e10vq
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2009
OR
     
o   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: 1-16337
OIL STATES INTERNATIONAL, INC.
 
(Exact name of registrant as specified in its charter)
     
Delaware   76-0476605
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
     
Three Allen Center, 333 Clay Street, Suite 4620,
Houston, Texas
  77002
(Zip Code)
(Address of principal executive offices)    
(713) 652-0582
 
(Registrant’s telephone number, including area code)
None
 
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YES þ       NO o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)
YES o       NO o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
      Large accelerated filer þ    Accelerated filer o    Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES o       NO þ
The Registrant had 49,770,334 shares of common stock outstanding and 3,232,118 shares of treasury stock as of October 30, 2009.
 
 

 


 

OIL STATES INTERNATIONAL, INC.
INDEX
         
    Page No.
Part I — FINANCIAL INFORMATION
       
 
       
Item 1. Financial Statements:
       
 
       
Condensed Consolidated Financial Statements
       
    3  
    4  
    5  
    6 - 15  
 
       
    16 - 27  
 
       
    27  
 
       
    27  
 
       
       
 
       
    28  
 
       
    28  
 
       
    28  
 
       
    28  
 
       
    28  
 
       
    29  
 
       
    29  
 
       
    29  
 
       
    30  
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
                                 
    THREE MONTHS ENDED     NINE MONTHS ENDED  
    SEPTEMBER 30,     SEPTEMBER 30,  
    2009     2008     2009     2008  
            AS ADJUSTED             AS ADJUSTED  
            (NOTE 11)             (NOTE 11)  
Revenues
  $ 456,103     $ 814,790     $ 1,579,536     $ 2,047,401  
 
                       
 
                               
Costs and expenses:
                               
Cost of sales and services
    353,845       609,354       1,235,747       1,532,874  
Selling, general and administrative expenses
    33,964       37,494       102,377       105,577  
Depreciation and amortization expense
    30,193       27,325       86,863       75,741  
Impairment of goodwill
                94,528        
Other operating income
    (439 )     (893 )     (181 )     (659 )
 
                       
 
    417,563       673,280       1,519,334       1,713,533  
 
                       
Operating income
    38,540       141,510       60,202       333,868  
 
                               
Interest expense
    (3,613 )     (5,656 )     (11,714 )     (18,416 )
Interest income
    27       940       350       2,756  
Equity in earnings of unconsolidated affiliates
    250       431       1,184       3,167  
Gain on sale of investment
          3,452             6,160  
Other income/(expense)
    91       (458 )     193       (264 )
 
                       
Income before income taxes
    35,295       140,219       50,215       327,271  
Income tax expense
    (8,594 )     (52,040 )     (30,637 )     (114,125 )
 
                       
Net income
    26,701       88,179       19,578       213,146  
Less: Net income attributable to noncontrolling interest
    122       98       357       327  
 
                       
Net income attributable to Oil States International, Inc.
  $ 26,579     $ 88,081     $ 19,221     $ 212,819  
 
                       
 
                               
Net income per share attributable to Oil States International, Inc. common stockholders
                               
Basic
  $ 0.54     $ 1.77     $ 0.39     $ 4.29  
Diluted
  $ 0.53     $ 1.68     $ 0.39     $ 4.10  
 
                               
Weighted average number of common shares outstanding:
                               
Basic
    49,653       49,811       49,584       49,622  
Diluted
    50,153       52,322       49,886       51,949  
The accompanying notes are an integral part of
these financial statements.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In Thousands)
                 
    SEPTEMBER 30,     DECEMBER 31,  
    2009     2008  
            AS ADJUSTED  
            (NOTE 11)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 61,281     $ 30,199  
Accounts receivable, net
    361,549       575,982  
Inventories, net
    485,304       612,488  
Prepaid expenses and other current assets
    13,730       18,815  
 
           
Total current assets
    921,864       1,237,484  
 
               
Property, plant, and equipment, net
    726,877       695,338  
Goodwill, net
    217,627       305,441  
Investments in unconsolidated affiliates
    4,893       5,899  
Other non-current assets
    35,335       54,356  
 
           
Total assets
  $ 1,906,596     $ 2,298,518  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 190,385     $ 371,789  
Income taxes
    10,555       52,546  
Current portion of long-term debt
    446       4,943  
Deferred revenue
    117,872       105,640  
Other current liabilities
    850       1,587  
 
           
Total current liabilities
    320,108       536,505  
 
               
Long-term debt
    192,657       449,058  
Deferred income taxes
    55,691       64,780  
Other noncurrent liabilities
    12,445       12,634  
 
           
Total liabilities
    580,901       1,062,977  
 
               
Stockholders’ equity:
               
Oil States International, Inc. stockholders’ equity:
               
Common stock
    530       526  
Additional paid-in capital
    463,920       453,733  
Retained earnings
    920,222       901,001  
Accumulated other comprehensive income/(loss)
    32,403       (28,409 )
Treasury stock
    (92,341 )     (91,831 )
 
           
Total Oil States International, Inc. stockholders’ equity
    1,324,734       1,235,020  
 
           
Noncontrolling interest
    961       521  
 
           
Total stockholders’ equity
    1,325,695       1,235,541  
 
           
Total liabilities and stockholders’ equity
  $ 1,906,596     $ 2,298,518  
 
           
The accompanying notes are an integral part of
these financial statements.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
                 
    NINE MONTHS  
    ENDED SEPTEMBER 30,  
    2009     2008  
            AS ADJUSTED  
            (NOTE 11)  
Cash flows from operating activities:
               
Net Income
  $ 19,578     $ 213,146  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    86,863       75,741  
Deferred income tax provision (benefit)
    (12,774 )     10,910  
Excess tax benefits from share-based payment arrangements
          (3,367 )
Loss on impairment of goodwill
    94,528        
Equity in earnings of unconsolidated subsidiaries, net of dividends
    (1,184 )     (2,914 )
Non-cash compensation charge
    8,614       7,968  
Accretion of debt discount
    5,016       4,670  
Gains on sale of investment and disposals of assets
    (439 )     (6,602 )
Other, net
    2,526       1,946  
Changes in working capital
    149,547       4,476  
 
           
Net cash flows provided by operating activities
    352,275       305,974  
 
               
Cash flows from investing activities:
               
Acquisitions of businesses, net of cash acquired
    18       (29,835 )
Capital expenditures
    (78,164 )     (206,731 )
Proceeds from note receivable
    21,166        
Proceeds from sale of investment
          27,381  
Other, net
    (1,778 )     3,103  
 
           
Net cash flows used in investing activities
    (58,758 )     (206,082 )
 
               
Cash flows from financing activities:
               
Revolving credit repayments
    (264,528 )     (73,188 )
Debt repayments
    (4,839 )     (4,816 )
Issuance of common stock
    2,237       8,628  
Purchase of treasury stock
          (4,026 )
Excess tax benefits from share-based payment arrangements
          3,367  
Other, net
    (505 )     (1,120 )
 
           
Net cash flows used in financing activities
    (267,635 )     (71,155 )
 
               
Effect of exchange rate changes on cash
    5,333       (3,664 )
 
           
Net increase in cash and cash equivalents from continuing operations
    31,215       25,073  
Net cash used in discontinued operations — operating activities
    (133 )     (44 )
Cash and cash equivalents, beginning of period
    30,199       30,592  
 
           
 
               
Cash and cash equivalents, end of period
  $ 61,281     $ 55,621  
 
           
 
               
Non-cash investing and financing activities:
               
Building capital lease
  $     $ 8,304  
Non-cash financing activities:
               
Reclassification of 2 3/8% contingent convertible senior notes to current liabilities
          147,497  
The accompanying notes are an integral part of these
financial statements.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
     The accompanying unaudited consolidated financial statements of Oil States International, Inc. and its wholly-owned subsidiaries (referred to in this report as we or the Company) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission pertaining to interim financial information. Certain information in footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted pursuant to these rules and regulations. The unaudited financial statements included in this report reflect all the adjustments, consisting of normal recurring adjustments, which the Company considers necessary for a fair presentation of the results of operations for the interim periods covered and for the financial condition of the Company at the date of the interim balance sheet. Results for the interim periods are not necessarily indicative of results for the full year.
     Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosed amounts of contingent assets and liabilities and the reported amounts of revenues and expenses. If the underlying estimates and assumptions, upon which the financial statements are based, change in future periods, actual amounts may differ from those included in the accompanying condensed consolidated financial statements.
     From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.
     The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2008. Further, in connection with preparation of the consolidated financial statements and in accordance with current accounting standards, the Company evaluated subsequent events after the balance sheet date of September 30, 2009 through the time of filing on November 4, 2009. There were no material subsequent events requiring additional disclosure in or amendment to the quarterly financial statements as of November 4, 2009.
2. RECENT ACCOUNTING PRONOUNCEMENTS
     From time to time, new accounting pronouncements are issued by the FASB that are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.
     In September 2006, the FASB issued a new accounting standard on fair value measurements, which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. This accounting standard does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. It is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued an accounting standards update deferring the effective date of the fair value accounting standard for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption was permitted, provided the company had not yet issued financial statements, including for interim periods, for that fiscal year. We adopted those provisions of this accounting standard that were unaffected by the delay in the first quarter of 2008. In the first quarter of 2009, we adopted the remaining provisions of this accounting standard. Certain assets are measured at fair value on a nonrecurring basis; that is, they are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment). Such adoption did not have a material effect on our consolidated statements of financial position, results of operations or cash flows.

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     In September 2009, the FASB issued an accounting standards update effective for this and future reporting periods on measuring the fair value of liabilities. Implementation is not expected to have a material impact on the Company’s financial condition, results of operation or disclosures contained in our notes to the condensed consolidated financial statements.
     In December 2007, the FASB issued a new accounting standard on business combinations. The new accounting standard establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The accounting standard also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. The accounting standard 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, and interim periods within those fiscal years. The accounting standard was effective beginning January 1, 2009; accordingly, any business combinations we engage in after this date will be recorded and disclosed in accordance with this accounting standard. No business combination transactions occurred during the nine months ended September 30, 2009.
     In December 2007, the FASB also issued a new accounting standard on noncontrolling interests in consolidated financial statements. This accounting standard requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. It also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This accounting standard applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. The new accounting standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. This accounting standard applies prospectively, except for presentation and disclosure requirements, which are applied retrospectively. Effective January 1, 2009, we have presented our noncontrolling interests in accordance with this standard.
     In May 2008, the FASB issued a new accounting standard on the accounting for convertible debt instruments that can be settled in cash upon conversion (including partial cash settlement), which changed the accounting for our Contingent Convertible Senior Subordinated 2 3/8% Notes (2 3/8% Notes). Under the new rules, for convertible debt instruments that can be settled entirely or partially in cash upon conversion, an entity is required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The difference between bond cash proceeds and the estimated fair value is recorded as a debt discount and accreted to interest expense over the expected life of the bond. Although this accounting standard has no impact on the Company’s actual past or future cash flows, it requires the Company to record a material increase in non-cash interest expense as the debt discount is amortized. The accounting standard became effective for the Company beginning January 1, 2009 and is applied retrospectively to all periods presented. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this quarterly report on Form 10-Q.
     In May 2009, the FASB issued a new accounting standard on subsequent events, which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Under the new accounting standard, as under current practice, an entity must record the effects of subsequent events that provide evidence about conditions that existed at the balance sheet date and must disclose but not record the effects of subsequent events which provide evidence about conditions that did not exist at the balance sheet date. This accounting standard is effective for fiscal years, and interim periods within those fiscal years, ending after June 15, 2009. The adoption of this accounting standard did not have a material impact on the Company’s financial condition, results of operation or disclosures contained in our notes to the condensed consolidated financial statements.
     In June 2009, the FASB issued a new accounting standard, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” This new accounting standard established the “FASB Accounting Standards Codification,” or FASB ASC, as the source of authoritative GAAP recognized by the FASB for non-governmental entities. All existing accounting standards have been superseded and accounting literature not included in the FASB ASC is considered non-authoritative. Subsequent issuances of new standards will be in the

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form of Accounting Standards Updates, or ASU, that will be included in the ASC. Generally, the FASB ASC is not expected to change GAAP. Pursuant to the adoption of this new accounting standard, we have adjusted references to authoritative accounting literature in our financial statements. Adoption of this standard had no effect on our financial condition, results of operations or cash flows.
     In October 2009, the FASB issued an accounting standards update that modified the accounting and disclosures for revenue recognition in a multiple-element arrangement. These amendments, effective for fiscal years beginning on or after June 15, 2010 (early adoption is permitted), modify the criteria for recognizing revenue in multiple- element arrangements and the scope of what constitutes a non-software deliverable. The Company is currently assessing the impact of these amendments on its financial condition and results of operations.
3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS
     Additional information regarding selected balance sheet accounts is presented below (in thousands):
                 
    SEPTEMBER 30,     DECEMBER 31,  
    2009     2008  
Accounts receivable, net:
               
Trade
  $ 261,906     $ 456,975  
Unbilled revenue
    102,951       119,907  
Other
    1,895       3,268  
 
           
Total accounts receivable
    366,752       580,150  
Allowance for doubtful accounts
    (5,203 )     (4,168 )
 
           
 
  $ 361,549     $ 575,982  
 
           
                 
    SEPTEMBER 30,     DECEMBER 31,  
    2009     2008  
Inventories, net:
               
Tubular goods
  $ 289,447     $ 396,462  
Other finished goods and purchased products
    73,588       88,848  
Work in process
    63,153       65,009  
Raw materials
    67,923       68,881  
 
           
Total inventories
    494,111       619,200  
Inventory reserves
    (8,807 )     (6,712 )
 
           
 
  $ 485,304     $ 612,488  
 
           
                         
    ESTIMATED     SEPTEMBER 30,     DECEMBER 31,  
    USEFUL LIFE     2009     2008  
Property, plant and equipment, net:
                       
Land
          $ 19,240     $ 18,298  
Buildings and leasehold improvements
  3-50 years     160,615       135,080  
Machinery and equipment
  2-29 years     286,895       270,434  
Accommodations assets
  10-15 years     369,046       300,765  
Rental tools
  4-10 years     152,307       141,644  
Office furniture and equipment
  1-10 years     29,523       26,506  
Vehicles
  2-10 years     71,774       68,645  
Construction in progress
            50,518       49,915  
 
                   
Total property, plant and equipment
            1,139,918       1,011,287  
Less: Accumulated depreciation
            (413,041 )     (315,949 )
 
                   
 
          $ 726,877     $ 695,338  
 
                   
                 
    SEPTEMBER 30,     DECEMBER 31,  
    2009     2008  
Accounts payable and accrued liabilities:
               
Trade accounts payable
  $ 124,190     $ 307,132  
Accrued compensation
    34,680       35,864  
Accrued insurance
    8,559       7,551  
Accrued taxes, other than income taxes
    9,274       7,257  
Reserves related to discontinued operations
    2,412       2,544  
Other
    11,270       11,441  
 
           
 
  $ 190,385     $ 371,789  
 
           

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4. EARNINGS PER SHARE
     The calculation of earnings per share attributable to Oil States International, Inc. is presented below (in thousands, except per share amounts):
                                 
    THREE MONTHS ENDED   NINE MONTHS ENDED
    SEPTEMBER 30   SEPTEMBER 30,
    2009   2008   2009   2008
            AS ADJUSTED           AS ADJUSTED
            (NOTE 11)           (NOTE 11)
Basic earnings per share:
                               
Net income attributable to Oil States International, Inc.
  $ 26,579     $ 88,081     $ 19,221     $ 212,819  
 
                               
Weighted average number of shares outstanding
    49,653       49,811       49,584       49,622  
 
                               
Basic earnings per share
  $ 0.54     $ 1.77     $ 0.39     $ 4.29  
 
                               
Diluted earnings per share:
                               
Net income attributable to Oil States International, Inc.
  $ 26,579     $ 88,081     $ 19,221     $ 212,819  
 
                               
Weighted average number of shares outstanding
    49,653       49,811       49,584       49,622  
Effect of dilutive securities:
                               
Options on common stock
    338       490       213       509  
2 3/8% Convertible Senior Subordinated Notes
    51       1,900       17       1,694  
Restricted stock awards and other
    111       121       72       124  
 
                               
Total shares and dilutive securities
    50,153       52,322       49,886       51,949  
 
                               
Diluted earnings per share
  $ 0.53     $ 1.68     $ 0.39     $ 4.10  
     Our calculation of diluted earnings per share for the three and nine months ended September 30, 2009 excludes 1,190,149 shares and 1,826,143 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect. Our calculation of diluted earnings per share for the three and nine months ended September 30, 2008 excludes anti-dilutive shares of 266,063 and 378,605, respectively.
5. BUSINESS ACQUISITIONS AND GOODWILL
     On February 1, 2008, we purchased all of the equity of Christina Lake Enterprises Ltd., an accommodations lodge (Christina Lake Lodge) in the Conklin area of Alberta, Canada. Christina Lake Lodge provides lodging and catering in the southern area of the oil sands region. Consideration for the lodge consisted of $6.9 million in cash, net of cash acquired, including transaction costs, funded from borrowings under the Company’s existing credit facility, and the assumption of certain liabilities. The Christina Lake Lodge has been included in the accommodations business within the well site services segment since the date of acquisition.
     On February 15, 2008, we acquired a waterfront facility on the Houston ship channel for use in our offshore products segment. This waterfront facility expanded our ability to manufacture, assemble, test and load out larger subsea production and drilling rig equipment thereby expanding our capabilities. Consideration paid for the facility was approximately $22.9 million in cash, including transaction costs, funded from borrowings under the Company’s existing credit facility.
     In June 2009, we acquired the 51% majority interest in a venture we had previously accounted for under the equity method. The business acquired supplies accommodations and other services to mining operations in Canada. Consideration paid for the business was $2.3 million in cash and estimated contingent consideration of $0.3 million.

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     Changes in the carrying amount of goodwill for the nine month period ended September 30, 2009 are as follows (in thousands):
                                         
    Balance as of     Acquisitions     Foreign currency             Balance as of  
    January 1,     and     translation and     Goodwill     September 30,  
    2009     adjustments     other changes     impairment     2009  
Offshore Products
  $ 85,074     $     $ 464     $     $ 85,538  
Well Site Services
    220,367       337       5,913       (94,528 )     132,089  
 
                             
Total
  $ 305,441     $ 337     $ 6,377     $ (94,528 )   $ 217,627  
 
                             
     Based on a combination of factors (including the current global economic environment, the Company’s outlook for U.S. drilling activity and pricing and the current market capitalization for the Company and comparable oilfield service companies), and consistent with methodologies utilized by the Company in the past as described in its Annual Report on Form 10-K for the year ended December 31, 2008, the Company concluded that the goodwill amounts previously recorded in its rental tools reporting unit were partially impaired as of June 30, 2009. The total goodwill impairment charge recognized was $94.5 million before taxes and $82.7 million after-tax. This non-cash charge did not impact the Company’s liquidity position, its debt covenants or cash flows. The fair value measurements used for our goodwill impairment testing use significant unobservable Level 3 inputs which reflect our own assumptions about the assumptions that market participants would use in measuring fair value including assumptions about risk.
6. DEBT
     As of September 30, 2009 and December 31, 2008, long-term debt consisted of the following (in thousands):
                 
    September 30,     December 31,  
    2009     2008  
    (Unaudited)     As Adjusted  
            (Note 11)  
U.S. revolving credit facility which matures on December 5, 2011, with available commitments up to $325 million and with an average interest rate of 1.4% for the nine month period ended September 30, 2009
  $ 28,000     $ 226,000  
Canadian revolving credit facility which matures on December 5, 2011, with available commitments up to $175 million and with an average interest rate of 1.9% for the nine month period ended September 30, 2009
          61,244  
2 3/8% contingent convertible senior subordinated notes, net — due 2025
    154,126       149,110  
Subordinated unsecured notes payable to sellers of businesses, interest rate of 6%, matured in 2009
          4,500  
Capital lease obligations and other debt
    10,977       13,147  
 
           
Total debt
    193,103       454,001  
Less: current maturities
    (446 )     (4,943 )
 
           
Total long-term debt
  $ 192,657     $ 449,058  
 
           
     As of September 30, 2009, we have classified the $175.0 million principal amount of our 2 3/8% Notes, net of unamortized discount, as a noncurrent liability because certain contingent conversion thresholds based on the Company’s stock price were not met at that date and, as a result, note holders could not present their notes for conversion during the quarter following the September 30, 2009 measurement date. The future convertibility and resultant balance sheet classification of this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company’s common stock during the prescribed measurement periods.
     In May 2008, the FASB issued a new accounting standard on the accounting for convertible debt instruments that can be settled in cash upon conversion (including partial cash settlement), which changed the accounting for our 2 3/8% Notes. Under the new rules, for convertible debt instruments that can be settled entirely or partially in cash upon conversion, an entity is required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. This accounting standard became effective for the Company beginning January 1, 2009, and is applied retrospectively to all periods presented. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this quarterly report on Form 10-Q.
     As of September 30, 2009, the Company had approximately $61.3 million of cash and cash equivalents and $450.3 million of the Company’s $500 million U.S. and Canadian revolving credit facility was available for future financing needs.

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     The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, notes receivable, payables, and debt instruments. The Company believes that the carrying values of these instruments, other than our fixed rate contingent convertible senior notes, on the accompanying consolidated balance sheets approximate their fair values.
     The fair value of our 2 3/8% contingent convertible senior notes is estimated based on prices quoted from third-party financial institutions. The carrying and fair values of these notes are as follows (in thousands):
                                         
            September 30, 2009     December 31, 2008  
    Interest     Carrying     Fair     Carrying     Fair  
    Rate     Value     Value     Value     Value  
Principal amount due 2025
    2 3/8 %   $ 175,000     $ 222,766     $ 175,000     $ 133,613  
Less: Unamortized discount
            (20,874 )           (25,890 )      
 
                               
 
Net value
          $ 154,126     $ 222,766     $ 149,110     $ 133,613  
 
                               
     As of September 30, 2009, the estimated fair value of the Company’s debt outstanding under its revolving credit facility is estimated to be lower than carrying value since the terms of this facility are more favorable than those that might be expected to be available in the current credit and lending environment. We are unable to estimate the fair value of the Company’s bank debt due to the potential variability of expected outstanding balances under the facility.
7. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING:
     Comprehensive income for the three and nine months ended September 30, 2009 and 2008 was as follows (dollars in thousands):
                                 
    THREE MONTHS     NINE MONTHS  
    ENDED SEPTEMBER 30,     ENDED SEPTEMBER 30,  
    2009     2008     2009     2008  
            As Adjusted             As Adjusted  
            (Note 11)             (Note 11)  
Net income
  $ 26,701     $ 88,179     $ 19,578     $ 213,146  
Other comprehensive income:
                               
Cumulative translation adjustment
    28,957       (26,722 )     60,812       (35,182 )
Unrealized gain on marketable securities, net of tax
          365             2,170  
Reclassification adjustment, net of tax
          (2,170 )           (2,170 )
 
                       
Total other comprehensive income
    28,957       (28,527 )     60,812       (35,182 )
 
                       
Comprehensive income
    55,658       59,652       80,390       177,964  
Comprehensive income attributable to noncontrolling interest
    (122 )     (98 )     (357 )     (327 )
 
                       
Comprehensive income attributable to Oil States International, Inc.
  $ 55,536     $ 59,554     $ 80,033     $ 177,637  
 
                       
         
Shares of common stock outstanding — January 1, 2009
    49,500,708  
Shares issued upon exercise of stock options and vesting of stock awards
    273,734  
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury
    (25,473 )
 
       
Shares of common stock outstanding — September 30, 2009
    49,748,969  
 
       
8. STOCK BASED COMPENSATION
     During the first nine months of 2009, we granted restricted stock awards totaling 191,772 shares valued at $3.6 million. A total of 121,500 of these awards vest in four equal annual installments, 25,500 awards vest in their entirety only after three years of service, 43,328 awards made to directors vest after one year and the remaining 1,444 awards vested immediately as part of compensation paid to the chairman of the Company’s board of directors. A total of 768,650 stock options were awarded in the nine months ended September 30, 2009 with an average exercise price of $17.20 and a six-year term. A total of 714,450 of these options vest in annual 25% increments over the next four years and the remaining 54,200 options vest in their entirety only after three years of service.
     Stock based compensation pre-tax expense recognized in the nine month period ended September 30, 2009 totaled $8.6 million, or $0.12 per diluted share after tax (excluding the impact on the Company’s effective tax rate of the goodwill impairment recognized during the period.) Stock based compensation pre-tax expense recognized in

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the nine month period ended September 30, 2008 totaled $8.0 million, or $0.10 per diluted share after tax. Stock based compensation pre-tax expense recognized in the three month period ended September 30, 2009 totaled $2.8 million, or $0.04 per diluted share after tax (excluding the impact on the Company’s effective tax rate of the goodwill impairment.) Stock based compensation pre-tax expense recognized in the three month period ended September 30, 2008 totaled $2.8 million, or $0.03 per diluted share after tax. The total fair value of restricted stock awards that vested during the nine months ended September 30, 2009 was $2.7 million. At September 30, 2009, $18.6 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.
9. INCOME TAXES
     Income tax expense for interim periods is based on estimates of the effective tax rate for the entire fiscal year. The Company’s income tax provision for the three months ended September 30, 2009 totaled $8.6 million, or 24.3% of pretax income, compared to $52.0 million, or 37.1% of pretax income, for the three months ended September 30, 2008. The decrease in the effective tax rate from the prior year was largely the result of proportionately higher foreign sourced income in 2009 compared to 2008 which is taxed at lower statutory rates, coupled with domestic benefits derived from estimated tax losses. The Company’s income tax provision for the nine months ended September 30, 2009 totaled $30.6 million, or 61.0% of pretax income, compared to $114.1 million, or 34.9% of pretax income, for the nine months ended September 30, 2008. The effective tax rate for the nine months ended September 30, 2009 was negatively impacted by a significant amount of the goodwill impairment charges that were non-deductible for tax purposes. Excluding the goodwill impairment, the effective tax rate for the nine months ended September 30, 2009 would have approximated 29.3%. The decrease in the effective tax rate (excluding the goodwill impairment) from the prior year is largely the result of proportionately higher foreign sourced income in 2009 compared to 2008, which is taxed at lower statutory rates, coupled with domestic benefits derived from estimated tax losses.
10. SEGMENT AND RELATED INFORMATION
     In accordance with current accounting standards regarding disclosures about segments of an enterprise and related information, the Company has identified the following reportable segments: well site services, offshore products and tubular services. The Company’s reportable segments are strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. The separate business lines within the well site services segment have been disclosed to provide additional detail for that segment. Results of a portion of our Canadian business related to the provision of work force accommodations, catering and logistics services are somewhat seasonal with increased activity occurring in the winter drilling season.

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     Financial information by business segment for each of the three and nine months ended September 30, 2009 and 2008 is summarized in the following table (in thousands):
                                         
    Revenues from     Depreciation                    
    unaffiliated     and     Operating     Capital        
    customers     amortization     income (loss)     expenditures     Total assets  
Three months ended September 30, 2009
                                       
Well Site Services -
                                       
Accommodations
  $ 110,299     $ 9,842     $ 26,575     $ 12,866     $ 553,059  
Rental tools
    51,721       10,526       (4,030 )     7,482       339,200  
Drilling and other
    18,380       6,585       (3,697 )     1,505       119,870  
 
                             
Total Well Site Services
    180,400       26,953       18,848       21,853       1,012,129  
Offshore Products
    131,761       2,734       20,553       3,245       513,452  
Tubular Services
    143,942       344       6,580       118       366,305  
Corporate and Eliminations
          162       (7,441 )     164       14,710  
 
                             
Total
  $ 456,103     $ 30,193     $ 38,540     $ 25,380     $ 1,906,596  
 
                             
                                         
    Revenues from     Depreciation                    
    unaffiliated     and     Operating     Capital        
    customers     amortization     income (loss)     expenditures     Total assets  
Three months ended September 30, 2008
                                       
Well Site Services -
                                       
Accommodations
  $ 105,380     $ 9,686     $ 23,695     $ 29,233     $ 525,780  
Rental tools
    91,699       8,921       21,003       22,931       467,983  
Drilling and other (1)
    52,086       5,272       14,833       14,005       200,161  
 
                             
Total Well Site Services
    249,165       23,879       59,531       66,169       1,193,924  
Offshore Products
    120,008       3,033       20,273       2,749       499,239  
Tubular Services
    445,617       340       68,261       1,022       513,520  
Corporate and Eliminations
          73       (6,555 )     1,085       13,492  
 
                             
Total
  $ 814,790     $ 27,325     $ 141,510     $ 71,025     $ 2,220,175  
 
                             
                                         
    Revenues from     Depreciation                      
    unaffiliated     and     Operating     Capital          
    customers     amortization     income (loss)     expenditures     Total assets  
Nine months ended September 30, 2009
                                       
Well Site Services -
                                       
Accommodations
  $ 340,531     $ 27,332     $ 100,588     $ 34,470     $ 553,059  
Rental tools
    177,075       30,342       (98,997 )     24,252       339,200  
Drilling and other
    46,525       19,501       (13,504 )     8,746       119,870  
 
                             
Total Well Site Services
    564,131       77,175       (11,913 )     67,468       1,012,129  
Offshore Products
    382,271       8,171       59,287       9,143       513,452  
Tubular Services
    633,134       1,097       35,458       314       366,305  
Corporate and Eliminations
          420       (22,630 )     1,239       14,710  
 
                             
Total
  $ 1,579,536     $ 86,863     $ 60,202     $ 78,164     $ 1,906,596  
 
                             
                                         
    Revenues from     Depreciation                    
    unaffiliated     and     Operating     Capital          
    customers     amortization     income (loss)     expenditures     Total assets  
Nine months ended September 30, 2008
                                       
Well Site Services -
                                       
Accommodations
  $ 332,518     $ 26,075     $ 93,761     $ 98,602     $ 525,780  
Rental tools
    258,767       25,793       54,926       57,882       467,983  
Drilling and other (1)
    133,316       14,119       31,679       34,429       200,161  
 
                             
Total Well Site Services
    724,601       65,987       180,366       190,913       1,193,924  
Offshore Products
    386,780       8,545       66,656       12,629       499,239  
Tubular Services
    936,020       1,004       106,533       1,941       513,520  
Corporate and Eliminations
          205       (19,687 )     1,248       13,492  
 
                             
Total
  $ 2,047,401     $ 75,741     $ 333,868     $ 206,731     $ 2,220,175  
 
                             
 
(1)   We have classified our equity interest in Boots & Coots and the notes receivable acquired in the transaction in which we sold our workover services business to Boots & Coots as “Drilling and other.”

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11. ADOPTION OF NEW ACCOUNTING STANDARD ON ACCOUNTING FOR CONVERTIBLE DEBT
     Effective January 1, 2009, we adopted the new accounting standard on accounting for convertible debt instruments that can be settled in cash upon conversion (including partial cash settlement). Under the new rules, for convertible debt instruments that can be settled entirely or partially in cash upon conversion, an entity is required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. This accounting standard requires retrospective restatement of all periods presented back to the date of issuance with the cumulative effect of the change in accounting principle on prior periods being recognized as of the beginning of the first period. The adoption of this new accounting standard affects the accounting, both retrospectively and prospectively, for our 2 3/8% Notes issued in June 2005. Although the accounting standard has no impact on the Company’s actual past or future cash flows, it requires the Company to record a material increase in non-cash interest expense as the debt discount is amortized.
The following tables present the effect of our adoption of this new accounting standard on our condensed consolidated statements of income for the three and nine months ended September 30, 2008 and our condensed consolidated balance sheet as of December 31, 2008, applied retrospectively (in thousands, except per share data):
                                                 
    Three months ended September 30, 2008   Nine months ended September 30, 2008
    Prior to   Effect of   As   Prior to   Effect of   As
    Adoption   adoption   adjusted   adoption   adoption   adjusted
Interest expense
  $ 4,129     $ 1,527     $ 5,656     $ 13,917     $ 4,499     $ 18,416  
 
                                               
Income before income taxes (a)
    141,746       (1,527 )     140,219       331,770       (4,499 )     327,271  
Net income (a)
    89,153       (974 )     88,179       216,012       (2,866 )     213,146  
Net income attributable to Oil States International, Inc. (a)
  $ 89,055     $ (974 )   $ 88,081     $ 215,685     $ (2,866 )   $ 212,819  
 
                                               
Net income per share attributable to Oil States International common stockholders:
                                               
Basic
  $ 1.79     $ (0.02 )   $ 1.77     $ 4.35     $ (0.06 )   $ 4.29  
Diluted
  $ 1.70     $ (0.02 )   $ 1.68     $ 4.15     $ (0.05 )   $ 4.10  
                         
    December 31, 2008
    Prior to   Effect of    
    Adoption   adoption   As adjusted
Other non-current assets
  $ 55,085     $ (729 )   $ 54,356  
Total assets
    2,299,247       (729 )     2,298,518  
 
                       
Long-term debt
  $ 474,948     $ (25,890 )   $ 449,058  
Deferred income taxes
    55,646       9,134       64,780  
Total liabilities
    1,079,733       (16,756 )     1,062,977  
 
                       
Additional paid-in capital
    425,284       28,449       453,733  
Retained earnings
    913,423       (12,422 )     901,001  
Total Oil States International, Inc. stockholders’ equity (a)
    1,218,993       16,027       1,235,020  
Total stockholders’ equity (a)
    1,219,514       16,027       1,235,541  
Total liabilities and stockholders’ equity
  $ 2,299,247     $ (729 )   $ 2,298,518  
 
(a)   As adjusted for current accounting standards regarding noncontrolling interests. See Note 2 to the Unaudited Condensed Consolidated Financial Statements in this quarterly report on Form 10-Q.
     Debt issue costs at December 31, 2008, recorded in other noncurrent assets, decreased $0.7 million as a result of the adoption of this new accounting standard, representing the cumulative adjustment caused by the reclassification of a portion of debt issue costs to additional paid-in capital as required by the accounting standard.
     The cumulative effect of the change on retained earnings as of January 1, 2008, is $8.6 million due to the retrospective increase in interest expense for the years 2005, 2006 and 2007.

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     The following table presents the carrying amount of our 2 3/8% Notes in our condensed consolidated balance sheets (in thousands):
                 
    September 30, 2009     December 31, 2008  
Carrying amount of the equity component in additional paid-in capital
  $ 28,449     $ 28,449  
 
               
Principal amount of the liability component
  $ 175,000     $ 175,000  
Less: Unamortized discount
    (20,874 )     (25,890 )
 
           
Net carrying amount of the liability component
  $ 154,126     $ 149,110  
 
           
     Following our adoption of the new accounting standard, the effective interest rate was 7.17% for our 2 3/8% Notes. Interest expense, excluding amortization of debt issue costs, was as follows (in thousands):
                                 
    Three months ended September 30,   Nine months ended September 30,
    2009   2008   2009   2008
Interest expense
  $ 2,741     $ 2,624     $ 8,133     $ 7,787  
         
    September 30, 2009
Remaining period over which discount will be amortized
  2.8 years  
Conversion price
  $ 31.75  
Number of shares to be delivered upon conversion
    530,303  
Conversion value in excess of principal amount (in thousands)
  $ 18,630  
Derivative transactions entered into in connection with the convertible notes
  None  
12. COMMITMENTS AND CONTINGENCIES
     The Company is a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials as a result of its products or operations. Some of these claims relate to matters occurring prior to its acquisition of businesses, and some relate to businesses it has sold. In certain cases, the Company is entitled to indemnification from the sellers of businesses, and in other cases, it has indemnified the buyers of businesses from it. Although the Company can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on it, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its consolidated financial position, results of operations or liquidity.

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This quarterly report on Form 10-Q contains certain “forward-looking statements” within the meaning of Section 27A of the Securities Exchange Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Some of the information in the quarterly report may contain “forward-looking statements.” The “forward-looking statements” can be identified by the use of forward-looking terminology including “may,” “expect,” “anticipate,” “estimate,” “continue,” “believe,” or other similar words. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to Item “Part I, Item 1.A. Risk Factors” and the financial statement line item discussions set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission on February 20, 2009. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations and are not guarantees of future performance. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in the entirety by the foregoing. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.
In addition, in certain places in this quarterly report, we refer to reports published by third parties that purport to describe trends or developments in the energy industry. The Company does so for the convenience of our stockholders and in an effort to provide information available in the market that will assist the Company’s investors in a better understanding of the market environment in which the Company operates. However, the Company specifically disclaims any responsibility for the accuracy and completeness of such information and undertakes no obligation to update such information.
ITEM 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
     You should read the following discussion and analysis together with our consolidated financial statements and the notes to those statements included elsewhere in this quarterly report on Form 10-Q.
Overview
     We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices except for our accommodations activities supporting oil sands developments which we believe are more tied to the long-term outlook for crude oil prices. Our offshore products segment provides highly engineered and technically designed products for offshore oil and gas development and production systems and facilities. Sales of our offshore products and services depend upon the development of offshore production systems and subsea pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels. In this segment, we are particularly influenced by global deepwater drilling and production activities, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales and gross margins of our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled, and the overall industry level of OCTG inventory and pricing. Historically, tubular services’ gross margin expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. In our well site services business segment, we provide land drilling services, work force accommodations and associated services and rental tools. Demand for our drilling services is driven by land drilling activity in our primary drilling markets in West Texas, Ohio and in the Rocky Mountains area in the U.S. Our rental tools and services depend primarily upon the level of drilling, completion and workover activity in North America. Our accommodations business is conducted principally in Canada and its activity levels are currently being driven primarily by oil sands development activities in northern Alberta.

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     We have a diversified product and service offering which has exposure to activities conducted throughout the oil and gas cycle. Demand for our tubular services, land drilling and rental tool businesses is highly correlated to changes in the drilling rig count in the United States and Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.
                                 
    Average Drilling Rig Count for
    Three Months Ended   Nine Months Ended
    September 30,   September 30,   September 30,   September 30,
    2009   2008   2009   2008
U.S. Land
    940       1,909       1,031       1,806  
U.S. Offshore
    33       69       47       65  
 
                               
Total U.S
    973       1,978       1,078       1,871  
Canada
    187       432       202       369  
 
                               
Total North America
    1,160       2,410       1,280       2,240  
 
                               
     The average North American rig count for the three months ended September 30, 2009 decreased by 1,250 rigs, or 51.9%, compared to the three months ended September 30, 2008. As of October 30, 2009, the North American rig count has increased to 1,318 rigs.
     Beginning in late 2008 and into 2009, we saw unprecedented declines in the global economic outlook that were initially fueled by the housing and credit crises. These market conditions to reduced growth, and in some instances, decreased overall output. We believe there are now some early signs that economic improvement is underway; however, the pace of improvement has been slow and it is yet to be determined if there will be sustained long-term growth. Although energy prices have recently increased compared to the declines witnessed in the first half of 2009, our businesses have been and we expect will continue to be negatively impacted by excess equipment and service capacity given reduced activity levels. Given our customers’ decreased cash flows caused by comparatively lower energy prices as well as shrinking credit availability affecting some of them, funds available for exploration and development have been reduced substantially when compared to 2008. This has led to material declines in the drilling rig count, particularly in North America. Assessing the current situation is challenging given the tenuous state of the global economy and the financial and commodity markets. Although we believe our Company remains financially strong with significant undrawn revolver capacity and cash on hand, certain of our operations have been materially adversely affected by the reduced rig count in the North American energy sector as well as the uncertainty about the level of future oil and natural gas prices. We experienced a significant decline in the utilization of our land drilling rigs beginning in late 2008 and continuing through the first half of 2009, with rig utilization improving somewhat in the third quarter of 2009. In addition, in many instances our customers have delayed or cancelled exploration and development plans and have sought pricing concessions from us.
     An additional important factor in our business, particularly in our land based North American businesses, has been the successful development of several natural gas shale discoveries which we support through our rental tool and OCTG businesses. Much of the continuing exploration and development activity has focused in these shale areas leading us and many of our competitors to relocate equipment to and also concentrate on these areas. This has led to increased competition and lower pricing. Domestic U.S. natural gas prices have decreased from a peak of approximately $13.00 per Mcf in July 2008 to recent levels of approximately $3.90 to $4.80 per Mcf. Many analysts are expecting continued weakness in natural gas prices unless reduced drilling activity and/or forced production shut-ins reverse gas supply excesses or demand for the commodity increases. There is also the risk that, as a result of the success of exploration and development activities in the shale areas coupled with the availability of increasing amounts of LNG, the supply of gas will offset or mitigate the impact of gas shut-ins or demand increases resulting from improved economic conditions. The rig count is not currently expected to recover to levels reached during peak activity levels in 2008.
     During 2009, we markedly reduced our expectations for the level of North American drilling activity, which is the primary driver of our rental tools utilization and pricing. We considered the factors driving these diminished expectations, among others, in assessing goodwill for potential impairment. As a result of our assessment, we wrote off a total of $94.5 million, or $82.7 million after tax, of goodwill in our rental tools reporting unit in the second

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quarter of 2009. See Note 5 to the Consolidated Financial Statements included in this Quarterly Report on Form 10-Q. Should conditions related to our rental tools reporting unit deteriorate further, we could potentially write off all or part of that reporting unit’s remaining goodwill balance of $74.5 million.
     Crude oil prices fell to approximately $30 to $35 per barrel during the quarter ended March 31, 2009; however, oil prices have recovered somewhat since then. As of mid-October 2009, crude oil was trading in a range of $73 to $80 per barrel which, though significantly improved, remains far below its all time high closing price of $147 per barrel reached in July 2008. The current crude oil prices have led to a partial recovery of drilling activity in the oil related rig count in the United States and the sanctioning of some oil sands development projects in Canada. However, it is unknown whether crude oil prices will stabilize at levels that will continue to support significant levels of exploration and production because crude oil market demand fundamentals remain weak and inventories for the resource are oversupplied.
     For the first nine months of 2009, the Canadian dollar was valued at an average exchange rate of U.S. $0.86 compared to U.S. $0.98 for the first nine months of 2008, a decrease of 12%. This weakening of the Canadian dollar had a significant negative impact on the translation of earnings generated from our Canadian subsidiaries.
     The major U.S. steel mills increased OCTG prices during 2008 because of high product demand, overall tight supplies and in response to raw material and other cost increases. However, steel prices on a global basis have declined precipitously during 2009 and industry inventories have increased materially as the rig count has declined. The OCTG Situation Report suggests that industry OCTG inventory levels peaked in the first quarter of 2009 at approximately twenty months’ supply on the ground and have trended down to approximately eleven months’ supply as the U.S. mills have materially reduced output, imports of OCTG have declined and drilling activity has increased. These trends have had a material detrimental impact on OCTG pricing and, accordingly, on our revenues and margins realized during the second and third quarters of 2009 in our tubular services segment. These trends, if continued for an extended period, could also negatively impact the valuation of our OCTG inventory, potentially resulting in lower of cost or market write-downs in the future.
     We continue to monitor the effect of the financial crisis on the global economy, the demand for crude oil and natural gas, and the resulting impact on the capital spending budgets of exploration and production companies in order to estimate the effect on our Company. We have reduced our capital spending significantly in 2009 compared to 2008. We currently expect that 2009 capital expenditures will total approximately $170 million compared to 2008 capital expenditures of $247.4 million. Our 2009 capital expenditures include funding to complete projects in progress at December 31, 2008, including (i) expansion of our Wapasu Creek accommodations facility in the Canadian oil sands, (ii) international expansion at offshore products and (iii) ongoing maintenance capital requirements. In our well site services segment, we continue to monitor industry capacity additions and make future capital expenditure decisions based on a careful evaluation of both the market outlook and industry fundamentals. In our tubular services segment, we remain focused on industry inventory levels, future drilling and completion activity and OCTG prices. In response to industry conditions and our corresponding decreased revenues, we have implemented a variety of cost saving measures throughout our businesses, including headcount reductions and a decrease in overhead costs.
     There are several potential energy policy changes in Washington D.C. that will likely change how energy in the United States is produced and consumed. Some of the major proposed policy changes (which will not likely take effect or have a material impact in the near-term) focus on creating energy standards and efficiencies, provide financing for clean energy generation, and emphasize greater renewable energy usage. Other proposed policy changes focus on eliminating some of the drilling tax incentives available to exploration and production companies, which would likely increase the cost of drilling and, in turn, could negatively affect development plans of exploration and production companies and/or increase the cost of energy to consumers. The company’s management will not be in a position to assess the full impact that the proposed policy changes will have on the energy industry until the policies are adopted.

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Consolidated Results of Operations (in millions)
                                                                 
    THREE MONTHS ENDED     NINE MONTHS ENDED  
    SEPTEMBER 30,     SEPTEMBER 30,  
                    Variance                     Variance  
                    2009 vs. 2008                     2009 vs. 2008  
    2009     2008     $     %     2009     2008     $     %  
Revenues
                                                               
Well Site Services -
                                                               
Accommodations
  $ 110.3     $ 105.4     $ 4.9       5 %   $ 340.5     $ 332.5     $ 8.0       2 %
Rental Tools
    51.7       91.7       (40.0 )     (44 %)     177.1       258.8       (81.7 )     (32 %)
Drilling and Other
    18.4       52.1       (33.7 )     (65 %)     46.5       133.3       (86.8 )     (65 %)
 
                                                   
Total Well Site Services
    180.4       249.2       (68.8 )     (28 %)     564.1       724.6       (160.5 )     (22 %)
Offshore Products
    131.8       120.0       11.8       10 %     382.3       386.8       (4.5 )     (1 %)
Tubular Services
    143.9       445.6       (301.7 )     (68 %)     633.1       936.0       (302.9 )     (32 %)
 
                                                   
Total
  $ 456.1     $ 814.8     $ (358.7 )     (44 %)   $ 1,579.5     $ 2,047.4     $ (467.9 )     (23 %)
 
                                                   
Product costs; Service and other costs (“Cost of sales and service”)
                                                               
Well Site Services -
                                                               
Accommodations
  $ 67.8     $ 65.3     $ 2.5       4 %   $ 196.6     $ 193.4     $ 3.2       2 %
Rental Tools
    38.6       52.8       (14.2 )     (27 %)     128.7       151.2       (22.5 )     (15 %)
Drilling and Other
    14.8       31.2       (16.4 )     (53 %)     38.4       85.2       (46.8 )     (55 %)
 
                                                   
Total Well Site Services
    121.2       149.3       (28.1 )     (19 %)     363.7       429.8       (66.1 )     (15 %)
Offshore Products
    98.7       88.5       10.2       12 %     285.2       286.6       (1.4 )     (0 %)
Tubular Services
    133.9       371.6       (237.7 )     (64 %)     586.8       816.5       (229.7 )     (28 %)
 
                                                   
Total
  $ 353.8     $ 609.4     $ (255.6 )     (42 %)   $ 1,235.7     $ 1,532.9     $ (297.2 )     (19 %)
 
                                                   
 
                                                               
Gross margin
                                                               
 
                                                               
Well Site Services -
                                                               
Accommodations
  $ 42.5     $ 40.1     $ 2.4       6 %   $ 143.9     $ 139.1     $ 4.8       3 %
Rental Tools
    13.1       38.9       (25.8 )     (66 %)     48.4       107.6       (59.2 )     (55 %)
Drilling and Other
    3.6       20.9       (17.3 )     (83 %)     8.1       48.1       (40.0 )     (83 %)
 
                                                   
Total Well Site Services
    59.2       99.9       (40.7 )     (41 %)     200.4       294.8       (94.4 )     (32 %)
Offshore Products
    33.1       31.5       1.6       5 %     97.1       100.2       (3.1 )     (3 %)
Tubular Services
    10.0       74.0       (64.0 )     (86 %)     46.3       119.5       (73.2 )     (61 %)
 
                                                   
Total
  $ 102.3     $ 205.4     $ (103.1 )     (50 %)   $ 343.8     $ 514.5     $ (170.7 )     (33 %)
 
                                                   
Gross margin as a percentage of revenues
                                                               
Well Site Services -
                                                               
Accommodations
    39 %     38 %                     42 %     42 %                
Rental Tools
    25 %     42 %                     27 %     42 %                
Drilling and Other
    20 %     40 %                     17 %     36 %                
Total Well Site Services
    33 %     40 %                     36 %     41 %                
Offshore Products
    25 %     26 %                     25 %     26 %                
Tubular Services
    7 %     17 %                     7 %     13 %                
Total
    22 %     25 %                     22 %     25 %                
THREE MONTHS ENDED SEPTEMBER 30, 2009 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2008
     We reported net income attributable to Oil States International, Inc. for the quarter ended September 30, 2009 of $26.6 million, or $0.53 per diluted share. These results compare to net income of $88.1 million, or $1.68 per diluted share, reported for the quarter ended September 30, 2008. Net income for the third quarter of 2008 included an after tax gain of $2.2 million, or approximately $0.04 per diluted share, on the sale of 5.38 million shares of Boots & Coots International Well Control, Inc. (Boots & Coots) common stock.
     Revenues. Consolidated revenues decreased $358.7 million, or 44%, in the third quarter of 2009 compared to the third quarter of 2008.
     Our well site services revenues decreased $68.8 million, or 28%, in the third quarter of 2009 compared to the third quarter of 2008. This decrease was primarily due to reductions in both activity and pricing from the Company’s North American drilling and rental tool operations as a result of the 52% year-over-year decrease in the North American rig count, partially mitigated by revenue growth in our accommodations business. Our rental tool

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revenues decreased $40.0 million, or 44%, primarily due to lower rental tool utilization and pricing. Our drilling services revenues decreased $33.7 million, or 65%, in the third quarter of 2009 compared to the third quarter of 2008 primarily as a result of reduced utilization in all three of our primary drilling operating regions. Our accommodations business reported revenues in the third quarter of 2009 that were $4.9 million, or 5%, above the third quarter of 2008. The increase in the accommodations revenue resulted from the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada, partially offset by the weakening of the Canadian dollar versus the U.S. dollar and lower accommodations activities in support of conventional oil and gas drilling activity in Canada.
     Our offshore products revenues increased $11.8 million, or 10%, in the third quarter of 2009 compared to the third quarter of 2008. This increase was primarily due to an increase in subsea pipeline and bearings and connector revenues largely driven by international activity.
     Tubular services revenues decreased $301.7 million, or 68%, in the third quarter of 2009 compared to the third quarter of 2008 as a result of a 60% decrease in tons shipped and a 20% decrease in realized revenues per ton shipped in the third quarter of 2009 as a result of fewer wells drilled and completed, coupled with excess industry inventories.
     Cost of Sales and Service. Our consolidated cost of sales decreased $255.6 million, or 42%, in the third quarter of 2009 compared to the third quarter of 2008 primarily as a result of decreased cost of sales at tubular services of $237.7 million, or 64%, due to 60% lower tonnage shipped. Our consolidated gross margin as a percentage of revenues declined from 25% in the third quarter of 2008 to 22% in the third quarter of 2009 primarily due to lower margins realized in our tubular services and well site services segments during 2009.
     Our well site services segment gross margin as a percentage of revenues declined from 40% in the third quarter of 2008 to 33% in the third quarter of 2009 despite modestly improved margins in our accommodations business. Our accommodations gross margin as a percentage of revenues increased from 38% in the third quarter of 2008 to 39% in the third quarter of 2009 primarily as a result of a higher proportion of higher margin revenues from our large accommodation facilities supporting oil sands development activities. Our rental tool gross margin as a percentage of revenues declined from 42% in the third quarter of 2008 to 25% in the third quarter of 2009 primarily due to the significant reduction in drilling and completion activity in both Canada and the U.S., which negatively impacted demand for and pricing of our equipment and services. In addition, a portion of our rental tool costs do not change proportionately with changes in revenue, leading to reduced gross margin percentages. Our drilling services cost of sales decreased $16.4 million, or 53%, in the third quarter of 2009 compared to the third quarter of 2008 as a result of significantly reduced rig utilization in each of our drilling operating areas, which led to significant cost reductions. This decline in drilling activity levels and competitive pricing pressures also resulted in our drilling services gross margin as a percentage of revenues decreasing from 40% in the third quarter of 2008 to 20% in the third quarter of 2009.
     Our offshore products segment gross margin as a percentage of revenues was essentially constant (26% in the third quarter of 2008 compared to 25% in the third quarter of 2009).
     Tubular services segment cost of sales decreased by $237.7 million, or 64%, as a result of lower tonnage shipped. Our tubular services gross margin as a percentage of revenues decreased from 17% in the third quarter of 2008 to 7% in the third quarter of 2009 due to excess industry OCTG inventory levels in 2009 resulting in lower pricing and margins. The third quarter 2009 tubular services gross margin as a percentage of revenues benefited from a $1.0 million margin adjustment primarily related to pipe sales by a third-party affiliate made in prior periods.
     Selling, General and Administrative Expenses. SG&A decreased $3.5 million, or 9%, in the third quarter of 2009 compared to the third quarter of 2008 due primarily to a decrease in accrued incentive bonuses. In addition, our costs have decreased as a result of the implementation of cost saving measures, including headcount reductions and reductions in overhead costs such as travel and entertainment and office expenses, in response to industry conditions.
     Depreciation and Amortization. Depreciation and amortization expense increased $2.9 million, or 10%, in the third quarter of 2009 compared to the same period in 2008 due primarily to capital expenditures made during the previous twelve months largely related to our Canadian accommodations business.

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     Operating Income. Consolidated operating income decreased $103.0 million, or 73%, in the third quarter of 2009 compared to the third quarter of 2008 primarily as a result of a decrease in operating income from our tubular services segment of $61.7 million, or 90%, and a decrease in operating income from our well site services segment of $40.7 million, or 68%.
     Interest Expense and Interest Income. Net interest expense decreased by $1.1 million, or 24%, in the third quarter of 2009 compared to the third quarter of 2008 due to reduced debt levels and lower LIBOR interest rates applicable to borrowings under our revolving credit facility. The weighted average interest rate on the Company’s revolving credit facility was 1.6% in the third quarter of 2009 compared to 3.7% in the third quarter of 2008. Interest income decreased as a result of the repayment in 2009 of a note receivable from Boots & Coots and reduced cash balances in interest bearing accounts.
     Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is $0.2 million, or 42%, lower in the third quarter of 2009 than in the third quarter of 2008 primarily due to the sale, in August of 2008, of our remaining investment in Boots & Coots.
     Income Tax Expense. Our income tax provision for the three months ended September 30, 2009 totaled $8.6 million, or 24.3% of pretax income, compared to income tax expense of $52.0 million, or 37.1% of pretax income, for the three months ended September 30, 2008. The decrease in the effective tax rate from the prior year was largely the result of proportionately higher foreign sourced income in 2009 compared to 2008 which is taxed at lower statutory rates, coupled with domestic benefits derived from estimated tax losses.
NINE MONTHS ENDED SEPTEMBER 30, 2009 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2008
     We reported net income attributable to Oil States International, Inc. for the nine months ended September 30, 2009 of $19.2 million, or $0.39 per diluted share. These results compare to net income of $212.8 million, or $4.10 per diluted share, reported for the nine months ended September 30, 2008. The net income for the first nine months of 2009 included an after tax loss of $82.7 million, or approximately $1.65 per diluted share, on the impairment of goodwill in our rental tools reporting unit. See Note 5 to the Consolidated Financial Statements included in this Quarterly Report on Form 10-Q. Net income for the first nine months of 2008 included an after tax gain of $4.0 million, or approximately $0.08 per diluted share, on the sale of 11.51 million shares of Boots & Coots common stock.
     Revenues. Consolidated revenues decreased $467.9 million, or 23%, in the first nine months of 2009 compared to the first nine months of 2008.
     Our well site services revenues decreased $160.5 million, or 22%, in the first nine months of 2009 compared to the first nine months of 2008. This decrease was primarily due to reductions in both activity and pricing from the Company’s North American drilling and rental tool operations as a result of the 43% year-over-year decrease in the North American rig count, partially mitigated by revenue growth in our accommodations business. Our rental tool revenues decreased $81.7 million, or 32%, primarily due to lower rental tool utilization and pricing. Our drilling services revenues decreased $86.8 million, or 65%, in the first nine months of 2009 compared to the first nine months of 2008 primarily as a result of reduced utilization in all three of our primary drilling operating regions. Our accommodations business reported revenues in the first nine months of 2009 that were $8.0 million, or 2%, above the first nine months of 2008. The increase in the accommodations revenue resulted from the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada and a $40.0 million increase in third-party accommodations manufacturing revenues, partially offset by lower accommodations activities in support of conventional oil and gas drilling activity in Canada and the weakening of the Canadian dollar versus the U.S. dollar.
     Our offshore products revenues decreased $4.5 million, or 1%, in the first nine months of 2009 compared to the first nine months of 2008. This decrease was primarily due to a decrease in bearing and connectors revenue due to deepwater development project award delays.

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     Tubular services revenues decreased $302.9 million, or 32%, in the first nine months of 2009 compared to the first nine months of 2008 as a result of a 45% decrease in tons shipped in the first nine months of 2009, resulting from fewer wells drilled and completed in the period, partially offset by a 23% increase in average selling prices.
     Cost of Sales and Service. Our consolidated cost of sales decreased $297.2 million, or 19%, in the first nine months of 2009 compared to the first nine months of 2008 primarily as a result of decreased cost of sales at tubular services of $229.7 million, or 28%, and decreased cost of sales at well site services of $66.1 million, or 15%. Our overall gross margin as a percentage of revenues declined from 25% in the first nine months of 2008 to 22% in the first nine months of 2009 primarily due to lower margins realized in our tubular services and rental tool operations during 2009.
     Our well site services segment gross margin as a percentage of revenues declined from 41% in the first nine months of 2008 to 36% in the first nine months of 2009 despite flat margins in our accommodations business. Our accommodations cost of sales included a $28.6 million increase in third-party accommodations manufacturing and installation costs, which were only partially offset by a reduction in costs stemming from the implementation of cost saving measures in response to the lower conventional oil and gas drilling activity levels in Canada and the weakening of the Canadian dollar versus the U.S. dollar. Our rental tool gross margin as a percentage of revenues declined from 42% in the first nine months of 2008 to 27% in the first nine months of 2009 primarily due to significant reductions in drilling and completion activity in both Canada and the U.S., which negatively impacted pricing and demand for our equipment and services. In addition, a portion of our rental tool costs do not change proportionately with changes in revenue, leading to reduced gross margin percentages. Our drilling services cost of sales decreased $46.8 million, or 55%, in the first nine months of 2009 compared to the first nine months of 2008 as a result of significantly reduced rig utilization in each of our drilling operating areas, which led to significant cost reductions. This decline in drilling activity levels also resulted in our drilling services gross margin as a percentage of revenues decreasing from 36% in the first nine months of 2008 to 17% in the first nine months of 2009.
     Our offshore products segment gross margin as a percentage of revenues was essentially constant (26% in the first nine months of 2008 compared to 25% in the first nine months of 2009).
     Tubular services segment cost of sales decreased by $229.7 million, or 28%, as a result of lower tonnage shipped partially offset by higher priced OCTG inventory being sold. Our tubular services gross margin as a percentage of revenues decreased from 13% in the first nine months of 2008 to 7% in the first nine months of 2009 due to excess industry-wide OCTG inventory levels in 2009 resulting in lower margins.
     Selling, General and Administrative Expenses. SG&A decreased $3.2 million, or 3%, in the first nine months of 2009 compared to the first nine months of 2008 due primarily to decreases in accrued incentive bonuses. In addition, our costs have decreased as a result of the implementation of cost saving measures, including headcount reductions and reductions in overhead costs such as travel and entertainment and office expenses, in response to industry conditions. Decreases in SG&A in the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 were partially offset by increases in ad valorem taxes and personnel and benefit costs at our offshore products segment.
     Depreciation and Amortization. Depreciation and amortization expense increased $11.1 million, or 15%, in the first nine months of 2009 compared to the same period in 2008 due primarily to capital expenditures made during the previous twelve months.
     Impairment of Goodwill. We recorded a goodwill impairment of $94.5 million, before tax, in the first nine months of 2009. The impairment was the result of our assessment of several factors affecting our rental tools reporting unit. See Note 5 to the Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.
     Operating Income. Consolidated operating income decreased $273.7 million, or 82%, in the first nine months of 2009 compared to the first nine months of 2008 primarily as a result of the $94.5 million pre-tax goodwill impairment charge recorded in the first nine months of 2009 and a decrease in operating income from our tubular and rental tool services operations.

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     Interest Expense and Interest Income. Net interest expense decreased by $4.3 million, or 27%, in the first nine months of 2009 compared to the first nine months of 2008 due to reduced debt levels and lower LIBOR interest rates applicable to borrowings under our revolving credit facility. The weighted average interest rate on the Company’s revolving credit facility was 1.5% in the first nine months of 2009 compared to 4.1% in the first nine months of 2008. Interest income decreased as a result of the repayment in 2009 of a note receivable from Boots & Coots and reduced cash balances in interest bearing accounts.
     Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is $2.0 million, or 63%, lower in the first nine months of 2009 than in the first nine months of 2008 primarily due to the sale, in August of 2008, of our remaining investment in Boots & Coots.
     Income Tax Expense. Our income tax provision for the first nine months of 2009 totaled $30.6 million, or 61.0%, of pretax income compared to $114.1 million, or 34.9%, of pretax income for the nine months ended September 30, 2008. The effective tax rate in the first nine months of 2009 was negatively impacted by a significant amount of the goodwill impairment charges which were non-deductible for tax purposes. Excluding the goodwill impairment, the effective tax rate for the first nine months of 2009 would have approximated 29.3%. The decrease in the effective rate (excluding the goodwill impairment) from the prior year was largely the result of proportionately higher foreign sourced income in 2009 compared to 2008 which is taxed at lower statutory rates, coupled with domestic benefits derived from estimated tax losses.
Liquidity and Capital Resources
     The unprecedented disruption in the credit markets has had a significant adverse impact on a number of financial institutions. To date, the Company’s liquidity has not been materially impacted by the current credit environment. The Company is not currently a party to any interest rate swaps, currency hedges or derivative contracts of any type and has no exposure to commercial paper or auction rate securities markets. Management will continue to closely monitor the Company’s liquidity and the overall health of the credit markets. However, management cannot predict with any certainty the direct impact on the Company of any further or continued disruption in the credit environment, although the Company is seeing the negative impact that such disruptions are currently having on the energy market generally.
     Our primary liquidity needs are to fund capital expenditures, which have included expanding our accommodations facilities, expanding and upgrading our manufacturing facilities and equipment, adding drilling rigs and increasing and replacing rental tool assets, funding new product development and general working capital needs. In addition, capital has been used to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our bank facilities and proceeds from our $175 million convertible note offering in 2005.
     Cash totaling $352.3 million was provided by operations during the first nine months of 2009 compared to cash totaling $306.0 million provided by operations during the first nine months of 2008. During the first nine months of 2009, $149.5 million was provided by working capital, primarily due to lower receivable levels resulting from decreased revenues and lower inventory levels. During the first nine months of 2008, operating cash flow was increased by higher earnings levels.
     Cash was used in investing activities during the nine months ended September 30, 2009 and 2008 in the amount of $58.8 million and $206.1 million, respectively. Capital expenditures totaled $78.2 million and $206.7 million during the nine months ended September 30, 2009 and 2008, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment, and in particular for accommodations investments made in support of Canadian oil sands development. In the nine months ended September 30, 2009, we received $21.2 million from Boots & Coots in full satisfaction of their note receivable.
     In the nine months ended September 30, 2008, we spent cash of $29.8 million to acquire Christina Lake Lodge in Northern Alberta, Canada to expand our oil sands capacity in our well site services segment and to acquire a waterfront facility on the Houston ship channel for use in the offshore products segment. There were no significant acquisitions made by the Company during the nine months ended September 30, 2009.

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     We have significantly reduced our capital spending in the first nine months of 2009 compared to the same period in 2008. We currently expect to spend a total of approximately $170 million for capital expenditures during 2009 to expand our Canadian oil sands related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. This compares to $247 million of capital expenditures made during 2008. We expect to fund these capital expenditures with internally generated funds and borrowings under our revolving credit facility. If there is a significant decrease in demand for our products and services as a result of further declines in the actual and longer term expected price of oil and gas, we may further reduce our capital expenditures and experience reduced requirements for working capital, especially in our tubular services segment, both of which would increase operating cash flow and liquidity. However, such an environment might also increase the availability of attractive acquisitions and if we decided to engage in such a transaction it would draw on such liquidity.
     Net cash of $267.6 million was used in financing activities during the nine months ended September 30, 2009, primarily as a result of debt repayments under our revolving credit facility. A total of $71.2 million was used in financing activities during the nine months ended September 30, 2008, primarily as a result of debt repayments.
     We believe that cash from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the economy, the financial markets and other factors, many of which are beyond our control. In addition, such additional debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to stockholders.
     Stock Repurchase Program. During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50.0 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, an additional $50.0 million was approved and the duration of the program was extended to August 31, 2008. On January 11, 2008, an additional $50.0 million was approved for the repurchase program and the duration of the program was again extended to December 31, 2009. Through September 30, 2009, a total of $90.1 million of our stock (3,162,344 shares), has been repurchased under this program, leaving a total of up to approximately $59.9 million remaining available under the program to make share repurchases. We will continue to evaluate future share repurchases in the context of allocating capital among other corporate opportunities including capital expenditures and acquisitions and in the context of current conditions in the credit and capital markets.
     Credit Facility. On December 13, 2007, we entered into an Incremental Assumption Agreement (Agreement) with the lenders and other parties to our existing credit agreement dated as of October 30, 2003 (Credit Agreement) in order to exercise the accordion feature (Accordion) available under the Credit Agreement and extend the maturity to December 5, 2011. The Accordion increased the total commitments under the Credit Agreement from $400 million to $500 million. In connection with the execution of the Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $300 million to U.S. $325 million, and the total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $100 million to U.S. $175 million. We currently have 11 lenders in our Credit Agreement with commitments ranging from $15 million to $102.5 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, the lack of or delay in funding by a significant member of our banking group could negatively affect our liquidity position.
     As of September 30, 2009, we had $28.0 million outstanding under the Credit Facility and an additional $21.7 million of outstanding letters of credit, leaving $450.3 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. and the U.K. that provide for an aggregate borrowing capacity of $8.2 million. As of September 30, 2009, we had $2.2 million outstanding under these other facilities and an additional $0.8 million of outstanding letters of credit leaving $5.2 million available to be drawn under these

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facilities. Our debt represented 12.7% of our total debt and shareholders’ equity at September 30, 2009 compared to 26.9% at December 31, 2008 and 23.1% at September 30, 2008.
     As of September 30, 2009, we have classified the $175.0 million principal amount of our 2 3/8% Notes as a noncurrent liability because certain contingent conversion thresholds based on the Company’s stock price were not met at that date and, as a result, note holders could not present their notes for conversion during the quarter following the September 30, 2009 measurement date. The future convertibility and resultant balance sheet classification of this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company common stock during the prescribed measurement periods.
     In May 2008, the FASB issued a new accounting standard on the accounting for convertible debt instruments that can be settled in cash upon conversion (including partial cash settlement), which changed the accounting for our 2 3/8% Notes. Under the new rules, for convertible debt instruments that can be settled entirely or partially in cash upon conversion, an entity is required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. This new accounting standard became effective for the Company beginning January 1, 2009 and is applied retrospectively to all periods presented. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this quarterly report on Form 10-Q.
Critical Accounting Policies
     In our selection of critical accounting policies, our objective is to properly reflect our financial position and results of operations in each reporting period in a manner that will be understood by those who utilize our financial statements. Often we must use our judgment about uncertainties.
     There are several critical accounting policies that we have put into practice that have an important effect on our reported financial results.
Accounting for Contingencies
     We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, interest, insurance claims, warranty claims, contract claims and discontinued operations.
Tangible and Intangible Assets, including Goodwill
     Our goodwill totals $217.6 million, or 11.4%, of our total assets, as of September 30, 2009. The assessment of impairment on long-lived assets, intangibles and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. The determination of the amount of impairment would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether a decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
     We review each reporting unit, as defined in current accounting standards regarding goodwill and other intangible assets to assess goodwill for potential impairment. Our reporting units include accommodations, rental tools, drilling, offshore products and tubular services. There is no remaining goodwill in our drilling or tubular services reporting units subsequent to the full write-off of goodwill at those reporting units as of December 31, 2008. As part of the goodwill impairment analysis, we estimate the implied fair value of each reporting unit (IFV)

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and compare the IFV to the carrying value of such unit (the Carrying Value). Because none of our reporting units has a publically quoted market price, we must determine the value that willing buyers and sellers would place on the reporting unit through a routine sale process. In our analysis, we target an IFV that represents the value that would be placed on the reporting unit by market participants, and value the reporting unit based on historical and projected results throughout a cycle, not the value of the reporting unit based on trough or peak earnings. We utilize, depending on circumstances, trading multiples analyses, discounted projected cash flow calculations with estimated terminal values and acquisition comparables to estimate the IFV. The IFV of our reporting units is affected by future oil and gas prices, anticipated spending by our customers, and the cost of capital. If the carrying amount of a reporting unit exceeds its IFV, goodwill is considered to be potentially impaired and additional analysis in accordance with current accounting standards is conducted to determine the amount of impairment, if any.
     As part of our process to assess goodwill for impairment, we also compare the total market capitalization of the Company to the sum of the IFV’s of all of our reporting units to assess the reasonableness of the IFV’s in the aggregate.
Revenue and Cost Recognition
     We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the period in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.
Valuation Allowances
     Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required. We have, in past years, recorded a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized.
Estimation of Useful Lives
     The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.

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Stock Based Compensation
     Since the adoption of the most recent accounting standards regarding share-based payments, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An initial estimate of fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward and consistent vesting terms, option prices and option lives. Utilizing the Black Scholes model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change assumptions for future awards as we consider appropriate.
Income Taxes
     In accounting for income taxes, we are required by the provisions of current accounting standards regarding the accounting for uncertainty in income taxes to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.
ITEM 3.   Quantitative and Qualitative Disclosures about Market Risk
     Interest Rate Risk. We have revolving lines of credit that are subject to the risk of higher interest charges associated with increases in interest rates. As of September 30, 2009, we had floating rate obligations totaling approximately $30.2 million for amounts borrowed under our revolving credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rate were to increase by 1% from September 30, 2009 levels, our consolidated interest expense would increase by a total of approximately $0.3 million annually.
     Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are (i) denominated in currencies other than the U.S. dollar, which is our functional currency or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks, we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the first nine months of 2009, our realized foreign exchange losses were $0.1 million and are included in other operating income in the consolidated statements of income.
ITEM 4.   Controls and Procedures
     Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2009 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act, including this Quarterly Report on Form 10-Q, is recorded, processed, summarized and reported within the time periods specified in the Commission rules and forms.
     Changes in Internal Control over Financial Reporting. During the three months ended September 30, 2009, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

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PART II — OTHER INFORMATION
ITEM 1.   Legal Proceedings
     We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses and, in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
ITEM 1A.   Risk Factors
     Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2008 (the “2008 Form 10-K”) includes a detailed discussion of our risk factors. There have been no significant changes to our risk factors as set forth in our 2008 Form 10-K.
ITEM 2.   Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities
Unregistered Sales of Equity Securities and Use of Proceeds
     None
Purchases of Equity Securities by the Issuer and Affiliated Purchases
                                 
                    Total Number of   Approximate
                    Shares Purchased   Dollar Value of Shares
                    as Part of the Share   Remaining to be Purchased
    Total Number of   Average Price   Repurchase   Under the Share Repurchase
Period   Shares Purchased   Paid per Share   Program   Program
July 1, 2009 – July 31, 2009
                3,162,344     $ 59,923,188  
August 1, 2009 – August 31, 2009
                3,162,344     $ 59,923,188  
September 1, 2009 – September 30, 2009
                3,162,344     $ 59,923,188  (1)
Total
                3,162,344     $ 59,923,188  
 
(1)   On March 2, 2005, we announced a share repurchase program of up to $50,000,000 over a two year period. On August 25, 2006, we announced the authorization of an additional $50,000,000 and the extension of the program to August 31, 2008. On January 11, 2008, an additional $50 million was approved for the repurchase program and the duration of the program was extended to December 31, 2009.
ITEM 3.   Defaults Upon Senior Securities
     None
ITEM 4.   Submission of Matters to a Vote of Security Holders
     None

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ITEM 5.   Other Information
     None
ITEM 6.   Exhibits
(a)   INDEX OF EXHIBITS
         
Exhibit No.       Description
3.1
    Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).
 
       
3.2
    Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on March 13, 2009).
 
       
3.3
    Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).
 
       
4.1
    Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (File No. 333-43400)).
 
       
4.2
    Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).
 
       
4.3
    First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the Commission on March 13, 2003).
 
       
4.4
  —    Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Commission on June 23, 2005).
 
       
4.5
  —    Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Commission on June 23, 2005).
 
       
4.6
  —    Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 hereof) (incorporated by reference to Oil States’ Current Reports on Form 8-K filed with the Commission on June 23, 2005 and July 13, 2005).
 
       
10.11E
  —    Amendment No. 3, dated as of October 1, 2009, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.11E to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 2, 2009).
 
       
31.1*
    Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
 
       
31.2*
    Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
 
       
32.1**
    Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
 
       
32.2**
    Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
 
*   Filed herewith
 
**   Furnished herewith.

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
             
    OIL STATES INTERNATIONAL, INC.    
 
           
Date: November 4, 2009
  By   /s/ BRADLEY J. DODSON
 
Bradley J. Dodson
   
 
      Vice President, Chief Financial Officer and    
 
      Treasurer (Duly Authorized Officer and Principal    
 
      Financial Officer)    
 
           
Date: November 4, 2009
  By   /s/ ROBERT W. HAMPTON
 
Robert W. Hampton
   
 
      Senior Vice President — Accounting and    
 
      Secretary (Duly Authorized Officer and Chief    
 
      Accounting Officer)    

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Exhibit Index
             
Exhibit No.           Description
3.1
        Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).
 
           
3.2
        Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on March 13, 2009).
 
           
3.3
        Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).
 
           
4.1
        Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (File No. 333-43400)).
 
           
4.2
        Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).
 
           
4.3
        First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the Commission on March 13, 2003).
 
           
4.4
        Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Securities and Exchange Commission on June 23, 2005).
 
           
4.5
        Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Securities and Exchange Commission on June 23, 2005).
 
           
4.6
        Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 hereof) (incorporated by reference to Oil States’ Current Reports on Form 8-K filed with the Securities and Exchange Commission on June 23, 2005 and July 13, 2005).
 
           
10.11E
        Amendment No. 3, dated as of October 1, 2009, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.11E to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 2, 2009).
 
           
31.1*
      Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
 
           
31.2*
          Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
 
           
32.1**
        Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
 
           
32.2**
        Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
 
*   Filed herewith
 
**   Furnished herewith.