Oil States International (OIS) 10-Q 2009 Q2 Quarterly report

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 June 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,	77002
Houston, Texas	(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.

YESþ       NOo

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)

YESo       NOo

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 filerþ  Accelerated filero   Non-accelerated filero
(Do not check if a smaller reporting company) Smaller reporting companyo 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YESo       NOþ

The Registrant had 49,651,602 shares of common stock outstanding and 3,232,118 shares of treasury stock as of
July 28, 2009.

OIL STATES INTERNATIONAL, INC.

INDEX

	Page No.
Part I — FINANCIAL INFORMATION
Item 1. Financial Statements:
Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Month Periods Ended June 30, 2009 and 2008		3
Unaudited Consolidated Balance Sheets – June 30, 2009 and December 31, 2008		4
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008		5
Notes to Unaudited Condensed Consolidated Financial Statements		6–15
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16–27
Item 3. Quantitative and Qualitative Disclosures About Market Risk		27
Item 4. Controls and Procedures		27
Part II — OTHER INFORMATION
Item 1. Legal Proceedings		28
Item 1A. Risk Factors		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities		28
Item 3. Defaults Upon Senior Securities		28
Item 4. Submission of Matters to a Vote of Security Holders		28–29
Item 5. Other Information		29
Item 6. Exhibits		29
(a) Index of Exhibits		29–30
Signature Page		31
EX-31.1
EX-31.2
EX-32.1
EX-32.2

2

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

	THREE MONTHS ENDED						SIX MONTHS ENDED
	JUNE 30,						JUNE 30,
	2009			2008			2009			2008
				AS ADJUSTED						AS ADJUSTED
				(NOTE 11)						(NOTE 11)
Revenues	$	456,334		$	631,364		$	1,123,433		$	1,232,611
Costs and expenses:
Cost of sales and services		361,692			478,435			881,902			923,519
Selling, general and administrative expenses		33,768			35,976			68,413			68,083
Depreciation and amortization expense		28,647			25,689			56,670			48,417
Impairment of goodwill		94,528			—			94,528			—
Other operating expense		935			244			258			234
		519,570			540,344			1,101,771			1,040,253
Operating income/(loss)		(63,236	)		91,020			21,662			192,358
Interest expense		(3,856	)		(6,061	)		(8,101	)		(12,760	)
Interest income		4			894			323			1,815
Equity in earnings of unconsolidated affiliates		475			1,242			934			2,737
Gain on sale of investment		—			2,708			—			2,708
Other income/(expense)		(59	)		(168	)		103			194
Income/( loss) before income taxes		(66,672	)		89,635			14,921			187,052
Income tax (expense) benefit		3,303			(30,338	)		(22,044	)		(62,085	)
Net income/(loss)		(63,369	)		59,297			(7,123	)		124,967
Less: Net income attributable to noncontrolling interest		117			89			235			230
Net income/(loss) attributable to Oil States International, Inc.	$	(63,486	)	$	59,208		$	(7,358	)	$	124,737
Net income/(loss) per share attributable to Oil States International, Inc. common stockholders
Basic	$	(1.28	)	$	1.19		$	(0.15	)	$	2.52
Diluted	$	(1.28	)	$	1.13		$	(0.15	)	$	2.41
Weighted average number of common shares outstanding:
Basic		49,581			49,633			49,549			49,527
Diluted		49,581			52,627			49,549			51,763

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

3

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

(In Thousands)

	JUNE 30,			DECEMBER 31,
	2009			2008
				AS ADJUSTED
				(NOTE 11)
ASSETS
Current assets:
Cash and cash equivalents	$	56,099		$	30,199
Accounts receivable, net		319,690			575,982
Inventories, net		502,999			612,488
Prepaid expenses and other current assets		16,741			18,815
Total current assets		895,529			1,237,484
Property, plant, and equipment, net		707,996			695,338
Goodwill, net		214,541			305,441
Investments in unconsolidated affiliates		4,639			5,899
Other non-current assets		35,115			54,356
Total assets	$	1,857,820		$	2,298,518
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	158,858		$	371,789
Income taxes		8,691			52,546
Current portion of long-term debt		4,940			4,943
Deferred revenue		113,457			105,640
Other current liabilities		916			1,587
Total current liabilities		286,862			536,505
Long-term debt		238,881			449,058
Deferred income taxes		54,185			64,780
Other noncurrent liabilities		12,700			12,634
Total liabilities		592,628			1,062,977
Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock		529			526
Additional paid-in capital		459,104			453,733
Retained earnings		893,643			901,001
Accumulated other comprehensive income/(loss)		3,446			(28,409	)
Treasury stock		(92,313	)		(91,831	)
Total Oil States International, Inc. stockholders’ equity		1,264,409			1,235,020
Noncontrolling interest		783			521
Total stockholders’ equity		1,265,192			1,235,541
Total liabilities and stockholders’ equity	$	1,857,820		$	2,298,518

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

4

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	SIX MONTHS
	ENDED JUNE 30,
	2009			2008
				AS ADJUSTED
				(NOTE 11)
Cash flows from operating activities:
Net Income/(loss)	$	(7,123	)	$	124,967
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		56,670			48,417
Deferred income tax provision		(13,285	)		6,372
Excess tax benefits from share-based payment arrangements		—			(3,108	)
Loss on impairment of goodwill		94,528			—
Equity in earnings of unconsolidated subsidiaries, net of dividends		(934	)		(2,484	)
Non-cash compensation charge		5,818			5,124
Accretion of debt discount		3,314			3,086
Gains on sale of investment and disposals of assets		(260	)		(2,788	)
Other, net		1,841			1,091
Changes in working capital		130,627			7,449
Net cash flows provided by operating activities		271,196			188,126
Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		18			(29,816	)
Capital expenditures		(52,784	)		(135,706	)
Proceeds from note receivable		21,166			—
Proceeds from sale of investment		—			11,156
Other, net		(2,043	)		894
Net cash flows used in investing activities		(33,643	)		(153,472	)
Cash flows from financing activities:
Revolving credit repayments		(216,572	)		(28,738	)
Debt repayments		(225	)		(204	)
Issuance of common stock		501			7,607
Purchase of treasury stock		—			(129	)
Excess tax benefits from share-based payment arrangements		—			3,108
Other, net		(482	)		(981	)
Net cash flows provided by (used in) financing activities		(216,778	)		(19,337	)
Effect of exchange rate changes on cash		5,241			121
Net increase in cash and cash equivalents from continuing operations		26,016			15,438
Net cash used in discontinued operations – operating activities		(116	)		(31	)
Cash and cash equivalents, beginning of period		30,199			30,592
Cash and cash equivalents, end of period	$	56,099		$	45,999
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		—			145,913

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

5

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 the recently issued Statement of Financial Accounting Standards No. 165 (SFAS 165), “Subsequent Events,” the Company evaluated subsequent events after the balance sheet date of June 30, 2009 through the time of filing on July 30, 2009. There were no material subsequent events requiring additional disclosure in or amendment to the quarterly financial statements as of July 30, 2009.

2. RECENT ACCOUNTING PRONOUNCEMENTS

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (SFAS 157), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which deferred the effective date of Statement 157 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 SFAS 157 that were unaffected by the delay in the first quarter of 2008. Such adoption did not have a material effect on our consolidated statements of financial position, results of operations or cash flows. In the first quarter of 2009, we adopted the remaining provisions of SFAS 157. 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).

     In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) (SFAS 141R), “Business Combinations,” which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired,

6

the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and interim periods within those fiscal years. SFAS 141R 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 statement. No business combination transactions occurred during the six months ended June 30, 2009.

     In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160 (SFAS 160), “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 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. SFAS 160 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. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. SFAS 160 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 FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May 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 may 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 the FSP 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 FSP 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 Statement of Financial Accounting Standards No. 165 (SFAS 165), “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 SFAS 165, 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 statement is effective for fiscal years, and interim periods within those fiscal years, ending after June 15, 2009. The adoption of SFAS 165 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.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

     Additional information regarding selected balance sheet accounts is presented below (in thousands):

	JUNE 30,			DECEMBER 31,
	2009			2008
Accounts receivable, net:
Trade	$	238,151		$	456,975
Unbilled revenue		85,350			119,907
Other		1,372			3,268
Total accounts receivable		324,873			580,150
Allowance for doubtful accounts		(5,183	)		(4,168	)
	$	319,690		$	575,982

7

	JUNE 30,			DECEMBER 31,
	2009			2008
Inventories, net:
Tubular goods	$	296,222		$	396,462
Other finished goods and purchased products		81,368			88,848
Work in process		60,329			65,009
Raw materials		72,728			68,881
Total inventories		510,647			619,200
Inventory reserves		(7,648	)		(6,712	)
	$	502,999		$	612,488

	ESTIMATED	JUNE 30,			DECEMBER 31,
	USEFUL LIFE	2009			2008
Property, plant and equipment, net:
Land		$	18,750		$	18,298
Buildings and leasehold improvements	3-50 years		144,418			135,080
Machinery and equipment	2-29 years		282,949			270,434
Accommodations assets	10-15 years		331,265			300,765
Rental tools	4-10 years		149,702			141,644
Office furniture and equipment	1-10 years		27,990			26,506
Vehicles	2-10 years		70,759			68,645
Construction in progress			57,750			49,915
Total property, plant and equipment			1,083,583			1,011,287
Less: Accumulated depreciation			(375,587	)		(315,949	)
		$	707,996		$	695,338

	JUNE 30,		DECEMBER 31,
	2009		2008
Accounts payable and accrued liabilities:
Trade accounts payable	$	104,510	$	307,132
Accrued compensation		22,950		35,864
Accrued insurance		9,239		7,551
Accrued taxes, other than income taxes		6,874		7,257
Reserves related to discontinued operations		2,429		2,544
Other		12,856		11,441
	$	158,858	$	371,789

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					SIX MONTHS ENDED
	JUNE 30					JUNE 30,
	2009			2008		2009			2008
				AS ADJUSTED					AS ADJUSTED
				(NOTE 11)					(NOTE 11)
Basic earnings (loss) per share:
Net income/(loss) attributable to Oil States International, Inc.	$	(63,486	)	$	59,208	$	(7,358	)	$	124,737
Weighted average number of shares outstanding		49,581			49,633		49,549			49,527
Basic earnings (loss) per share	$	(1.28	)	$	1.19	$	(0.15	)	$	2.52
Diluted earnings (loss) per share:
Net income/(loss) attributable to Oil States International, Inc.	$	(63,486	)	$	59,208	$	(7,358	)	$	124,737
Weighted average number of shares outstanding		49,581			49,633		49,549			49,527
Effect of dilutive securities:
Options on common stock		—			614		—			519
2 3/8% Convertible Senior Subordinated Notes		—			2,238		—			1,591
Restricted stock awards and other		—			142		—			126
Total shares and dilutive securities		49,581			52,627		49,549			51,763
Diluted earnings (loss) per share	$	(1.28	)	$	1.13	$	(0.15	)	$	2.41

8

     Our calculation of diluted earnings per share for the three and six months ended June 30, 2009 excludes 2,063,763 shares and 2,144,140 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 six months ended June 30, 2008 excludes anti-dilutive shares of 196,793 and 434,877, 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 and is subject to post-closing working capital adjustments. 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.

     Changes in the carrying amount of goodwill for the six month period ended June 30, 2009 are as follows (in thousands):

	Balance as of		Acquisitions		Foreign currency					Balance as of
	January 1,		and		translation and		Goodwill			June 30,
	2009		adjustments		other changes		impairment			2009
Offshore Products	$	85,074	$	—	$	623	$	—		$	85,697
Well Site Services		220,367		337		2,668		(94,528	)		128,844
Total	$	305,441	$	337	$	3,291	$	(94,528	)	$	214,541

     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 in the second quarter of 2009 was $94.5 million before taxes and $84.5 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.

9

6. DEBT

     As of June 30, 2009 and December 31, 2008, long-term debt consisted of the following (in thousands):

	June 30,			December 31,
	2009			2008
				As Adjusted
	(Unaudited)			(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 1.3% for the six month period ended June 30, 2009	$	77,200		$	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 six month period ended June 30, 2009		—			61,244
2 3/8% contingent convertible senior subordinated notes, net — due 2025		152,425			149,110
Subordinated unsecured notes payable to sellers of businesses, interest rate of 6%, maturing in 2009		4,500			4,500
Capital lease obligations and other debt		9,696			13,147
Total debt		243,821			454,001
Less: current maturities		(4,940	)		(4,943	)
Total long-term debt	$	238,881		$	449,058

     As of June 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 June 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 FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May 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 may 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 FSP is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this quarterly report on Form 10-Q.

     At June 30, 2009, the Company had approximately $56.1 million of cash and cash equivalents. In addition, at June 30, 2009, $403.3 million of the Company’s $500 million U.S. and Canadian revolving credit facility was available for future financing needs.

     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):

				June 30, 2009					December 31, 2008
	Interest			Carrying			Fair		Carrying			Fair
	Rate			Value			Value		Value			Value
Principal amount due 2025		2 3/8	%	$	175,000		$	176,792	$	175,000		$	133,613
Less: Unamortized discount					(22,575	)		—		(25,890	)		—
Net value				$	152,425		$	176,792	$	149,110		$	133,613

     As of June 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.

10

7. COMPREHENSIVE INCOME (LOSS) AND CHANGES IN COMMON STOCK OUTSTANDING:

     Comprehensive income (loss) for the three and six months ended June 30, 2009 and 2008 was as follows (dollars in thousands):

	THREE MONTHS						SIX MONTHS
	ENDED JUNE 30,						ENDED JUNE 30,
	2009			2008			2009			2008
				As Adjusted						As Adjusted
				(Note 11)						(Note 11)
Net income/(loss)	$	(63,369	)	$	59,297		$	(7,123	)	$	124,967
Other comprehensive income/(loss):
Cumulative translation adjustment		43,676			4,037			31,855			(8,459	)
Unrealized gain on marketable securities		—			1,804			—			1,804
Total other comprehensive income/(loss)		43,676			5,841			31,855			(6,655	)
Comprehensive income/(loss)		(19,693	)		65,138			24,732			118,312
Comprehensive income attributable to noncontrolling interest	(117)				(89	)		(235	)		(230	)
Comprehensive income/(loss) attributable to Oil States International, Inc.	$	(19,810	)	$	65,049		$	24,497		$	118,082

Shares of common stock outstanding – January 1, 2009	49,500,708
Shares issued upon exercise of stock options and vesting of stock awards	166,967
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury	(24,329	)
Shares of common stock outstanding – June 30, 2009	49,643,346

8. STOCK BASED COMPENSATION

     During the first six months of 2009, we granted restricted stock awards totaling 191,487 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 1,159 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 six months ended June 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 six month period ended June 30, 2009 totaled $5.8 million, or $0.08 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 the six month period ended June 30, 2008 totaled $5.1 million, or $0.07 per diluted share after tax. Stock based compensation pre-tax expense recognized in the three month period ended June 30, 2009 totaled $2.9 million, or $0.04 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 the three month period ended June 30, 2008 totaled $2.6 million, or $0.03 per diluted share after tax. The total fair value of restricted stock awards that vested during the six months ended June 30, 2009 was $2.5 million. At June 30, 2009, $21.5 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

     The Company’s income tax benefit for the three months ended June 30, 2009 totaled $3.3 million, or 5.0% of pretax losses, compared to income tax expense of $30.3 million, or 33.8% of pretax income, for the three months ended June 30, 2008. The Company’s income tax provision for the six months ended June 30, 2009 totaled $22.0 million, or 147.7% of pretax income, compared to $62.1 million, or 33.2% of pretax income, for the six months ended June 30, 2008. The effective tax rates in the three and six months ended June 30, 2009 were 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 rates for the three and six months ended June 30, 2009 would have approximated 24.0% and 29.3%, respectively. The decrease in effective tax rates (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.

11

10. SEGMENT AND RELATED INFORMATION

     In accordance with SFAS No. 131, “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 seasonal with a major part of expected activity occurring in the winter drilling season.

12

     Financial information by business segment for each of the three and six months ended June 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 June 30, 2009
Well Site Services —
Accommodations	$	88,400	$	9,050	$	25,770		$	9,370	$	496,513
Rental tools		53,629		9,859		(98,612	)		4,975		342,699
Drilling and other		10,861		6,483		(6,313	)		2,028		120,091
Total Well Site Services		152,890		25,392		(79,155	)		16,373		959,303
Offshore Products		122,511		2,742		17,548			2,830		504,698
Tubular Services		180,933		377		5,967			101		378,664
Corporate and Eliminations		—		136		(7,596	)		810		15,155
Total	$	456,334	$	28,647	$	(63,236	)	$	20,114	$	1,857,820

	Revenues from		Depreciation
	unaffiliated		and		Operating			Capital
	customers		amortization		income (loss)			expenditures		Total assets
Three months ended June 30, 2008
Well Site Services —
Accommodations	$	80,880	$	8,581	$	17,257		$	41,075	$	515,164
Rental tools		84,576		9,036		16,293			17,443		447,491
Drilling and other (1)		44,426		4,810		10,794			10,667		194,798
Total Well Site Services		209,882		22,427		44,344			69,185		1,157,453
Offshore Products		139,850		2,859		24,936			5,057		500,147
Tubular Services		281,632		336		28,751			471		416,607
Corporate and Eliminations		—		67		(7,011	)		148		22,334
Total	$	631,364	$	25,689	$	91,020		$	74,861	$	2,096,541

	Revenues from		Depreciation
	unaffiliated		and		Operating			Capital
	customers		amortization		income (loss)			expenditures		Total assets
Six months ended June 30, 2009
Well Site Services —
Accommodations	$	230,232	$	17,491	$	74,014		$	21,604	$	496,513
Rental tools		125,354		19,816		(94,967	)		16,770		342,699
Drilling and other		28,145		12,916		(9,808	)		7,240		120,091
Total Well Site Services		383,731		50,223		(30,761	)		45,614		959,303
Offshore Products		250,510		5,436		38,734			5,898		504,698
Tubular Services		489,192		753		28,878			196		378,664
Corporate and Eliminations		—		258		(15,189	)		1,076		15,155
Total	$	1,123,433	$	56,670	$	21,662		$	52,784	$	1,857,820

	Revenues from		Depreciation
	unaffiliated		and		Operating			Capital
	customers		amortization		income (loss)			expenditures		Total assets
Six months ended June 30, 2008
Well Site Services —
Accommodations	$	227,137	$	16,389	$	70,065		$	69,368	$	515,164
Rental tools		167,069		16,872		33,924			34,952		447,491
Drilling and other (1)		81,230		8,847		16,846			20,424		194,798
Total Well Site Services		475,436		42,108		120,835			124,744		1,157,453
Offshore Products		266,772		5,512		46,383			9,880		500,147
Tubular Services		490,403		664		38,272			919		416,607
Corporate and Eliminations		—		133		(13,132	)		163		22,334
Total	$	1,232,611	$	48,417	$	192,358		$	135,706	$	2,096,541

(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.”

13

11. ADOPTION OF FSP APB 14-1

     Effective January 1, 2009, we adopted FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement.)” Under the new rules, for convertible debt instruments that may 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. FSP APB 14-1 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 FSP APB 14-1 affects the accounting, both retrospectively and prospectively, for our 2 3/8% Notes issued in June 2005. Although the FSP 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 FSP APB 14-1 on our condensed consolidated statements of operations for the three and six months ended June 30, 2008 and our condensed consolidated balance sheet as of December 31, 2008, applied retrospectively (in thousands, except per share data):

	Three months ended June 30, 2008							Six months ended June 30, 2008
	Prior to		Effect of			As		Prior to		Effect of			As
	adoption		adoption			adjusted		adoption		adoption			adjusted
Interest expense	$	4,561	$	1,500		$	6,061	$	9,788	$	2,972		$	12,760
Income before income taxes		91,135		(1,500	)		89,635		190,024		(2,972	)		187,052
Net income (a)		60,252		(955	)		59,297		126,860		(1,893	)		124,967
Net income attributable to Oil States International, Inc. (a)	$	60,163	$	(955	)	$	59,208	$	126,630	$	(1,893	)	$	124,737
Net income per share attributable to Oil States International common stockholders:
Basic	$	1.21	$	(0.02	)	$	1.19	$	2.56	$	(0.04	)	$	2.52
Diluted	$	1.14	$	(0.01	)	$	1.13	$	2.45	$	(0.04	)	$	2.41

	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 SFAS 160. 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 FSP APB 14-1, representing the cumulative adjustment caused by the reclassification of a portion of debt issue costs to additional paid-in capital as required by FSP APB 14-1.

     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.

14

     The following table presents the carrying amount of our 2 3/8% Notes in our condensed consolidated balance sheets (in thousands):

	June 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		(22,575	)		(25,890	)
Net carrying amount of the liability component	$	152,425		$	149,110

     Following our adoption of FSP APB 14-1, 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 June 30,				Six months ended June 30,
	2009		2008		2009		2008
Interest expense	$	2,711	$	2,596	$	5,392	$	5,162

	June 30, 2009
Remaining period over which discount will be amortized	3.0 years
Conversion price	$	31.75
Number of shares to be delivered upon conversion (1)		n/a
Conversion value in excess of principal amount (1)		n/a
Derivative transactions entered into in connection with the convertible notes	None

(1) As of June 30, 2009, no shares would be issuable since the closing stock price of $24.21 is less than the conversion price.

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.

15

     This quarterly report onForm 10-Q contains 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. 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. 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.

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 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 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.

     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.

16

	Average Drilling Rig Count for
	Three Months Ended				Six Months Ended
	June 30,		June 30,		June 30,		June 30,
	2009		2008		2009		2008
U.S. Land		887		1,797		1,078		1,755
U.S. Offshore		49		67		53		62
Total U.S.		936		1,864		1,131		1,817
Canada		90		169		210		338
Total North America		1,026		2,033		1,341		2,155

     The average North American rig count for the three months ended June 30, 2009 decreased by 1,007 rigs, or 49.5%, compared to the three months ended June 30, 2008. As of July 24, 2009, the North American rig count has increased to 1,123 rigs.

     Since late 2008 and throughout 2009 to date, we have seen unprecedented declines in the global economic outlook that were initially fueled by the housing and credit crises which have led to reduced growth, and in some instances, decreased overall output. Energy prices have declined precipitously from prior record levels attained in 2008. Given our customers’ decreased cash flows caused by lower energy prices as well as shrinking credit availability affecting some of them, funds available for exploration and development have been reduced. This has led to material declines in the drilling rig count, particularly in North America. Although our Company remains financially strong with significant undrawn revolver capacity and cash on our balance sheet, 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 have experienced a significant decline in the utilization of our land drilling rigs beginning in late 2008 and continuing in the first half of 2009. 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 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 leading 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 $3.00 to $3.75 per Mcf. Analysts are expecting continued weakness in natural gas prices until reduced drilling activity and forced production shut-ins reverse gas supply excesses or demand for the commodity increases. The rig count is not currently expected to recover to levels reached during peak activity levels in 2008.

     Since our evaluation of market conditions at year-end, we have 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 $84.5 million after tax, of goodwill in our rental tools reporting unit in the second 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 $73.6 million.

     Crude oil prices fell to approximately $30 to $35 per barrel during the quarter ended March 31, 2009. We have seen oil prices recover from recent lows experienced in the first quarter of 2009. As of mid-July 2009, crude oil was trading in a range of $59 to $65 per barrel, which though improved, is far below its all time high closing price of $147 per barrel. 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.

     For the first six months of 2009, the Canadian dollar was valued at an average exchange rate of U.S. $0.83 compared to U.S. $0.99 for the first six months of 2008, a decrease of 16%. This weakening of the Canadian dollar had a significant negative impact on the translation of earnings generated from our Canadian subsidiaries.

17

     The major U.S. steel mills increased OCTG prices during 2008 because of high product demand, overall tight supplies and also in response to raw material and other cost increases. However, steel prices have declined precipitously during 2009 on a global basis and industry inventories have increased materially as the rig count has declined. These trends have had a material detrimental impact on OCTG pricing and, accordingly, on our revenues and margins realized during the second quarter 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 $140 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 expansion of our Wapasu Creek facility, for international expansion at offshore products and for 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. Throughout our businesses, we have implemented a variety of cost saving measures, including headcount reductions and reductions in overhead costs, in response to industry conditions to reduce expense levels in line with decreased revenues.

18

Consolidated Results of Operations (in millions)

	THREE MONTHS ENDED												SIX MONTHS ENDED
	JUNE 30,												JUNE 30,
							Variance												Variance
							2009 vs. 2008												2009 vs. 2008
	2009			2008			$			%			2009			2008			$			%
Revenues
Well Site Services —
Accommodations	$	88.4		$	80.9		$	7.5			9	%	$	230.2		$	227.1		$	3.1			1	%
Rental Tools		53.6			84.6			(31.0	)		(37	%)		125.4			167.1			(41.7	)		(25	%)
Drilling and Other		10.9			44.4			(33.5	)		(75	%)		28.1			81.2			(53.1	)		(65	%)
Total Well Site Services		152.9			209.9			(57.0	)		(27	%)		383.7			475.4			(91.7	)		(19	%)
Offshore Products		122.5			139.9			(17.4	)		(12	%)		250.5			266.8			(16.3	)		(6	%)
Tubular Services		180.9			281.6			(100.7	)		(36	%)		489.2			490.4			(1.2	)		0	%
Total	$	456.3		$	631.4		$	(175.1	)		(28	%)	$	1,123.4		$	1,232.6		$	(109.2	)		(9	%)
Product costs; Service and other costs (“Cost of sales and service”)
Well Site Services —
Accommodations	$	48.8		$	48.6		$	0.2			0	%	$	128.7		$	128.2		$	0.5			0	%
Rental Tools		40.3			50.3			(10.0	)		(20	%)		90.1			98.4			(8.3	)		(8	%)
Drilling and Other		10.0			27.9			(17.9	)		(64	%)		23.6			53.9			(30.3	)		(56	%)
Total Well Site Services		99.1			126.8			(27.7	)		(22	%)		242.4			280.5			(38.1	)		(14	%)
Offshore Products		91.2			102.7			(11.5	)		(11	%)		186.6			198.1			(11.5	)		(6	%)
Tubular Services		171.4			248.9			(77.5	)		(31	%)		452.9			444.9			8.0			2	%
Total	$	361.7		$	478.4		$	(116.7	)		(24	%)	$	881.9		$	923.5		$	(41.6	)		(5	%)
Gross margin
Well Site Services —
Accommodations	$	39.6		$	32.3		$	7.3			23	%	$	101.5		$	98.9		$	2.6			3	%
Rental Tools		13.3			34.3			(21.0	)		(61	%)		35.3			68.7			(33.4	)		(49	%)
Drilling and Other		0.9			16.5			(15.6	)		(95	%)		4.5			27.3			(22.8	)		(84	%)
Total Well Site Services		53.8			83.1			(29.3	)		(35	%)		141.3			194.9			(53.6	)		(28	%)
Offshore Products		31.3			37.2			(5.9	)		(16	%)		63.9			68.7			(4.8	)		(7	%)
Tubular Services		9.5			32.7			(23.2	)		(71	%)		36.3			45.5			(9.2	)		(20	%)
Total	$	94.6		$	153.0		$	(58.4	)		(38	%)	$	241.5		$	309.1		$	(67.6	)		(22	%)
Gross margin as a percentage of revenues
Well Site Services —
Accommodations		45	%		40	%								44	%		44	%
Rental Tools		25	%		41	%								28	%		41	%
Drilling and Other		8	%		37	%								16	%		34	%
Total Well Site Services		35	%		40	%								37	%		41	%
Offshore Products		26	%		27	%								26	%		26	%
Tubular Services		5	%		12	%								7	%		9	%
Total		21	%		24	%								22	%		25	%

THREE MONTHS ENDED JUNE 30, 2009 COMPARED TO THREE MONTHS ENDED JUNE 30, 2008

     We reported a net loss attributable to Oil States International, Inc. for the quarter ended June 30, 2009 of $63.5 million, or $1.28 per diluted share. These results compare to net income of $59.2 million, or $1.13 per diluted share, reported for the quarter ended June 30, 2008. The net loss for the second quarter of 2009 included an after tax loss of $84.5 million, or approximately $1.70 per diluted share, on the impairment of a portion of the 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 second quarter of 2008 included an after tax gain of $1.8 million, or approximately $0.03 per diluted share, on the sale of 6.13 million shares of Boots & Coots International Well Control, Inc. (Boots & Coots) common stock.

     Revenues.Consolidated revenues decreased $175.1 million, or 28%, in the second quarter of 2009 compared to the second quarter of 2008.

     Our well site services revenues decreased $57.0 million, or 27%, in the second quarter of 2009 compared to the second quarter of 2008. This decrease was primarily due to reductions in both activity and pricing from the

19

Company’s North American drilling and rental tool operations as a result of the 50% year-over-year decrease in the North American rig count, partially mitigated by revenue growth in our accommodations business. Our rental tool revenues decreased $31.0 million, or 37%, primarily due to lower rental tool utilization and pricing. Our drilling services revenues decreased $33.5 million, or 75%, in the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of reduced utilization in all three of our primary drilling operating regions with a more pronounced decline in West Texas. Our accommodations business reported revenues in the second quarter of 2009 that were $7.5 million, or 9%, above the second 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 decreased $17.4 million, or 12%, in the second quarter of 2009 compared to the second quarter of 2008. This decrease was primarily due to a decrease in bearings and connector revenues due to project delays in deepwater development awards and a decrease in elastomer revenues as a result of reduced drilling and completion activity in North America.

     Tubular services revenues decreased $100.7 million, or 36%, in the second quarter of 2009 compared to the second quarter of 2008 as a result of a 52% decrease in tons shipped in the second quarter of 2009 as a result of fewer wells drilled and completed, partially offset by a 34% increase in average selling prices.

     Cost of Sales and Service.Our consolidated cost of sales decreased $116.7 million, or 24%, in the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of decreased cost of sales at tubular services of $77.5 million, or 31%. Cost of sales decreased due to 52% lower tonnage shipped partially offset by higher OCTG prices charged by our suppliers. Our consolidated gross margin as a percentage of revenues declined from 24% in the second quarter of 2008 to 21% in the second 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 second quarter of 2008 to 35% in the second quarter of 2009 despite improved margins in our accommodations business. Our accommodations gross margin as a percentage of revenues increased from 40% in the second quarter of 2008 to 45% in the second 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 41% in the second quarter of 2008 to 25% in the second 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 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 $17.9 million, or 64%, in the second quarter of 2009 compared to the second 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 37% in the second quarter of 2008 to 8% in the second quarter of 2009.

     Our offshore products segment gross margin as a percentage of revenues was essentially constant (27% in the second quarter of 2008 compared to 26% in the second quarter of 2009).

     Tubular services segment cost of sales decreased by $77.5 million, or 31%, 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 12% in the second quarter of 2008 to 5% in the second quarter of 2009 due to excess industry OCTG inventory levels in 2009 resulting in lower margins.

     Selling, General and Administrative Expenses.SG&A decreased $2.2 million, or 6%, in the second quarter of 2009 compared to the second 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, which have been partially offset by increased bad debt expense.

20

     Depreciation and Amortization.Depreciation and amortization expense increased $3.0 million, or 12%, in the second quarter 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 second quarter 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 $154.3 million, or 169%, in the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of the $94.5 million pre-tax goodwill impairment charge recognized in the second quarter of 2009, a decrease in operating income from our well site services segment of $29.0 million, or 65.3%, prior to consideration of the impact of the goodwill impairment of $94.5 million, and a decrease in operating income from our tubular services segment of $22.8 million, or 79%.

     Interest Expense and Interest Income.Net interest expense decreased by $1.3 million, or 25%, in the second quarter of 2009 compared to the second quarter of 2008 due to lower LIBOR interest rates applicable to borrowings under our revolving credit facility and reduced debt levels. The weighted average interest rate on the Company’s revolving credit facility was 1.4% in the second quarter of 2009 compared to 3.8% in the second 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 $0.8 million, or 62%, lower in the second quarter of 2009 than in the second 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 benefit for the three months ended June 30, 2009 totaled $3.3 million, or 5.0% of pretax losses, compared to income tax expense of $30.3 million, or 33.8% of pretax income, for the three months ended June 30, 2008. The effective tax rate in the second quarter 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 second quarter of 2009 would have approximated 24.0% . The decrease in the effective tax 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.

SIX MONTHS ENDED JUNE 30, 2009 COMPARED TO SIX MONTHS ENDED JUNE 30, 2008

     We reported a net loss attributable to Oil States International, Inc. for the six months ended June 30, 2009 of $7.4 million, or $0.15 per diluted share. These results compare to net income of $124.7 million, or $2.41 per diluted share, reported for the six months ended June 30, 2008. The net loss for the first half of 2009 included an after tax loss of $84.5 million, or approximately $1.70 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 half of 2008 included an after tax gain of $1.8 million, or approximately $0.03 per diluted share, on the sale of 6.13 million shares of Boots & Coots common stock.

     Revenues.Consolidated revenues decreased $109.2 million, or 9%, in the first half of 2009 compared to the first half of 2008.

     Our well site services revenues decreased $91.7 million, or 19%, in the first half of 2009 compared to the first half 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 38% year-over-year decrease in the North American rig count, partially mitigated by revenue growth in our accommodations business. Our rental tool revenues decreased $41.7 million, or 25%, primarily due to lower rental tool utilization and pricing. Our drilling services revenues decreased $53.1 million, or 65%, in the first half of 2009 compared to the first half of 2008 primarily as a result of reduced utilization in all three of our primary drilling operating regions with a more pronounced decline in West Texas. Our accommodations business reported revenues in the first half of 2009 that were $3.1 million, or 1%, above the first half of 2008. The increase in the accommodations revenue resulted from a $40.8 million increase in

21

third-party accommodations manufacturing revenues and the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada, 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 $16.3 million, or 6%, in the first half of 2009 compared to the first half of 2008. This decrease was primarily due to a decrease in bearing and connectors revenue due to deepwater development project award delays.

     Tubular services revenues decreased $1.2 million, or less than 1%, in the first half of 2009 compared to the first half of 2008 as a result of a 36% decrease in tons shipped in the first half of 2009, resulting from fewer wells drilled and completed in the period, substantially offset by a 56% increase in average selling prices.

     Cost of Sales and Service.Our consolidated cost of sales decreased $41.6 million, or 5%, in the first half of 2009 compared to the first half of 2008 primarily as a result of decreased cost of sales at well site services of $38.1 million, or 14%. Our overall gross margin as a percentage of revenues declined from 25% in the first half of 2008 to 22% in the first half of 2009 primarily due to lower margins realized in our rental tool and drilling operations during 2009.

     Our well site services segment gross margin as a percentage of revenues declined from 41% in the first half of 2008 to 37% in the first half of 2009 despite flat margins in our accommodations business. Our accommodations cost of sales included a $29.0 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 41% in the first half of 2008 to 28% in the first half of 2009 primarily due to significant reductions in drilling and completion activity in both Canada and the U.S., which negatively impacted 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 $30.3 million, or 56%, in the first half of 2009 compared to the first half 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 34% in the first half of 2008 to 16% in the first half of 2009.

     Our offshore products segment gross margin as a percentage of revenues was 26% in both the first half of 2008 and 2009.

     Tubular services segment cost of sales increased by $8.0 million, or 2%, as a result of higher priced OCTG inventory being sold partially offset by lower tonnage shipped. Our tubular services gross margin as a percentage of revenues decreased from 9% in the first half of 2008 to 7% in the first half of 2009 due to excess OCTG inventory levels in 2009 resulting in lower margins.

     Selling, General and Administrative Expenses.SG&A increased $0.3 million, or less than 1%, in the first half of 2009 compared to the first half of 2008 due primarily to increases in bad debt expenses, equity compensation expense, ad valorem taxes and personnel costs and benefits at our offshore products segment which was partially driven by a reclassification of costs formerly classified as operating expenses. Increases in SG&A in the six months ended June 30, 2009 compared to the six months ended June 30, 2008 were partially offset by 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.

     Depreciation and Amortization.Depreciation and amortization expense increased $8.3 million, or 17%, in the first half of 2009 compared to the same period in 2008 due primarily to capital expenditures made during the previous twelve months.

22

     Impairment of Goodwill.We recorded a goodwill impairment of $94.5 million, before tax, in the first half 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 $170.7 million, or 89%, in the first half of 2009 compared to the first half of 2008 primarily as a result of the $94.5 million pre-tax goodwill impairment charge recorded in the first half of 2009 and a decrease in operating income from our drilling, rental tool and tubular services operations.

     Interest Expense and Interest Income.Net interest expense decreased by $3.2 million, or 29%, in the first half of 2009 compared to the first half of 2008 due to lower LIBOR interest rates applicable to borrowings under our revolving credit facility and reduced debt levels. The weighted average interest rate on the Company’s revolving credit facility was 1.5% in the first half of 2009 compared to 4.3% in the first half 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 $1.8 million, or 66%, lower in the first half of 2009 than in the first half 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 half of 2009 totaled $22.0 million, or 147.7%, of pretax income compared to $62.1 million, or 33.2%, of pretax income for the six months ended June 30, 2008. The effective tax rate in the first half 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 half 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 recent and 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 typically 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 $271.2 million was provided by operations during the first half of 2009 compared to cash totaling $188.1 million provided by operations during the first half of 2008. During the first half of 2009, $130.6 million was provided by working capital, primarily due to lower receivable levels resulting from decreased revenues and due to decreased tubular inventory levels. During the first half of 2008, operating cash flow was increased by higher earnings levels and, to a lesser extent, positive working capital changes.

     Cash was used in investing activities during the six months ended June 30, 2009 and 2008 in the amount of $33.6 million and $153.5 million, respectively. Capital expenditures, including capitalized interest, totaled $52.8 million and $135.7 million during the six months ended June 30, 2009 and 2008, respectively. Capital expenditures

23

in both years consisted principally of purchases of assets for our well site services segment particularly for accommodations investments made in support of Canadian oil sands development. In the six months ended June 30, 2009, we received $21.2 million from Boots & Coots in full satisfaction of their note receivable.

     In the six months ended June 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 six months ended June 30, 2009.

     We have significantly reduced our capital spending in the first half of 2009 compared to 2008. We currently expect to spend a total of approximately $140 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. 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 have 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 which would draw on such liquidity.

     Net cash of $216.8 million was used in financing activities during the six months ended June 30, 2009, primarily as a result of debt repayments under our revolving credit facility. A total of $19.3 million was used in financing activities during the six months ended June 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, which will be affected by prevailing conditions in our industry, the economy and in the financial markets and other financial, business 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 June 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 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

24

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 June 30, 2009, we had $77.2 million outstanding under the Credit Facility and an additional $19.5 million of outstanding letters of credit, leaving $403.3 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 $8.3 million. As of June 30, 2009, we had $1.0 million outstanding under these other facilities and an additional $1.1 million of outstanding letters of credit leaving $6.2 million available to be drawn under these facilities. Our total debt represented 16.2% of our total debt and shareholders’ equity at June 30, 2009 compared to 26.9% at December 31, 2008 and 26.2% at June 30, 2008.

     As of June 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 June 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 FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May 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 may 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 FSP is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. 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 $214.5 million, or 11.5%, of our total assets, as of June 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

25

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 Statement of Financial Accounting Standards No. 142 (SFAS 142), “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) 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 utilized, 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 SFAS 142 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.

Stock Based Compensation

     Since the adoption of Statement of Financial Accounting Standards No. 123R (SFAS 123R), “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

26

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 FASB Interpretation No. 48, “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 long-term debt and revolving lines of credit that are subject to the risk of loss associated with movements in interest rates. As of June 30, 2009, we had floating rate obligations totaling approximately $78.2 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 June 30, 2009 levels, our consolidated interest expense would increase by a total of approximately $0.8 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 denominated in currencies other than the U.S. dollar, which is our functional currency or 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 half of 2009, our realized foreign exchange losses were $0.5 million and are included in other operating income in the consolidated statements of operations.

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 June 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 June 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.

27

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
April 1, 2009 – April 30, 2009	—	—		3,162,344	$	59,923,188
May 1, 2009 – May 31, 2009	—	—		3,162,344	$	59,923,188
June 1, 2009 – June 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

     The Company’s Annual Meeting of Stockholders was held on May 14, 2009 (1) to elect three Class II members of the Board of Directors to serve for three-year terms and (2) to ratify the appointment of Ernst & Young LLP as independent accountants for the year ended December 31, 2009.

28

     The Class II directors elected were S. James Nelson, Gary L. Rosenthal and William T. Van Kleef. The number of affirmative votes and the number of votes withheld for the directors were:

Names	Number of Affirmative Votes		Number Withheld
S. James Nelson		46,670,375		1,033,958
Gary L. Rosenthal		46,672,103		1,032,230
William T. Van Kleef		46,279,047		1,425,286

     Following the annual meeting, Stephen A. Wells, Martin Lambert, Mark G. Papa, Christopher T. Seaver, Douglas E. Swanson and Cindy B. Taylor continued in their terms as directors.

     The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the ratification of the appointment of Ernst & Young LLP were:

Number of Affirmative Votes	Number of Negative Votes	Abstentions
47,397,129	285,824	21,382

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)

29

Exhibit No.				Description
				(incorporated by reference to Oil States’ Current Reports on Form 8-K filed with the Commission on June 23, 2005 and July 13, 2005).
	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.

30

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: July 30, 2009	By	/s/ BRADLEY J. DODSON
		Bradley J. Dodson
		Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)
Date: July 30, 2009	By	/s/ ROBERT W. HAMPTON
		Robert W. Hampton
		Senior Vice President — Accounting and Secretary (Duly Authorized Officer and Chief Accounting Officer)

31

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).
	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.

32