unaudited)REVENUESContract
      drilling revenues, including 0%, 2%, 0%,
                  and
      1% to related parties$
                26,498
                
                
                $
                60,494
                
                
                $
                74,323
                
                
                $
                114,567Well
      service, including 0%, 2%, 0%, and
                  1%
      to related parties1,020
                
                
                
                9,320
                
                
                
                3,799
                
                
                
                17,543Gain
      on Challenger transactions
                
                
                
                -
                
                
                
                (1,507
                )
                
                
                -
                
                
                
                3,20027,518
                
                
                
                68,307
                
                
                
                78,122
                
                
                
                135,310EXPENSESContract
      drilling
                
                
                18,234
                
                
                
                36,715
                
                
                
                48,078
                
                
                
                69,909Well
      service
                
                
                
                1,257
                
                
                
                6,079
                
                
                
                3,572
                
                
                
                11,022Depreciation
      and amortization
                
                
                11,962
                
                
                
                12,457
                
                
                
                24,488
                
                
                
                24,382General
      and administrative
                
                
                4,930
                
                
                
                5,414
                
                
                
                10,118
                
                
                
                11,15336,383
                
                
                
                60,665
                
                
                
                86,256
                
                
                
                116,466Income
      (loss) from operations
                (8,865
                )
                
                
                7,642
                
                
                
                (8,134
                )
                
                
                18,844OTHER
      INCOME (EXPENSE)Interest
      expense
                
                
                (1,855
                )
                
                
                (1,161
                )
                
                
                (4,154
                )
                
                
                (2,387
                )Interest
      income
                
                
                163
                
                
                
                274
                
                
                
                164
                
                
                
                1,009Equity
      in income (loss) of Challenger
                
                
                
                (969
                )
                
                
                (69
                )
                
                
                (557
                )
                
                
                1,776Other
                
                
                260
                
                
                
                308
                
                
                
                (306
                )
                
                
                453(2,401
                )
                
                
                (648
                )
                
                
                (4,853
                )
                
                
                851Income
      (loss) before income taxes
                
                
                (11,266
                )
                
                
                6,994
                
                
                
                (12,987
                )
                
                
                19,695Income
      tax expense (benefit)
                
                
                (4,108
                )
                
                
                2,655
                
                
                
                (4,119
                )
                
                
                7,208NET
      INCOME (LOSS)
                
                $
                (7,158
                )
                
                $
                4,339
                
                
                $
                (8,868
                )
                
                $
                12,487Income
      (loss) per common share-Basic
                
                $
                (0.27
                )
                
                $
                0.17
                
                
                $
                (0.33
                )
                
                $
                0.48Income
      (loss) per common share-Diluted
                
                $
                (0.27
                )
                
                $
                0.16
                
                
                $
                (0.33
                )
                
                $
                0.47Weighted
      average number of shares outstanding-Basic
                
                
                26,657
                
                
                
                26,270
                
                
                
                26,623
                
                
                
                26,267Weighted
      average number of shares outstanding-Diluted
                
                
                26,657
                
                
                
                26,388
                
                
                
                26,623
                
                
                
                26,340The
      accompanying notes are an integral part of these
    statements.
  -4-
 Table of Contents


Bronco
      Drilling Company Inc. and SubsidiariesCONSOLIDATED STATEMENT OF STOCKHOLDERS'
    EQUITY(Amounts
      in thousands)For
      the six months ended June 30, 2009(Unaudited)Additional
              
              
              
              
              
              TotalCommon
              
              
              Common
              
              
              Paid
      In
              
              
              Retained
              
              
              Stockholders'Shares
              
              
              Amount
              
              
              Capital
              
              
              Earnings
              
              
              EquityBalance
      as of January 1, 2009
              
              
              26,346
              
              
              $
              267
              
              
              $
              304,015
              
              
              $
              89,729
              
              
              $
              394,011Net
      loss
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (8,868
              )
              
              
              (8,868
              )Stock
      compensation
              
              
              311
              
              
              
              1
              
              
              
              1,607
              
              
              
              -
              
              
              
              1,608Balance
      as of June 30, 2009
              
              
              26,657
              
              
              $
              268
              
              
              $
              305,622
              
              
              $
              80,861
              
              
              $
              386,751The
      accompanying notes are an integral part of these
    statements.
  -5-
 Table of Contents
   Bronco Drilling Company, Inc. and
      SubsidiariesCONSOLIDATED STATEMENTS OF CASH FLOWS(Amounts
      in thousands)Six
      Months Ended June 30,2009
              
              
              2008(Unaudited)Cash
      flows from operating activities:Net
      income (loss)
              
              $
              (8,868
              )
              
              $
              12,487Adjustments
      to reconcile net income (loss) to net cashprovided
      by operating activities:Depreciation
      and amortization
              
              
              24,890
              
              
              
              24,674Bad
      debt expense
              
              
              1,069
              
              
              
              299(Gain)
      loss on sale of assets
              
              
              (8
              )
              
              
              240Gain
      on Challenger transactions
              
              
              -
              
              
              
              (3,200
              )Equity
      in income of Challenger
              
              
              557
              
              
              
              (1,776
              )Stock
      compensation
              
              
              1,608
              
              
              
              2,588Provision
      for deferred income taxes
              
              
              (4,498
              )
              
              
              7,208Changes
      in current assets and liabilities:Receivables
              
              
              34,427
              
              
              
              3,794Unbilled
      receivables
              
              
              2,554
              
              
              
              726Prepaid
      expenses
              
              
              (641
              )
              
              
              (696
              )Other
      assets
              
              
              449
              
              
              
              (116
              )Accounts
      payable
              
              
              (15,397
              )
              
              
              (9,318
              )Accrued
      expenses
              
              
              (7,461
              )
              
              
              1,867Income
      taxes receivable
              
              
              522
              
              
              
              (435
              )Net
      cash provided by operating activities
              
              
              29,203
              
              
              
              38,342Cash
      flows from investing activities:Restricted
      cash account
              
              
              -
              
              
              
              70Business
      acquisitions, net of cash acquired
              
              
              -
              
              
              
              (5,063
              )Principal
      payments on note receivable
              
              
              2,142
              
              
              
              -Proceeds
      from sale of assets
              
              
              543
              
              
              
              3,022Purchase
      of property and equipment
              
              
              (7,153
              )
              
              
              (40,159
              )Net
      cash used in investing activities
              
              
              (4,468
              )
              
              
              (42,130
              )Cash
      flows from financing activities:Proceeds
      from borrowings
              
              
              -
              
              
              
              10,000Payments
      of debt
              
              
              (5,046
              )
              
              
              (2,019
              )Net
      cash provided by (used in) financing activities
              
              
              (5,046
              )
              
              
              7,981Net
      increase in cash and cash equivalents
              
              
              19,689
              
              
              
              4,193Beginning
      cash and cash equivalents
              
              
              26,676
              
              
              
              5,721Ending
      cash and cash equivalents
              
              $
              46,365
              
              
              $
              9,914Supplementary
      disclosure of cash flow information:Interest
      paid, net of amount capitalized
              
              $
              5,318
              
              
              $
              1,848Income
      taxes (refunded) paid
              
              
              (143)
              
              
              
              435Supplementary
      disclosure of non-cash investing and financing:Assets
      exchanged/sold for equity interest and note receivable
              
              
              -
              
              
              
              72,376Note
      issued for acquisition of property and equipment
              
              
              -
              
              
              
              846Purchase
      of property and equipment in accounts payable
              
              
              552
              
              
              
              7,682Common
      stock received for payment of receivable
              
              
              -
              
              
              
              1,900Reduction
      of receivable for property and equipment
              
              
              5,040
              
              
              
              -The
      accompanying notes are an integral part of these
    statements.
  -6-
 Table of Contents
  Bronco Drilling Company, Inc. and Subsidiaries
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Unaudited)
 ($
Amounts in thousands, except per share amounts)
  Unless the
context requires otherwise, a reference in this quarterly report to “Bronco,”
the “Company,” “we,” “us,” and “our” are to Bronco Drilling Company, Inc., a
Delaware corporation, and its consolidated subsidiaries.
  1.
Organization and Summary of Significant Accounting Policies
  Business
and Principles of Consolidation
  Bronco
Drilling Company, Inc. 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 accompanying unaudited consolidated financial statements and
related notes in accordance with accounting principles generally accepted in the
United States of America for interim financial information and with the
instructions of Form 10-Q and Regulation S-X. 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.
  In
management’s opinion, the accompanying unaudited consolidated financial
statements contain all adjustments (consisting of normal recurring accruals)
necessary to present fairly the financial position of the Company as of June 30,
2009, the related results of operations for the three and six months ended June
30, 2009 and 2008 and the cash flows for the six months ended June 30, 2009 and
2008.  The information included in this Quarterly Report on Form 10-Q
should be read in conjunction with the Company’s Annual Report on Form 10-K for
the year ended December 31, 2008. In preparing the accompanying unaudited
consolidated financial statements, we have reviewed, as we have determined
necessary, events that have occurred after June 30, 2009 through the filing of
this Form 10-Q on August 10, 2009.
  The results
of operations for the three and six months ended June 30, 2009 are not
necessarily an indication of the results expected for the full
year.
  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 and money market mutual funds to be cash
equivalents.
  The Company
maintains its cash and cash equivalents in accounts and instruments which may
not be federally insured 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.
  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 $33,801 and $34,293 as of
June 30, 2009 and December 31, 2008, respectively.  Due to
immateriality, gains and losses on dispositions, with the exception of the
Challenger Limited 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 six months ended June 30, 2009 and 2008,
the Company capitalized $0 and $459, respectively, and for the three months
ended June 30, 2009 and 2008, the Company capitalized $0 and $77, 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.
  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% and effective state
tax rate of 3.7% (net of Federal income tax effects) were used for the enacted
tax rates for all periods.  The Company’s effective income tax rate
during the three and six months ended June 30, 2009 is higher than what would be
expected if the federal statutory rate were applied to income before income
taxes primarily because of certain stock compensation expenses recorded for
financial reporting purposes that are not deductible for tax
purposes.
  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
applies the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes — an interpretation of FASB Statement No. 109(“FIN 48”), which
addresses 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
recognizes interest and/or penalties related to income tax matters as income tax
expense. As of June 30, 2009, 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
accounts for stock-based compensation in accordance with SFAS No. 123(R),
“Share-Based
Payment.” SFAS No. 123(R) requires a public entity to measure
the costs of employee services received in exchange for an award of equity or
liability instruments based on the grant-date fair value of the award. That cost
will be recognized over the periods during which an employee is required to
provide service in exchange for the award.
  Recent
Accounting Pronouncements
 -7-
 Table of Contents
 
 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 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 the Company’s financial
statements.
 
 In June 2009,
the FASB issued SFAS No. 168 (“SFAS 168”), “The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles – a
replacement of FASB Statement No. 162.”On the effective date of
SFAS 168, the FASB Accounting
Standards Codification(“Codification”) will become the source of
authoritative U.S. generally accepted accounting principles. Following SFAS 168,
the FASB will not issue new standards in the form of Statements, FASB Staff
Positions or EITF Abstracts. Instead, it will issue Accounting Standards Updates
to update the Codification. SFAS 168 is effective for financial statements
issued for interim and annual periods ending after September 15, 2009 and
will be effective for the Company in the quarter ending September 30, 2009.
The adoption of FAS 168 will not have a material impact on the
Company.
  In December
2007, the FASB issued SFAS No. 141 (“SFAS 141R”) (revised 2007) “Business Combinations.” 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 adoption of the provisions of SFAS 141R did not have an
immediate impact on the Company’s 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 adoption of the provisions of SFAS 160
did not have a material impact on the Company’s 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 adoption of the provisions of SFAS 161 did not have a material
impact on the Company’s financial statements.
  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 adoption of this FSP did not 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 applies to
transactions that occur in fiscal years, and interim periods within those fiscal
years, beginning on or after December 15, 2008. The adoption of the provisions
EITF 08-6 did not have a material impact on the Company’s financial condition or
results of operations.
  In
April 2009, the FASB issued FASB Staff Position No. 107-1 and APB
No. 28-1, “Interim
Disclosures about Fair Value of Financial Instruments”(“FSP 107-1”).
This FSP increases the frequency of fair value disclosures as required by FAS
107, Disclosures about Fair
Value of Financial Instruments, from annual only to quarterly reporting
periods. The provisions of this FSP are effective for financial statements
issued for interim and annual periods ending after June 15, 2009 and became
effective for the Company in the quarter ended June 30, 2009. The adoption
of FSP 107-1 did not have a material impact on the Company’s financial
statements. The carrying amount of our cash and cash equivalents, trade
receivables, payables and debt approximate their fair values.
 
 In
June 2009 the FASB issued SFAS No. 165, “Subsequent Events,” which
requires entities to disclose the date through which they have evaluated
subsequent events and whether the date corresponds with the release of their
financial statements. The requirements of SFAS No. 165 are effective for
interim and annual periods ending after June 15, 2009. SFAS No. 165
did not have a material impact on the Company’s financial statements. See the
disclosure in the "Business and Principles of Consolidation" section
above.
  2.
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 June 30, 2009 was based on
64,957,265 shares outstanding.  The Company recorded equity in income
(loss) of investment of $(969) and $(557) for the three and six months ended
June 30, 2009, respectively, and $(69) and $1,776 for the three and six months
ended June 30, 2008, respectively, 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.  During
the second quarter of 2009, the Company and Challenger agreed to reduce the
installment receivable and term note by approximately $5,040 and the Company
assumed ownership of two drilling rigs that were originally sold to
Challenger.  The term note bears interest at 8.5%.  Interest
and principal payments of $529 on the note are due quarterly until maturity at
February 2, 2011.  The note receivable is collateralized by the assets
sold to Challenger.  The note receivable from Challenger at June 30,
2009 was $3,453, of which $1,932 was classified as current and $1,521 was
classified as long-term.
  The Company
recorded a net gain of $3,200 for the six months ended June 30, 2008 relating to
the exchange 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 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 $3,953 and $3,387 at June 30, 2009 and December
31, 2008, respectively, related to these services provided.
  At
June 30, 2009, the book value of the Company’s ordinary share investment in
Challenger was $62,318.  The Company’s 25% share of the net assets of
Challenger was estimated to be $37,124.  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.  Amortization recorded during the three and
six months ended June 30, 2009 was $322 and $644, respectively.  The
remaining excess of $9,751 is accounted for as equity method
goodwill.
 -8-
 Table of Contents
 
 Summarized
financial information of Challenger is presented below:
 Three
      Months Ended June 30,
              
              Six
      Months Ended June 30,2009
              
              
              2008
              
              2009
              
              
              2008Condensed
      statement of operations:Revenues
              
              $
              11,800
              
              
              $
              14,916
              
              $
              31,650
              
              
              $
              33,440Gross
      margin
              
              $
              2,823
              
              
              $
              6,676
              
              $
              12,338
              
              
              $
              16,871Net
      Income (loss)
              
              $
              (2,589
              )
              
              $
              (957
              )
              $
              348
              
              
              $
              5,597June
      30,
              
              
              December
      31,2009
              
              
              2008Condensed
      balance sheet:Current
      assets
              
              $
              66,600
              
              
              $
              50,837Noncurrent
      assets
              
              
              132,039
              
              
              
              141,558Total
      assets
              
              $
              198,639
              
              
              $
              192,395Current
      liabilities
              
              $
              26,633
              
              
              $
              26,944Noncurrent
      liabilities
              
              
              23,512
              
              
              
              17,304Equity
              
              
              148,494
              
              
              
              148,147Total
      liabilities and equity
              
              $
              198,639
              
              
              $
              192,395
 3.
Long-term Debt
  Long-term
debt consists of the following:
  June
      30,
              
              
              December
      31,2009
              
              
              2008Notes
      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%, repaid in March, 2009.
      (1)
              
              $
              -
              
              
              $
              3,234Revolving
      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
              
              
              
              111,100Note
      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)
              
              
              1,401
              
              
              
              1,442Notes
      payable to General Motors Acceptance Corporation, collateralized by
      trucks,
                payable
      in monthly principal and interest installments of $65, repaid in March,
      2009. (4)
              
              
              -
              
              
              
              1,623Note
      payable to John Deere Construction & Forestry Company, collaterized by
      forklifts,
                payable
      in thirty-six monthly installments of $11, repaid in March, 2009
      (5)
              
              
              -
              
              
              
              124Note
      payable to Ford Motor Credit, collateralized by truck, payable in
      principal and interestinstallments
      of $1.  Interest on the note is 2.9%, repaid in March, 2009.
      (6)
              
              
              -
              
              
              
              24112,501
              
              
              
              117,547Less
      current installments
              
              
              86
              
              
              
              1,464$
              112,415
              
              
              $
              116,083


(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.  The term loans were repaid in
      full on March 30, 2009.
 
 (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 three and six months ended June 30, 2009 were $159 and $304,
respectively, and for the three and six months ended June 30, 2008 were $56 and
$115, 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 June 30, 2009.  If oil and gas commodity prices
remain at low levels causing demand for our services to continue to decline, the
Company could be in violation of our revolving credit facility covenants during
2009, unless ratios are amended or the Company receives an infusion of
capital.  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.  The term loans were repaid in full on March 16,
      2009.
 
 (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.  The term loans were repaid
      in full on March 19, 2009.
 
 (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.  The term loan was repaid in full on
      March 24, 2009.
 -9-
 Table of Contents
 
 Long-term
debt maturing each year subsequent to June 30, 2009 is as
follows:
  2010
              
              $
              862011
              
              
              922012
              
              
              972013
              
              
              1032014
              
              
              111,2102015
      and thereafter
              
              
              913$
              112,501
 4.
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 $11,560 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.
Accrued expenses at June 30, 2009 and December 31, 2008 included approximately
$3,133 and $4,288, 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 $125 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
June 30, 2009 and December 31, 2008 included approximately $1,466 and
$1,773, respectively, for our estimate of incurred but not reported costs
related to the self-insurance portion of our health insurance.
  5.
Transactions with Affiliates
  The Company
has six operating leases with affiliated entities.  Related rent
expense was approximately $143 and $286 for the three and six months ended June
30, 2009, respectively, and $86 and $156 for the three and six months ended June
30, 2008, respectively.
  The Company
provided drilling and workover services totaling $1,346 and $1,362 to affiliated
entities during the three and six months ended June 30, 2008,
respectively.  The Company provided $0 in drilling and workover
services to affiliated entities during the three and six months ended June 30,
2009.
  The Company
had receivables from affiliates of $3,953 and $3,387 at June 30, 2009 and
December 31, 2008, respectively.
  Additional
information about our transactions with affiliates is included in Note 2, Investment in
Challenger.
  6.
Commitments and Contingencies
  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.
  7.
Business Segments
 
 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 the six months ended
June 30, 2009, our drilling rigs operated in Oklahoma, Texas, Colorado, Utah,
North Dakota, Louisiana, Pennsylvania, and Mexico.  The Company had
revenues of $3,864 and $6,874 from rigs operating in Mexico for the three months
and six months ended June 30, 2009, respectively.  The well servicing
segment encompasses a full range of services performed with a mobile well
servicing rig, including the installation and removal of downhole equipment and
elimination of obstructions in the well bore to facilitate the flow of oil and
gas. During the six months ended June 30, 2009, our workover rigs operated in
Oklahoma, Texas, Kansas, Colorado, Arkansas, and New Mexico.  During
the second quarter of 2009, the Company temporarily suspended its well servicing
operations.  The Company is currently evaluating this business unit
determining a plan for its redeployment in anticipation of more favorable market
conditions.  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
              
              
              TotalThree
      Months Ended June 30, 2009Operating
      Revenues
              
              $
              26,498
              
              
              $
              1,020
              
              
              $
              27,518Direct
      operating costs
              
              
              (18,234
              )
              
              
              (1,257
              )
              
              $
              (19,491
              )Segment
      profits
              
              $
              8,264
              
              
              $
              (237
              )
              
              $
              8,027Depreciation
      and amortization
              
              $
              10,285
              
              
              $
              1,677
              
              
              $
              11,962Capital
      expenditures
              
              $
              3,518
              
              
              $
              505
              
              
              $
              4,023Identifiable
      assets
              
              $
              518,007
              
              
              $
              54,641
              
              
              $
              572,648Three
      Months Ended June 30, 2008Operating
      Revenues
              
              $
              60,494
              
              
              $
              9,320
              
              
              $
              69,814Direct
      operating costs
              
              
              (36,715
              )
              
              
              (6,079
              )
              
              $
              (42,794
              )Segment
      profits
              
              $
              23,779
              
              
              $
              3,241
              
              
              $
              27,020Depreciation
      and amortization
              
              $
              11,027
              
              
              $
              1,430
              
              
              $
              12,457Capital
      expenditures
              
              $
              17,130
              
              
              $
              4,501
              
              
              $
              21,631Identifiable
      assets
              
              $
              534,738
              
              
              $
              65,051
              
              
              $
              599,789Contract
      land drilling
              
              
              Well
      servicing
              
              
              TotalSix
      Months Ended June 30, 2009Operating
      Revenues
              
              $
              74,323
              
              
              $
              3,799
              
              
              $
              78,122Direct
      operating costs
              
              
              (48,078
              )
              
              
              (3,572
              )
              
              $
              (51,650
              )Segment
      profits
              
              $
              26,245
              
              
              $
              227
              
              
              $
              26,472Depreciation
      and amortization
              
              $
              21,127
              
              
              $
              3,361
              
              
              $
              24,488Capital
      expenditures
              
              $
              6,426
              
              
              $
              727
              
              
              $
              7,153Identifiable
      assets
              
              $
              518,007
              
              
              $
              54,641
              
              
              $
              572,648Six
      Months Ended June 30, 2008Operating
      Revenues
              
              $
              114,567
              
              
              $
              17,543
              
              
              $
              132,110Direct
      operating costs
              
              
              (69,909
              )
              
              
              (11,022
              )
              
              $
              (80,931
              )Segment
      profits
              
              $
              44,658
              
              
              $
              6,521
              
              
              $
              51,179Depreciation
      and amortization
              
              $
              21,649
              
              
              $
              2,733
              
              
              $
              24,382Capital
      expenditures
              
              $
              32,470
              
              
              $
              7,689
              
              
              $
              40,159Identifiable
      assets
              
              $
              534,738
              
              
              $
              65,051
              
              
              $
              599,789


-10-
 Table of Contents
 
 The following
table reconciles the segment profits above to the operating income as reported
in the consolidated statements of operations:


Three
      Months Ended
              
              
              Three
      Months EndedJune
      30, 2009
              
              
              June
      30, 2008Segment
      profits
              
              $
              8,027
              
              
              $
              27,020General
      and administrative expenses
              
              
              (4,930
              )
              
              
              (5,414
              )Depreciation
      and amortization
              
              
              (11,962
              )
              
              
              (12,457
              )Gain
      on Challenger transaction
              
              
              -
              
              
              
              (1,507
              )Operating
      income (loss)
              
              $
              (8,865
              )
              
              $
              7,642Six
      Months Ended
              
              
              Six
      Months EndedJune
      30, 2009
              
              
              June
      30, 2008Segment
      profits
              
              $
              26,472
              
              
              $
              51,179General
      and administrative expenses
              
              
              (10,118
              )
              
              
              (11,153
              )Depreciation
      and amortization
              
              
              (24,488
              )
              
              
              (24,382
              )Gain
      on Challenger transaction
              
              
              -
              
              
              
              3,200Operating
      income (loss)
              
              $
              (8,134
              )
              
              $
              18,844
 8.
Net Income Per Common Share
  The following
table presents a reconciliation of the numerators and denominators of the basic
and diluted earnings per share (“EPS”) and diluted EPS comparisons as required
by SFAS No. 128:
 Three
      Months Ended
              
              
              Six
      Months EndedJune
      30,
              
              
              June
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008Basic:Net
      income (loss)
              
              $
              (7,158
              )
              
              $
              4,339
              
              
              $
              (8,868
              )
              
              $
              12,487Weighted
      average shares
              
              
              26,657
              
              
              
              26,270
              
              
              
              26,623
              
              
              
              26,267Earnings
      (loss) per share
              
              $
              (0.27
              )
              
              $
              0.17
              
              
              $
              (0.33
              )
              
              $
              0.48Diluted:Net
      income (loss)
              
              $
              (7,158
              )
              
              $
              4,339
              
              
              $
              (8,868
              )
              
              $
              12,487Weighted
      average shares:Outstanding
      (thousands)
              
              
              26,657
              
              
              
              26,270
              
              
              
              26,623
              
              
              
              26,267Restricted
      Stock and Options (thousands)
              
              
              -
              
              
              
              118
              
              
              
              -
              
              
              
              7326,657
              
              
              
              26,388
              
              
              
              26,623
              
              
              
              26,340Income
      (loss) per share
              
              $
              (0.27
              )
              
              $
              0.16
              
              
              $
              (0.33
              )
              
              $
              0.47
 The weighted average
number of diluted shares excludes 68,980 and 0 shares for the three months ended
June 30, 2009 and 2008, respectively, and 52,881 and 2,097 for the six months
ended June 30, 2009 and 2008, respectively, subject to restricted stock awards
due to their antidilutive effects.
  9.
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 three and six months ended June 30, 2009, related to shares of
restricted stock was $857 and $1,608, respectively, and for the three and six
months ended June 30, 2008 was $1,438 and $2,588,
respectively.  Restricted stock activity for the six months ended June
30, 2009 was as follows:
  Weighted
      AverageGrant
      DateShares
              
              
              Fair
      ValueOutstanding
      at December 31, 2008
              
              
              463,680
              
              
              $
              15.22Granted
              
              
              415,955
              
              
              
              5.28Vested
              
              
              (318,965
              )
              
              
              15.59Forfeited/expired
              
              
              -
              
              
              
              -Outstanding
      at June 30, 2009
              
              
              560,670
              
              
              $
              7.73
 There was
$2,903 of total unrecognized compensation cost related to nonvested restricted
stock awards to be recognized over a weighted-average period of 1.22 years as of
June 30, 2009.
  11.
Employee Benefit Plans
  The Company
implemented a new 401(k) retirement plan for its eligible employees during 2007.
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 three and six months ended June 30, 2009 were
$175 and $379, respectively, and for the three and six months ended June 30,
2008 were $282 and $540, respectively.
  ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations
  The following
discussion and analysis should be read in conjunction with the “Management’s
Discussion and Analysis of Financial Condition and Results of Operations”
section and audited consolidated financial statements and related notes thereto
included in our Annual Report on Form 10-K, filed with the Securities and
Exchange Commission, or SEC, on March 16, 2009 and with the unaudited
consolidated financial statements and related notes thereto presented in this
Quarterly Report on Form 10-Q.
  Disclosure
Regarding Forward-Looking Statements
  Our
disclosure and analysis in this Form 10-Q 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-Q that address activities, events or developments
that we expect, believe or anticipate will or may occur in the future are
forward-looking statements.
 -11-
 Table of Contents
 
 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-Q 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 “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and “Risk Factors” sections of
this Quarterly Report on Form 10-Q and our most recent Annual Report on Form
10-K. All forward-looking statements speak only as of the date of this Form
10-Q. 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.
  Overview
  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. As of July 31, 2009, we owned a fleet of 56 land
drilling rigs, of which 45 were marketed and 11 were held in inventory. We also
owned a fleet of 61 workover rigs, of which 0 were marketed and 61 were held in
inventory. As of June 30, 2009, we also owned a fleet of 60 trucks used to
transport our rigs.
  We commenced
operations in 2001 with the purchase of one stacked 650-horsepower drilling rig
that we refurbished and deployed. We subsequently made selective acquisitions of
both operational and inventoried drilling rigs, as well as ancillary equipment.
Our management team has significant experience not only with acquiring rigs, but
also with refurbishing and deploying inventoried rigs. We have successfully
refurbished and brought into operation 25 inventoried drilling rigs during the
period from November 2003 through December 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
three drilling rig refurbishment yards, significantly reduces our reliance on
outside machine shops and the attendant risk of third-party delays in our rig
refurbishment program.
  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.
  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 11 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. Generally, we will receive a percentage of the contracted dayrate during
the mobilization period. We account for these revenues as mobilization
fees.
  For the three
and six months ended June 30, 2009 and 2008 and years ended December 31, 2008,
2007 and 2006, our rig utilization rates, revenue days and average number of
operating rigs were as follows:


Three
      Months Ended
              
              
              Six
      Months EndedJune
      30,
              
              
              June
      30,
              
              
              Years
      Ended December 31,2009
              
              
              2008
              
              
              2009
              
              
              2008
              
              
              2008
              
              
              2007
              
              
              2006Average
      number of operating rigs
              
              
              46
              
              
              
              45
              
              
              
              45
              
              
              
              45
              
              
              
              44
              
              
              
              51
              
              
              
              45Revenue
      days
              
              
              1,311
              
              
              
              3,355
              
              
              
              3,672
              
              
              
              6,203
              
              
              
              12,712
              
              
              
              14,245
              
              
              
              15,202Utilization
      Rates
              
              
              32
              %
              
              
              82
              %
              
              
              45
              %
              
              
              76
              %
              
              
              79
              %
              
              
              76
              %
              
              
              93
              %
  The decrease
in the number of revenue days in the three and six month-periods ended June 30,
2009 as compared to the same periods in 2008 is attributable to a decrease in
our rig utilization rate.
 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 three
and six months ended June 30, 2009 and 2008 and years ended December 31,
2008 and 2007, our workover rig utilization rates, revenue hours and average
number of operating workover rigs were as follows:
  Three
      Months Ended
              
              
              Six
      Months EndedJune
      30,
              
              
              June
      30,
              
              
              Years
      Ended December 31,2009
              
              
              2008
              
              
              2009
              
              
              2008
              
              
              2008
              
              
              2007Average
      number of operating workover rigs
              
              
              52
              
              
              
              53
              
              
              
              52
              
              
              
              51
              
              
              
              52
              
              
              
              33Revenue
      hours
              
              
              3,374
              
              
              
              25,533
              
              
              
              11,386
              
              
              
              49,398
              
              
              
              91,591
              
              
              
              63,746Utilization
      Rates
              
              
              10
              %
              
              
              75
              %
              
              
              17
              %
              
              
              76
              %
              
              
              68
              %
              
              
              78
              %
  Due to the
continued deterioration in the well servicing business, the Company has
temporarily suspended operations in this segment.  The Company intends
to restructure this business unit in anticipation of more favorable market
conditions.




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.




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 three and six months ended June 30, 2009, the
Company recorded $3.1 million and $6.2 million, respectively, 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.


-12-
 Table of Contents





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





At
      June 30,
            
            
            At
      December 31,2009
            
            
            2008
            
            
            2007
            
            
            2006Crude
      oil (Bbl)
            
            $
            69.89
            
            
            $
            44.60
            
            
            $
            95.98
            
            
            $
            61.05Natural
      gas (Mmbtu)
            
            $
            3.84
            
            
            $
            5.62
            
            
            $
            7.48
            
            
            $
            6.30U.S.
      Land Rig Count
            
            
            874
            
            
            
            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 has led 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.  We are more likely to encounter losses on footage contracts
in years in which revenue rates are lower for all types of
contracts.




Revenues and
costs during a reporting period could be affected by contracts in progress at
the end of a reporting period that have not been completed before our financial
statements for that period are released. We had no footage contracts in progress
at June 30, 2009 and December 31, 2008.  At June 30, 2009
and December 31, 2008, our unbilled receivables totaled $386,000 and $2.9
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 $3.1 million and $3.8 million at June 30, 2009 and
December 31, 2008, respectively. Any allowance established is subject to
judgment and estimates made by management. We determine our allowance by
considering a number of factors, including the length of time trade accounts
receivable are past due, our previous loss history, our customer’s current
ability to pay its obligation to us and the condition of the general economy and
the industry as a whole. We write off specific accounts receivable when they
become uncollectible and payments subsequently received on such receivables
reduce the allowance for doubtful accounts.




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




Asset Impairment and
Depreciation—We review long-lived
assets to be held and used for impairment whenever events or changes in
circumstances indicate that the carrying amount of the assets may not be
recoverable.  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 and intangible assets
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 and intangible assets to its fair market value.  A
one percent write-down in the cost of our drilling equipment and intangible
assets as of June 30, 2009, would have resulted in a corresponding increase in
our net loss by approximately $2.7 million.




During the
first six months of 2009, demand for our services continued to decline and
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.  Management
believes that the contract drilling industry will continue to be cyclical and
rig utilization will fluctuate. Based on management’s expectations of future
trends, we estimate future cash flows over the life of the respective assets in
our assessment of impairment.  These estimates of cash flows are based
on historical cyclical trends in the industry as well as management’s
expectations regarding the continuation of these trends in the
future.  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.


-13-
 Table of Contents





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 three and six months ended June 30, 2008, we
capitalized approximately $77,000 and $459,000, respectively.  During
the three and six months ended June 30, 2009 we did not capitalize any
interest.




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 $857,000 and $1.6 million for
the three and six months ended June 30, 2009, respectively, and $1.4 million and
$2.6 million for the three and six months ended June 30, 2008,
respectively.




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




Other Accounting
Estimates—Our other accrued expenses as of June 30, 2009 and
December 31, 2008 included accruals of approximately $3.1 million and $4.3
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
$11.6 million for the benefit of various insurance companies as collateral for
retrospective premiums and retained losses which may become payable under the
terms of the underlying insurance contracts.  The letters of credit
are typically renewed annually.  No amounts have been drawn under the
letters of credit. We accrue for these costs as claims are incurred based on
cost estimates established for each claim by the insurance companies providing
the administrative services for processing the claims, including an estimate for
incurred but not reported claims, estimates for claims paid directly by us, our
estimate of the administrative costs associated with these claims and our
historical experience with these types of claims.  We also have a
self-insurance program for major medical, hospitalization and dental coverage
for employees and their dependents.  We recognize both reported and
incurred but not reported costs related to the self-insurance portion of our
health insurance.  Since the accrual is based on estimates of expenses
for claims, the ultimate amount paid may differ from accrued
amounts.




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 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 June 2009,
the FASB issued SFAS No. 168 (“SFAS 168”), “The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles – a
replacement of FASB Statement No. 162.”On the effective date of
SFAS 168, the FASB Accounting
Standards Codification(“Codification”) will become the source of
authoritative U.S. generally accepted accounting principles. Following SFAS 168,
the FASB will not issue new standards in the form of Statements, FASB Staff
Positions or EITF Abstracts. Instead, it will issue Accounting Standards Updates
to update the Codification. SFAS 168 is effective for financial statements
issued for interim and annual periods ending after September 15, 2009 and
will be effective for the us in the quarter ending September 30, 2009. The
adoption of FAS 168 will 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.  The adoption of the provisions of SFAS 141R
did not have an immediate impact 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"). 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 adoption of the
provisions of SFAS 141R did not have a material impact 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").  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 adoption of the provisions of SFAS 161 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.  The adoption of this FSP did not 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 applies to
transactions that occur in fiscal years, and interim periods within those fiscal
years, beginning on or after December 15, 2008.  The adoption of EITF
08-6 did not have a material impact on our consolidated financial
statements.




In
April 2009, the FASB issued FASB Staff Position No. 107-1 and APB
No. 28-1, “Interim
Disclosures about Fair Value of Financial Instruments”(“FSP 107-1”).
This FSP increases the frequency of fair value disclosures as required by FAS
107, "Disclosures about Fair
Value of Financial Instruments," from annual only to quarterly reporting
periods. The provisions of this FSP are effective for financial statements
issued for interim and annual periods ending after June 15, 2009 and became
effective for us in the quarter ended June 30, 2009. The adoption of FSP
107-1 did not have a material impact on our financial statements.




In
June 2009 the FASB issued SFAS No. 165, “Subsequent Events," which
requires entities to disclose the date through which they have evaluated
subsequent events and whether the date corresponds with the release of their
financial statements. The requirements of SFAS No. 165 are effective for
interim and annual periods ending after June 15, 2009. SFAS No. 165
did not have a material impact on our financial statements.


-14-
 Table of Contents




Recent
Highlights




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:Second
            
            $
            4.45
            
            
            $
            3.25
            
            
            $
            72.68
            
            
            $
            45.88First
            
            $
            6.07
            
            
            $
            3.63
            
            
            $
            54.34
            
            
            $
            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 our dayrates and
utilization rates also tend to decline.  In addition, lower commodity
prices for any sustained period of time could impact the liquidity condition of
some of our customers, which, in turn, might limit their ability to meet their
financial obligations to us.




The impact on
our business and financial results as a consequence of the 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 significantly reduced our total 2009 estimated capital expenditures
      for our business segments 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 for 2009,
      resulting in a significant reduction in the average utilization of our
      drilling and workover rig fleet.  Our average contract land
      drilling utilization was approximately 83% for the three months ended
      December 31, 2008, 58% for the first quarter of 2009 and 32% for the
      second quarter of 2009




·
            The
      Company has temporarily suspended operations in our well
      servicing segment.  The Company intends to restructure this
      business unit in anticipation of more favorable market
      conditions.




Results of
Operations




Three
Months Ended June 30, 2009 Compared to Three Months Ended June 30,
2008




Contract Drilling
Revenue. For the three months ended June 30, 2009, we reported
contract drilling revenues of $26.5 million, a 56% decrease from revenues of
$60.5 million for the same period in 2008. The decrease is primarily due to a
decrease in average dayrates and total revenue days for the three months
ended June 30, 2009 as compared to the same period in 2008. Average dayrates for
our drilling services decreased $208, or 1%, to $16,124 for the three months
ended June 30, 2009 from $16,332 in the same period in 2008. Revenue days
decreased 61% to 1,311 days for the three months ended June 30, 2009 from 3,355
days during the same period in 2008. The decrease in the number of revenue days
for the three months ended June 30, 2009 as compared to the same period in 2008
is primarily due to a decrease in the utilization rate for the same
period.  Utilization decreased to 32% for the three months ended June
30, 2009 from 82% for the same period in 2008.  During the second
quarter of 2009, the Company recorded $3.1 million of contract drilling revenue
related to terminated contracts.




Well Service
Revenue.For the three months ended June 30, 2009, we reported
well service revenues of approximately $1.0 million, an 89% decrease from
revenues of $9.3 million for the same period in 2008.  The decrease is
primarily due to a decrease in revenue hours.  Revenue hours decreased
87% to 3,374 hours for the three months ended June 30, 2009 from 25,533 hours
during the same period in 2008.  The decrease in revenue hours for the
three months ended June 30, 2009 compared to the same period in 2008 is due to a
decrease in the utilization rate for the same time period and a decrease in the
average operating rigs for the same time period.  Utilization
decreased to 10% for the three months ended June 30, 2009 from 75% for the same
period in 2008.  The average operating rigs decreased 2%, or 1 rig,
from 53 for the three months ended June 30, 2008 to 52 for the same period in
2009.




Equity in Loss of
Challenger.Equity in loss of Challenger was $969,000 for the
three months ended June 30, 2009 related to our investment in Challenger
compared to a loss of $69,000 for the three months ended June 30,
2008.  The equity in loss of Challenger represents our 25% share of
Challenger’s loss.  For the three months ended June 30, 2009,
Challenger had operating revenues of $11.8 million and operating costs of $9.0
million compared to $14.9 million and $8.2 million for the three months ended
June 30, 2008.




Contract Drilling
Expense. Direct rig cost decreased $18.5 million to $18.2 million
for the three months ended June 30, 2009 from $36.7 million for the same period
in 2008. This 50% decrease is primarily due to the decrease in revenue days for
the three months ended June 30, 2009 as compared to the same period in
2008.  As a percentage of contract drilling revenue, drilling expense
increased to 69% for the three-month period ended June 30, 2009 from 61% for the
same period in 2008 due primarily to a general increase in the cost of supplies
and materials.




Well Service
Expense. Well service expense decreased $4.8 million to $1.3 million for
the three months ended June 30, 2009 from $6.1 million for the same period in
2008.  This 79% decrease is primarily due to the decrease in revenue
hours for the three months ended June 30, 2009 as compared to the same period in
2008.




Depreciation and
Amortization Expense.Depreciation expense decreased $494,000 to $12.0
million for the three months ended June 30, 2009 from $12.5 million for the same
period in 2008. The decrease is primarily due to assets that are fully
depreciated.




General and Administrative
Expense. General and administrative expense decreased $484,000 to
$4.9 million for the three months ended June 30, 2009 from $5.4 million for the
same period in 2008. The decrease is the result of a decrease in stock
compensation expense of $581,000 and a decrease in yard expense of
$252,000.  The decrease in stock compensation expense is primarily due
to stock grants with higher grant date fair values becoming fully
amortized.  The decrease in yard expense is primarily due to decreased
activity in the yards as a result of the slowdown of our rig refurbishment
program.  These decreases were partially offset by an increase in
accounts receivable write-offs of $478,000.




Interest
Expense. Interest expense increased $694,000 to $1.9 million for the
three months ended June 30, 2009 from $1.2 million for the same period in 2008.
The increase is due to an increase in the average outstanding balance under our
revolving credit facility and a decrease in the capitalization of interest
expense related to our rig refurbishment program.  We capitalized $0
of interest for the three months ended June 30, 2009 compared to $77,000 of
interest for the same period in 2008.




Income Tax Expense. We recorded
an income tax benefit of $4.1 million for the three months ended June 30, 2009.
This compares to an income tax expense of $2.7 million for the three months
ended June 30, 2008.  This decrease is primarily due to a $18.3
million decrease in pre-tax income to a pre-tax loss of $11.3 million for the
three months ended June 30, 2009 from pre-tax income of $7.0 million for the
three months ended June 30, 2008.


-15-
 Table of Contents




Six
months Ended June 30, 2009 Compared to Six months Ended June 30,
2008




Contract Drilling
Revenue. For the six months ended June 30, 2009, we reported
contract drilling revenues of $74.3 million, a 35% decrease from revenues of
$114.6 million for the same period in 2008. The decrease is primarily due to a
decrease in average dayrates and total revenue days for the six months
ended June 30, 2009 as compared to the same period in 2008. Average dayrates for
our drilling services decreased $80, or 1%, to $16,511 for the six months ended
June 30, 2009 from $16,591 in the same period in 2008. Revenue days decreased
41% to 3,672 days for the six months ended June 30, 2009 from 6,203 days during
the same period in 2008. The decrease in the number of revenue days for the six
months ended June 30, 2009 as compared to the same period in 2008 is primarily
due to a decrease in the utilization rate for the same
period.  Utilization decreased to 45% for the six months ended June
30, 2009 from 76% for the same period in 2008.  During the first six
months of 2009, the Company recorded $6.2 million of contract drilling revenue
related to terminated contracts.





Well Service
Revenue.For the six months ended June 30, 2009, we reported
well service revenues of approximately $3.8 million, a 78% decrease from
revenues of $17.5 million for the same period in 2008.  The decrease
is primarily due to a decrease in revenue hours.  Revenue hours
decreased 77% to 11,386 hours for the six months ended June 30, 2009 from 49,398
hours during the same period in 2008.  The decrease in revenue hours
for the six months ended June 30, 2009 compared to the same period in 2008 is
due to a decrease in the utilization rate for the same time period partially
offset by an increase in the average operating rigs for the same time
period.  Utilization decreased to 17% for the six months ended June
30, 2009 from 76% for the same period in 2008.  The average operating
rigs increased 2%, or 1 rig, from 51 for the six months ended June 30, 2008 to
52 for the same period in 2009.




Equity in Income
(Loss) of Challenger.Equity in loss of Challenger was
$557,000 for the six months ended June 30, 2009 related to our investment in
Challenger compared to equity in income of $1.8 million for the six months ended
June 30, 2008.  The equity in loss of Challenger represents our 25%
share of Challenger’s income.  For the six months ended June 30, 2009,
Challenger had operating revenues of $31.7 million and operating costs of $19.3
million compared to $33.4 million and $16.6 million for the six months ended
June 30, 2008.




Contract Drilling
Expense. Direct rig cost decreased $21.8 million to $48.1 million
for the six months ended June 30, 2009 from $69.9 million for the same period in
2008. This 31% decrease is primarily due to the decrease in revenue days for the
six months ended June 30, 2009 as compared to the same period in
2008.  As a percentage of contract drilling revenue, drilling expense
increased to 65% for the three-month period ended June 30, 2009 from 61% for the
same period in 2008 due primarily to a general increase in the cost of supplies
and materials.




Well Service
Expense. Well service expense decreased $7.4 million to $3.6 million for
the six months ended June 30, 2009 from $11.0 million for the same period in
2008.  This 68% decrease is primarily due to the decrease in revenue
hours for the six months ended June 30, 2009 as compared to the same period in
2008.




Depreciation and
Amortization Expense.Depreciation expense increased $106,000 to $24.5
million for the six months ended June 30, 2009 from $24.4 million for the same
period in 2008. The increase is primarily due to the 11% increase in fixed
assets.




General and Administrative
Expense. General and administrative expense decreased $1.1 million
to $10.1 million for the six months ended June 30, 2009 from $11.2 million for
the same period in 2008. The decrease is the result of a decrease in stock
compensation expense of $979,000 and a decrease in yard expense of
$495,000.  The decrease in stock compensation expense is primarily due
to stock grants with higher grant date fair values becoming fully
amortized.  The decrease in yard expense is primarily due to decreased
activity in the yards as a result of the slowdown of our rig refurbishment
program.  These decreases were partially offset by an increase in
accounts receivable write-offs of $769,000.




Interest
Expense. Interest expense increased $1.8 million to $4.2 million for
the six months ended June 30, 2009 from $2.4 million for the same period in
2008. The increase is due to an increase in the average outstanding balance
under our revolving credit facility and a decrease in the capitalization of
interest expense related to our rig refurbishment program.  We
capitalized $0 of interest for the six months ended June 30, 2009 compared to
$459,000 of interest for the same period in 2008.




Income Tax Expense. We recorded
an income tax benefit of $4.1 million for the six months ended June 30, 2009.
This compares to an income tax expense of $7.2 million for the six months ended
June 30, 2008.  This decrease is primarily due to a $32.7 million
decrease in pre-tax income to a pre-tax loss of $13.0 million for the six months
ended June 30, 2009 from pre-tax income of $19.7 million for the six months
ended June 30, 2008.  The Company’s effective income tax rate is
higher than what would be expected if the federal statutory rate were applied to
income before income taxes primarily because of certain stock compensation
expenses recorded for financial reporting purposes that are not deductible for
tax purposes.




Liquidity
and Capital Resources




OperatingActivities. Net cash provided by
operating activities was $31.3 million for the six months ended June 30, 2009 as
compared to $38.3 million in 2008. The decrease of $7.0 million from 2008 to
2009 was primarily due to a decrease in cash receipts from customers, partially
offset by a decrease in cash payments to suppliers.




Investing
Activities. We use a significant
portion of our cash flows from operations and financing activities for
acquisitions and the refurbishment of our rigs. Cash used in investing
activities was $6.6 million for the six months ended June 30, 2009 as compared
to $42.1 million for the same period in 2008.   For the six
months ended June 30, 2009, we used $7.2 million to purchase fixed
assets.  This amount was partially offset by $543,000 of proceeds
received from the sale of assets.  For the six months ended June 30,
2008, we used $40.2 million to purchase fixed assets and $5.1 million to
purchase an equity interest in Challenger.  These amounts were
partially offset by $3.0 million of proceeds received from the sale of
assets.




Financing
Activities. Our cash flows used in
financing activities were $5.0 million for the six months ended June 30, 2009 as
compared to $8.0 million provided by financing activities for the same period in
2008.  For the six months ended June 30, 2009 our net cash used in
financing activities related to principal payments of $5.0 million to various
lenders.  For the six months ended June 30, 2008, our net cash
provided by financing activities related to borrowings of $10.0 million under
our credit facility with Fortis Bank SA/NV, New York Branch, and borrowings of
$846,000 from various lenders, partially offset by principal payments of $2.0
million to various lenders.




Sources of
Liquidity. Our primary sources of
liquidity are cash from operations, debt 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 June 30, 2009.




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
three and six months ended June 30, 2009 were $159,000 and $304,000,
respectively, and for the three and six months ended June 30, 2008 were $56,000
and $115,000, 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 June 30, 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 June 30,
2009.  If oil and gas commodity prices remain at low levels causing
demand for our services to continue to decline, we could be in violation of our
revolving credit facility covenants during 2009, unless ratios are amended or we
receive an infusion of capital. 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.




At December
31, 2008 we were 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.  These loans were paid in full in March of 2009.


-16-
 Table of Contents





We are party
to a term loan agreement with Ameritas Life Insurance Corp. for an aggregate
principal amount of approximately $1.4 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%.




Working
Capital.Our working capital was $71.9 million at June 30,
2009 compared to $71.6 million at December 31, 2008.  Our current
ratio, which we calculate by dividing our current assets by our current
liabilities, was 6.8 at June 30, 2009 compared to 3.0 at December 31,
2008.




We believe
that the liquidity shown on our balance sheet as of June 30, 2009, which
includes approximately $71.9 million in working capital (including $46.4 million
in cash) and availability under our $150.0 million credit facility with $111.1
million outstanding at June 30, 2009, 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 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):


June
      30,
            
            
            December
      31,2009
            
            
            2008
            
            
            ChangeCash
      and cash equivalents
            
            $
            46,365
            
            
            $
            26,676
            
            
            $
            19,689Trade
      and other receivables
            
            
            30,038
            
            
            
            65,817
            
            
            
            (35,779
            )Unbilled
      receivables
            
            
            386
            
            
            
            2,940
            
            
            
            (2,554
            )Income
      tax receivable
            
            
            1,550
            
            
            
            2,072
            
            
            
            (522
            )Current
      deferred income taxes
            
            
            2,249
            
            
            
            2,844
            
            
            
            (595
            )Current
      maturities of note receivable
            
            
            1,932
            
            
            
            6,900
            
            
            
            (4,968
            )Prepaid
      expenses
            
            
            1,213
            
            
            
            572
            
            
            
            641Current
      assets
            
            
            83,733
            
            
            
            107,821
            
            
            
            (24,088
            )Current
      debt
            
            
            86
            
            
            
            1,464
            
            
            
            (1,378
            )Accounts
      Payable
            
            
            3,628
            
            
            
            18,473
            
            
            
            (14,845
            )Accrued
      liabilities and deferred revenues
            
            
            8,788
            
            
            
            16,249
            
            
            
            (7,461
            )Current
      liabilities
            
            
            12,502
            
            
            
            36,186
            
            
            
            (23,684
            )Working
      capital
            
            $
            71,231
            
            
            $
            71,635
            
            
            $
            (404
            )


The increase
in cash and cash equivalents was primarily due to the reduction in trade and
other receivables of $35.8 million, partially offset by the reduction in current
debt and accounts payable of $1.4 million and $14.8 million,
respectively.




The decrease
in trade receivables and other receivables as well as accounts payable at June
30, 2009 as compared to December 31, 2008 was due to a continued reduction in
revenue days and utilization rates during the first six months of 2009 compared
to 2008.  Utilization for the six months ended June 30, 2009 was 45%
compared to 79% for 2008.




The decrease
in accrued liabilities was due to a decrease in deferred revenue of
approximately $3.4 million due to the reduction in the deferral of mobilization
revenue, a $1.5 million reduction in accrued interest, and a $1.4 million
decrease in accrued salaries and related.  The decrease in our
deferral of mobilization revenue is due to the reduction in revenue days and
utilization rates during the second quarter of 2009.




Item 3. Quantitative and Qualitative Disclosures About Market
Risks




We are
subject to market risk exposure related to changes in interest rates on our
outstanding floating rate debt. Borrowings under our revolving credit facility
bear interest at a floating rate equal to LIBOR plus a margin that can range
from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range
from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to
Adjusted EBITDA, as defined in our credit agreement with Fortis Bank, SA/NV, New
York Branch. 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 June 30, 2009.




Item 4.
Controls and Procedures




Evaluation of
Disclosure Control and Procedures.




As of the end
of the period covered by this Quarterly Report on Form 10−Q, 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 June 30, 2009 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 Quarterly
Report on Form 10−Q was prepared, as appropriate to allow timely decision
regarding the required disclosure.




Changes in Internal
Control over Financial Reporting.




There were no
changes in our internal control over financial reporting that occurred during
the first six months of 2009 that have materially affected, or are reasonably
likely to materially affect, our internal control over financial
reporting.


-17-
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PART
II: OTHER INFORMATION




Item 1.
Legal Proceedings




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




Item 1A.
Risk Factors




There have
been no material changes to the Risk Factors previously disclosed in our Annual
Report on Form 10-K for the year ended December 31, 2008 filed with the SEC
on March 16, 2009.




Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds




None.




Item 3.
Defaults Upon Senior Securities




None.




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




None.




Item 5.
Other Information




None.




Item 6.
Exhibits




Exhibits:




Exhibit
              No.
            Description2.1
            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).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).*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.





*
            Filed
      herewith.





-18-
 Table of Contents




SIGNATURE




Pursuant to
the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on their behalf by the undersigned, thereunto
duly authorized.




BRONCO
      DRILLING COMPANY, INC.Dated:
      August 10, 2009
            
            By:
            
            /s/
      Zachary M. GravesZachary
      M. GravesChief
      Financial Officer(Principal
      Accounting and Financial Officer)Dated:
      August 10, 2009
            
            By:
            
            /s/
      D. Frank HarrisonD.
      Frank HarrisonChief
      Executive Officer(Authorized
      Officer and Principal Executive
Officer)