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 ~~March 31,~~June 30, 2007


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

For the transition period from to

Commission file number:1-16337

OIL STATES INTERNATIONAL, INC.

(Exact name of registrant as specified in its charter)


Delaware		76-0476605

(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

Three Allen Center, 333 Clay Street, Suite 4620,
Houston, Texas		77002

(Address of principal executive offices)		(Zip Code)

(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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 2b-2 of the Exchange Act. (Check one):

Large Accelerated Filerþ Accelerated Filero Non-Accelerated Filero

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 ~~49,238,957~~49,615,077 shares of common stock outstanding and ~~2,085,452~~2,090,796 shares of treasury stock as of
~~April~~ July 20, 2007.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Amounts)


	THREE MONTHS ENDED						THREE MONTHS ENDED						SIX MONTHS ENDED
	MARCH 31,						JUNE 30,						JUNE 30,
	2007			2006			2007			2006			2007			2006
Revenues	$	480,516		$	496,231		$	499,308		$	463,359		$	979,824		$	959,590

Costs and expenses:
Cost of sales		355,803			378,233			386,710			353,686			742,513			731,919
Selling, general and administrative expenses		27,324			25,444			28,225			26,753			55,548			52,197
Depreciation and amortization expense		14,419			12,886			16,113			12,995			30,532			25,881
Other operating expense		79			465
Other operating (income) expense								(221	)		(78	)		(141	)		387

		397,625			417,028			430,827			393,356			828,452			810,384

Operating income		82,891			79,203			68,481			70,003			151,372			149,206

Interest expense		(4,842	)		(4,796	)		(3,739	)		(4,938	)		(8,581	)		(9,734	)
Interest income		926			273			784			683			1,710			956
Equity in earnings of unconsolidated affiliates		542			684			748			1,303			1,290			1,987
Sale of workover services business		—			11,494			—			(244	)		—			11,250
Other income		114			246
Gain on sale of investment								12,774			—			12,774			—
Other income (expense)								237			(1	)		351			245

Income before income taxes		79,631			87,104			79,285			66,806			158,916			153,910
Income tax expense		(27,170	)		(34,188	)		(27,052	)		(21,501	)		(54,222	)		(55,689	)

Net income	$	52,461		$	52,916		$	52,233		$	45,305		$	104,694		$	98,221


Net income per share:
Basic	$	1.06		$	1.08		$	1.06		$	0.91		$	2.12		$	1.99
Diluted	$	1.05		$	1.04		$	1.03		$	0.88		$	2.08		$	1.92

Weighted average number of common shares outstanding:
Basic		49,268			49,208			49,341			49,598			49,305			49,403
Diluted		49,994			51,022			50,833			51,230			50,414			51,126

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands)


	MARCH 31,			DECEMBER 31,			JUNE 30,			DECEMBER 31,
	2007			2006			2007			2006
	(UNAUDITED)						(UNAUDITED)
ASSETS

Current assets:
Cash and cash equivalents	$	22,461		$	28,396		$	21,121		$	28,396
Accounts receivable, net		361,663			351,701			366,456			351,701
Inventories, net		383,209			386,182			365,880			386,182
Prepaid expenses and other current assets		23,190			17,710			28,430			17,710

Total current assets		790,523			783,989			781,887			783,989

Property, plant, and equipment, net		383,567			358,716			444,978			358,716
Goodwill, net		332,718			331,804			337,026			331,804
Investments in unconsolidated affiliates		38,641			38,079			22,711			38,079
Other non-current assets		58,157			58,506			57,304			58,506

Total assets	$	1,603,606		$	1,571,094		$	1,643,906		$	1,571,094


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt							$	176,545		$	6,873
Accounts payable and accrued liabilities	$	184,686		$	199,842			212,470			199,842
Income taxes		15,491			11,376			912			11,376
Current portion of long-term debt		6,487			6,873
Deferred revenue		53,024			58,645			46,192			58,645
Other current liabilities		5,427			3,680			1,592			3,680

Total current liabilities		265,115			280,416			437,711			280,416

Long-term debt		382,567			391,729			167,103			391,729
Deferred income taxes		39,233			38,020			38,513			38,020
Other liabilities		24,898			21,093			26,413			21,093

Total liabilities		711,813			731,258			669,740			731,258

Stockholders’ equity:
Common stock		513			511			517			511
Additional paid-in capital		376,249			372,043			385,940			372,043
Retained earnings		539,801			487,627			592,034			487,627
Accumulated other comprehensive income		33,245			30,183			53,827			30,183
Treasury stock		(58,015	)		(50,528	)		(58,152	)		(50,528	)

Total stockholders’ equity		891,793			839,836			974,166			839,836

Total liabilities and stockholders’ equity	$	1,603,606		$	1,571,094		$	1,643,906		$	1,571,094

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)


	THREE MONTHS						SIX MONTHS
	ENDED MARCH 31,						ENDED JUNE 30,
	2007			2006			2007			2006
Cash flows from operating activities:
Net income	$	52,461		$	52,916		$	104,694		$	98,221
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		14,419			12,886			30,532			25,881
Deferred income tax provision		3,702			2,788			2,989			1,071
Excess tax benefits from share-based payment arrangements		(545	)		(1,791	)		(3,344	)		(4,792	)
Non-cash gain on sale of workover services business		—			(11,494	)		—			(11,250	)
Equity in earnings of unconsolidated subsidiaries		(542	)		(684	)		(1,290	)		(1,987	)
Non-cash compensation charge		1,920			1,688			3,708			4,206
Gain on sale of investment								(12,774	)		—
Gain on disposal of assets		(265	)		(23	)		(825	)		(75	)
Other, net		502			790			19			1,309
Changes in working capital		(20,317	)		(38,418	)		(2,292	)		(50,762	)

Net cash flows provided by operating activities		51,335			18,658			121,417			61,822

Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		—			(49	)		—			(99	)
Cash balances of workover services business sold		—			(4,366	)		—			(4,366	)
Capital expenditures		(36,900	)		(26,542	)		(100,556	)		(56,999	)
Proceeds from sale of investment								29,354			—
Proceeds from sale of equipment		428			792			1,318			1,567
Other, net		(862	)		(30	)		(412	)		(530	)

Net cash flows used in investing activities		(37,334	)		(30,195	)		(70,296	)		(60,427	)

Cash flows from financing activities:
Revolving credit borrowings (repayments)		(9,625	)		5,300
Revolving credit repayments								(52,983	)		(10,615	)
Debt repayments		(448	)		(1,854	)		(5,504	)		(2,184	)
Issuance of common stock		1,743			3,297			6,684			7,823
Purchase of treasury stock		(12,211	)		—			(12,211	)		(3,044	)
Excess tax benefits from share-based payment arrangements		545			1,791			3,344			4,792
Other, net		(212	)		(101	)		(421	)		(193	)

Net cash flows provided by (used in) financing activities		(20,208	)		8,433
Net cash flows used in financing activities								(61,091	)		(3,421	)

Effect of exchange rate changes on cash		315			(178	)		2,869			950

Net decrease in cash and cash equivalents from continuing operations		(5,892	)		(3,282	)		(7,101	)		(1,076	)
Net cash used in discontinued operations — operating activities		(43	)		(17	)
Net cash used in discontinued operations – operating activities								(174	)		(81	)
Cash and cash equivalents, beginning of period		28,396			15,298			28,396			15,298

Cash and cash equivalents, end of period	$	22,461		$	11,999		$	21,121		$	14,141


Non-cash investing activities:
Receipt of stock and notes for hydraulic workover services business in merger transaction, net of unrecognized gain of $9.6 million (See Note 11)	$	—		$	50,349
Receipt of stock and notes for hydraulic workover services business in merger transaction, net of unrecognized gain of $9.4 million (See Note 11)								—		$	50,105
Non-cash financing activities:
Reclassification of 2 3/8% contingent convertible senior notes to current liabilities							$	175,000			—

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 ~~(the~~(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 ~~condensed~~ 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, 2006.

2. RECENT ACCOUNTING PRONOUNCEMENT

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. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. The Company is currently evaluating the impact of SFAS 157, but does not expect the adoption of SFAS 157 to have a material impact on its results from operations or financial position.

In February 2007, the FASB issued SFAS No. 159 (SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”. SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of SFAS 159, but does not expect the adoption of SFAS 159 to have a material impact on its results from operations or financial position.

See also Note 9 —– Income Taxes and Change in Accounting Principle.

MARCH 31, DECEMBER 31,
2007 2006
Inventories, net:

Tubular goods $ 251,449 $ 261,785
Other finished goods and purchased products 54,327 50,095
Work in process 41,169 45,848
Raw materials 43,435 35,642

Total inventories 390,380 393,370
Inventory reserves (7,171 ) (7,188 )

$ 383,209 $ 386,182


	JUNE 30,			DECEMBER 31,
	2007			2006
Accounts receivable, net:
Trade	$	292,045		$	269,136
Unbilled revenue		76,010			83,782
Other		1,318			1,726
Allowance for doubtful accounts		(2,917	)		(2,943	)

	$	366,456		$	351,701

ESTIMATED MARCH 31, DECEMBER 31,
USEFUL LIFE 2007 2006
Property, plant and equipment, net:

Land $ 9,746 $ 9,112
Buildings and leasehold improvements 5-50 years 79,606 77,853
Machinery and equipment 2-20 years 337,573 326,977
Rental tools 1-10 years 65,990 64,178
Office furniture and equipment 1-10 years 19,961 18,832
Vehicles 4-10 years 35,347 31,541
Construction in progress 36,946 18,811

Total property, plant and equipment 585,169 547,304
Less: Accumulated depreciation (201,602 ) (188,588 )

$ 383,567 $ 358,716


	JUNE 30,			DECEMBER 31,
	2007			2006
Inventories, net:
Tubular goods	$	221,702		$	261,785
Other finished goods and purchased products		57,405			50,095
Work in process		49,853			45,848
Raw materials		44,406			35,642

Total inventories		373,366			393,370
Inventory reserves		(7,486	)		(7,188	)

	$	365,880		$	386,182

MARCH 31, DECEMBER 31,
2007 2006
Accounts payable and accrued liabilities:

Trade accounts payable $ 148,766 $ 142,204
Accrued compensation 12,375 29,058
Accrued insurance 6,249 5,836
Accrued taxes, other than income taxes 4,720 3,317
Reserves related to discontinued operations 3,313 3,357
Other 9,263 16,070

$ 184,686 $ 199,842


	ESTIMATED	JUNE 30,			DECEMBER 31,
	USEFUL LIFE	2007			2006
Property, plant and equipment, net:
Land		$	11,525		$	9,112
Buildings and leasehold improvements	5-50 years		88,829			77,853
Machinery and equipment	2-20 years		372,400			326,977
Rental tools	1-10 years		70,462			64,178
Office furniture and equipment	1-10 years		21,310			18,832
Vehicles	4-10 years		39,271			31,541
Construction in progress			61,694			18,811


Total property, plant and equipment			665,491			547,304
Less: Accumulated depreciation			(220,513	)		(188,588	)

		$	444,978		$	358,716

~~4. EARNINGS PER SHARE~~

THREE MONTHS ENDED
MARCH 31,
2007 2006
(In thousands, except per share data)
Basic earnings per share:
Net income $ 52,461 $ 52,916

Weighted average number of shares outstanding 49,268 49,208

Basic earnings per share $ 1.06 $ 1.08

Diluted earnings per share:
Net income $ 52,461 $ 52,916

Weighted average number of shares outstanding 49,268 49,208
Effect of dilutive securities:
Options on common stock 655 1,028
2 3/8% Contingent Convertible Notes — 724
Restricted stock awards and other 71 62

Total shares and dilutive securities 49,994 51,022

Diluted earnings per share $ 1.05 $ 1.04


	JUNE 30,		DECEMBER 31,
	2007		2006
Accounts payable and accrued liabilities:
Trade accounts payable	$	166,836	$	142,204
Accrued compensation		17,429		29,058
Accrued insurance		7,512		5,836
Accrued taxes, other than income taxes		6,166		3,317
Reserves related to discontinued operations		3,183		3,357
Other		11,344		16,070

	$	212,470	$	199,842

4. EARNINGS PER SHARE

The calculation of earnings per share is presented below (in thousands except per share amounts):


	THREE MONTHS ENDED				SIX MONTHS ENDED
	JUNE 30,				JUNE 30,
	2007		2006		2007		2006
Basic earnings per share:
Net income	$	52,233	$	45,305	$	104,694	$	98,221


Weighted average number of shares outstanding		49,341		49,598		49,305		49,403

									��
Basic earnings per share	$	1.06	$	0.91	$	2.12	$	1.99


Diluted earnings per share:
Net income	$	52,233	$	45,305	$	104,694	$	98,221


Weighted average number of shares outstanding		49,341		49,598		49,305		49,403
Effect of dilutive securities:
Options on common stock		673		857		664		943
2 3/8% Contingent Convertible Notes		741		721		370		723
Restricted stock awards and other		78		54		75		57


Total shares and dilutive securities		50,833		51,230		50,414		51,126


Diluted earnings per share	$	1.03	$	0.88	$	2.08	$	1.92

5. GOODWILL

Changes in the carrying amount of goodwill for the ~~three~~six month period ended ~~March 31,~~June 30, 2007 isare as follows (in thousands):


	Balance as of		Acquisitions		Foreign currency		Balance as of		Balance as of		Acquisitions		Foreign currency		Balance as of
	January 1,		and		translation and		March 31,		January		and		translation and		June 30,
	2007		adjustments		other changes		2007		2007		adjustments		other changes		2007
Offshore Products	$	75,716	$	—	$	33	$	75,749	$	75,716	$	—	$	168	$	75,884
Tubular Services		62,453		364		—		62,817		62,453		364		—		62,817
Wellsite Services		193,635		—		517		194,152
Well Site Services										193,635		—		4,690		198,325

Total	$	331,804	$	364	$	550	$	332,718	$	331,804	$	364	$	4,858	$	337,026

closing price of the Company’s common stock for the prescribed measurement periods during the quarter ended June 30, 2007, the contingent conversion conditions on the 2 3/8% Notes were met. As a result, the 2 3/8% Notes were convertible at the option of the holder as of June 30, 2007, and, as such, the principal balance of the notes has been classified as a current liability. The holders of the 2 3/8% Notes may convert their notes only during the quarter ended September 30, 2007 based on the share price performance during measurement periods in the quarter ended June 30, 2007. 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 prescribed measurement periods.

7. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING:

Comprehensive income for the three and six months ended ~~March 31,~~June 30, 2007 and 2006 was as follows (in thousands):


	THREE MONTHS				THREE MONTHS				SIX MONTHS
	ENDED MARCH 31				ENDED JUNE 30,				ENDED JUNE 30,
	2007		2006		2007		2006		2007		2006
Comprehensive income:
Net income	$	52,461	$	52,916	$	52,233	$	45,305	$	104,694	$	98,221
Other comprehensive income:
Cumulative translation adjustment		3,062		24		20,582		11,596		23,644		11,621
Foreign currency hedge		—		41		—		—		—		41

Total comprehensive income	$	55,523	$	52,981	$	72,815	$	56,901	$	128,338	$	109,883

Stock based compensation pre-tax expense recognized under SFAS 123R in the ~~three months~~six month periods ended ~~March 31,~~June 30, 2007 and June 30, 2006 totaled ~~$1.9~~$3.7 million and ~~$1.7~~$4.2 million, or ~~$0.04~~$0.05 and $0.05 per diluted share after tax, respectively. For the three month periods ended June 30, 2007 and June 30, 2006, our stock compensation pre-tax expense totaled $1.8 million and $2.5 million, or $0.02 and $0.03 per diluted share after tax, respectively. At ~~March 31,~~June 30, 2007, ~~$17.3~~$16.2 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized. The total fair value of restricted stock awards that vested during the ~~three month~~six months ended ~~March 31,~~June 30, 2007 was ~~$0.9~~$2.2 million.

9. INCOME TAXES AND CHANGE IN ACCOUNTING PRINCIPLE

The Company’s income tax provision for the three months and six months ended ~~March 31,~~June 30, 2007 totaled ~~$27.2~~$27.1 million and $54.2 million, respectively, or 34.1%, of pretax income in both periods, compared to ~~$34.2~~$21.5 million, or ~~39.2%~~32.2%, of pretax income for the three months ended ~~March 31,~~June 30, 2006 and $55.7 million, or 36.2%, of pretax income for the six months ended June 30, 2006. The effective rate was higher in the ~~quarter~~six months ended ~~March 31,~~June 30, 2006 principally because of the higher effective tax rate applicable to the gain on the sale of the workover services business.

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”), which became effective for the Company on January 1, 2007. The Interpretation prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to

be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The adoption of FIN 48 has resulted in a transition adjustment reducing beginning retained earnings by $0.3 million; $0.2 million in taxes and $0.1 million in interest. Had the transition adjustment not been recognized as an adjustment of beginning retained earnings, it would have affected the effective tax rate. Interest costs and penalties related to income taxes are classified as income tax expense.

The total amount of unrecognized tax benefits as of ~~March 31,~~June 30, 2007 was ~~$4.3~~$4.5 million, including ~~$0.6~~$0.9 million of accrued interest. Currently, the Company’s consolidated U.S. federal return for the year 2004 is undergoing an examination by the Internal Revenue Service. Tax years subsequent to 2003 remain open to U.S. federal tax audit and, because of net operating losses (NOL’s) utilized by the Company, years from 1994 to 2002 remain subject to federal tax audit with respect to NOL’s available for tax carryforward. Our Canadian subsidiaries’ federal tax returns since 2003 are subject to audit by Canada Revenue Agency.

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 our Canadian business related to the provision of work force accommodations, catering and logistics services are seasonal with significant activity occurring in the peak winter drilling season. We sold our workover services, business, effective March 1, 2006, in exchange for an equity interest in Boots & Coots International Well Control, Inc. (AMEX:WEL) (Boots & Coots) and a note receivable – See Note 11.

Financial information by business segment for each of the three and six months ended ~~March 31,~~June 30, 2007 and 2006 is summarized in the following table (in thousands):


	Revenues from		Depreciation		Operating						Revenues from		Depreciation		Operating
	unaffiliated		and		income		Capital				unaffiliated		and		income			Capital
	customers		amortization		(loss)		expenditures		Total assets		customers		amortization		(loss)			expenditures		Total assets
Three months ended March 31, 2007
Well Site Services —
Three months ended June 30, 2007
Well Site Services -
Accommodations	$	93,553	$	3,828	$	34,992	$	17,642	$	329,353	$	61,864	$	4,923	$	13,152		$	38,250	$	368,004
Rental tools		53,639		4,739		17,482		8,425		269,814		50,842		5,123		14,131			9,430		275,880
Drilling and other (1)		30,918		2,651		9,994		7,390		168,072		36,752		2,892		11,816			11,885		164,801

Total Well Site Services												149,458		12,938		39,099			59,565		808,685
Offshore Products												135,437		2,795		24,207			3,165		419,688
Tubular Services												214,413		331		10,710			760		388,286
Corporate and Eliminations												—		49		(5,535	)		165		27,247

Total											$	499,308	$	16,113	$	68,481		$	63,655	$	1,643,906


Three months ended June 30, 2006
Well Site Services -
Accommodations											$	75,015	$	4,025	$	15,581		$	18,497	$	304,391
Rental tools												46,777		4,152		14,193			5,763		259,106
Drilling and other (1)												32,205		1,826		13,664			4,006		139,517

Total Well Site Services												153,997		10,003		43,438			28,266		703,014
Offshore Products												93,675		2,692		15,186			1,800		337,656
Tubular Services												215,687		269		17,023			357		406,982
Corporate and Eliminations												—		31		(5,644	)		33		16,281

											$	463,359	$	12,995	$	70,003		$	30,456	$	1,463,933


	Revenues from		Depreciation		Operating							Revenues from		Depreciation		Operating
	unaffiliated		and		income			Capital				unaffiliated		and		income			Capital
	customers		amortization		(loss)			expenditures		Total assets		customers		amortization		(loss)			expenditures		Total assets
Total Well Site Services		178,110		11,218		62,468			33,457		767,239
Offshore Products		119,039		2,830		17,608			3,244		410,637
Tubular Services		183,367		323		7,734			133		401,727
Corporate and Eliminations		—		48		(4,919	)		66		21,473

Total	$	480,516	$	14,419	$	82,891		$	36,900	$	1,601,076


Three months ended March 31, 2006
Six months ended June 30, 2007
Well Site Services -
Accommodations	$	104,589	$	3,578	$	25,359		$	11,536	$	296,005	$	155,417	$	8,750	$	48,144		$	55,893	$	368,004
Rental tools		49,588		4,005		16,893			5,542		253,423		104,481		9,863		31,613			17,854		275,880
Drilling and other (1)		28,018		1,704		11,781			6,332		133,600		67,669		5,543		21,810			19,275		164,801
Workover services (1)		8,544		700		1,789			263		—		—		—		—			—		—

Total Well Site Services		190,739		9,987		55,822			23,673		683,028		327,567		24,156		101,567			93,022		808,685
Offshore Products		78,272		2,609		10,065			2,560		305,159		254,477		5,625		41,815			6,409		419,688
Tubular Services		227,220		263		17,818			286		404,077		397,780		654		18,444			894		388,286
Corporate and Eliminations		—		27		(4,502	)		23		19,957		—		97		(10,454	)		231		27,247

Total												$	979,824	$	30,532	$	151,372		$	100,556	$	1,643,906
	$	496,231	$	12,886	$	79,203		$	26,542	$	1,412,221

Six months ended June 30, 2006
Well Site Services -
Accommodations												$	179,604	$	7,603	$	40,940		$	30,034	$	304,391
Rental tools													96,365		8,233		31,010			11,305		259,106
Drilling and other (1)													60,223		3,504		25,387			10,338		139,517
Workover services													8,544		650		1,922			263		—

Total Well Site Services													344,736		19,990		99,259			51,940		703,014
Offshore Products													171,946		5,300		25,251			4,360		337,656
Tubular Services													442,908		533		34,842			642		406,982
Corporate and Eliminations													—		58		(10,146	)		57		16,281

Total												$	959,590	$	25,881	$	149,206		$	56,999	$	1,463,933

In April 2007, the Company sold, pursuant to a registration statement filed by Boots & Coots, 14,950,000 shares of Boots & Coots stock that it owned for net proceeds of $29.4 million and, as a result, we recognized a net after tax gain of $8.4 million, or approximately $0.17 per diluted share in the second quarter of 2007. After the sale of Boots & Coots shares by the Company and the sale of primary shares of stock directly by Boots & Coots in April 2007, the Company’s ownership interest in Boots & Coots was reduced to approximately 15%. The equity method of accounting will continue to be used to account for the Company’s remaining investment in Boots & Coots common stock (11.5 million shares). The carrying value of the Company’s remaining investment in Boots & Coots stock totals $18.5 million as of June 30, 2007.

12. COMMITMENTS AND CONTINGENCIES

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 that purchased 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.

On February 18, 2005, we announced that we had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of our subsidiaries (the Subsidiary) to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in our previously reported fourth quarter 2004 results. We and independent counsel retained by our Audit Committee conducted separate investigations consisting of interviews and a thorough examination of the facts and circumstances in this matter. We voluntarily reported the results of our investigation to the Securities and Exchange Commission (the SEC) and fully cooperated with requests for information received from the SEC. On October 31, 2005, our counsel received a “Wells Notice” from the SEC staff indicating that it made a preliminary decision to recommend that the SEC bring a civil action against the Company alleging violations of provisions of the Securities and Exchange Act of 1934 (the Act) relating to the maintenance of books, records and internal accounting controls and procedures as set forth in Sections 13(b)(2)(A) and (B) of the Act. The Company reached a settlement agreement with the SEC on April 27, 2006. The Company consented to an Order by the SEC (the Order), without admitting or denying the findings in the Order, that required the Company to cease and desist from committing or causing violations of the “books and records” and “internal control provisions” of the Act. The settlement did not require the Company to pay a monetary penalty.

13. SUBSEQUENT ~~EVENT~~EVENTS

In ~~April~~July and August 2007, the Company ~~sold 14,950,000 shares~~announced the expansion of ~~Boots & Coots stock~~its rental tools operations through two acquisitions.

In July 2007, we acquired substantially all of the assets of Wire Line Service, Ltd. (“Well Testing”), a Midland, Texas business that ~~it owned for net proceeds of $29.4~~primarily provides well testing and flowback services through its locations in Texas and New Mexico. Total consideration was approximately $44.0 million and ~~as a result, we expect to recognize a net after tax gain~~consisted of ~~$8.4 million, or approximately $0.17 per diluted share~~cash in the ~~second quarter~~amount of ~~2007. After~~$41.0 million and a $3.0 million note payable to the ~~sale~~seller that bears interest at 6% and is payable in two equal annual installments beginning one year from the July 2, 2007 date of ~~Boots & Coots shares by~~ the ~~Company~~closing of the transaction.

In August 2007, we completed the acquisition of substantially all of the assets of Schooner Petroleum Services, Inc. (“Schooner”). Schooner, headquartered in Houston, Texas, primarily provides completion-related rental tools and ~~considering~~services through eleven locations in Texas, Louisiana, Wyoming and Arkansas. The consideration for the ~~sale~~assets acquired, totaling approximately $67.0 million subject to customary post-closing adjustments, consisted of ~~primary shares~~cash and a $6.0 million note payable to the seller that bears interest at 6% and is payable in two equal annual installments beginning one year from the August 2, 2007 date of ~~stock directly by Boots & Coots in April 2007,~~the closing of the transaction.

These acquisitions were funded with amounts available under the Company’s ownership interest in Boots & Coots will be approximately 15%. The equity method of accounting will be continued for the Company’s investment in the remaining 11.5 million shares of Boots & Coots common stock still owned after the sale considering the Company’s continuing interests in Boots & Coots. Following the sale of stock, the carrying value of the Company’s remaining investment in Boots & Coots stock totals $18.2 million. See also Note 11 — Workover Services Business Transaction above.existing credit facility.

1112

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 ourForm 10-K Annual Report for the year ended December 31, 2006 filed with the Securities and Exchange Commission on February 28, 2007 and Item 2 of thisForm 10-Q, which follows. 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 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 than our offshore products segment. 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 pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs. In this segment, we are particularly influenced by 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 (for example, deepwater wells usually require higher priced seamless alloy tubulars) and the level of oil country tubular goods (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, catering and logistics services and rental tools. Demand for our drilling services is driven by land drilling activity in Texas, New Mexico, 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 the U.S. and Canada. Our accommodations business is conducted primarily in Canada and its activity levels are driven by oil sands development in Northern Alberta, oil and gas drilling activity, and to a lesser extent mining activities.

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 and well site services segments are 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.

1213

The average North American rig count for the ~~quarter~~six months ended ~~March 31,~~June 30, 2007 increased by 8131 rigs, or ~~3.7%~~1.5%, compared to the ~~quarter~~six months ended ~~March 31,~~June 30, 2006. The increases in U.S. land rig counts have contributed to increased well site services revenues, particularly in our land drilling and rental tool businesses. ~~The~~However, decreased Canadian rig counts, compared to the first ~~quarter~~six months of 2006, have adversely impacted our rental tools and accommodations, catering and logistical services ~~serving~~which support Canadian oil and gas drilling operations. These decreases in Canada were ~~more than~~ offset by growth in accommodations, catering and logistical services in support of oil sands ~~development. Our~~development in Canada. Also, our well site services segment results for the first ~~quarter~~half of 2007 also benefited from capital spending, which aggregated ~~$127~~$158 million in the twelve months ended ~~March 31,~~June 30, 2007 in that segment, and the impact of increased activity levels and pricing gains in certain rental tool and accommodations business lines.

Management believes that, based on the current economic environment, oil and gas producers will continue to explore for and develop oil and gas reserves at an active pace in spite of continued ~~volality~~volatility in current U.S. domestic natural gas and crude oil prices, given their longer term views of supply and demand fundamentals. Management estimates that approximately ~~60%~~55% to 65% of the Company’s revenues are dependent on North American natural gas drilling and completion activity with a significant amount of such revenues being derived from lower margin OCTG sales. As such, we estimate that our profitability is more evenly impacted by oil ~~price~~ driven activity and natural gas ~~price~~ driven activity. Our customers have increased their spending and commitments for deepwater offshore exploration and development which has benefited our offshore products segment. Our customers have also announced significant levels of expenditures for oil sands related projects in Canada. ~~However, there~~We continue to focus on expansion opportunities and execution initiatives in these high growth markets supporting deepwater development and Canadian oil sands spending. Deepwater infrastructure spending and capital equipment upgrades have driven improved financial results and improved backlog. In addition, our commitment to support the oil sands activity continues to increase with our investments in large scale accommodations in the oil sands region of northern Alberta, Canada. We see continued growth in activity for our accommodations business in the oil sands region as labor needs in the region are expected to double over the next three to five years.

Consolidated Results of Operations


	THREE MONTHS ENDED												THREE MONTHS ENDED												SIX MONTHS ENDED
	March 31,												June 30,												June 30,
							Variance												Variance												Variance
							2007 vs. 2006												2007 vs. 2006												2007 vs. 2006
	2007			2006			$			%			2007			2006			$			%			2007			2006			$			%
Revenues
Well site services —
Well Site Services -
Accommodations	$	93.6		$	104.6		$	(11.0	)		(11	%)	$	61.9		$	75.0		$	(13.1	)		(17	%)	$	155.4		$	179.6		$	(24.2	)		(13	%)
Rental Tools		53.6			49.6			4.0			8	%		50.8			46.8			4.0			9	%		104.5			96.4			8.1			8	%
Drilling and Other		30.9			28.0			2.9			10	%		36.8			32.2			4.6			14	%		67.6			60.2			7.4			12	%
Workover Services		—			8.5			(8.5	)		(100	%)		—			—			—			0	%		—			8.5			(8.5	)		(100	%)

Total Well Site Services		178.1			190.7			(12.6	)		(7	%)		149.5			154.0			(4.5	)		(3	%)		327.5			344.7			(17.2	)		(5	%)
Offshore Products		119.0			78.3			40.7			52	%		135.4			93.7			41.7			45	%		254.5			172.0			82.5			48	%
Tubular services		183.4			227.2			(43.8	)		(19	%)		214.4			215.7			(1.3	)		(1	%)		397.8			442.9			(45.1	)		(10	%)

Total	$	480.5		$	496.2		$	(15.7	)		(3	%)	$	499.3		$	463.4		$	35.9			8	%	$	979.8		$	959.6		$	20.2			2	%

Cost of sales
Well site services —
Well Site Services -
Accommodations	$	49.7		$	71.3		$	(21.6	)		(30	%)	$	38.5		$	50.5		$	(12.0	)		(24	%)	$	88.2		$	121.8		$	(33.6	)		(28	%)
Rental Tools		25.4			23.1			2.3			10	%		26.1			22.7			3.4			15	%		51.5			45.8			5.7			12	%
Drilling and Other		17.5			14.0			3.5			25	%		21.5			16.2			5.3			33	%		39.0			30.2			8.8			29	%
Workover Services		—			5.3			(5.3	)		(100	%)		—			—			—			0	%		—			5.3			(5.3	)		(100	%)

Total Well Site Services		92.6			113.7			(21.1	)		(19	%)		86.1			89.4			(3.3	)		(4	%)		178.7			203.1			(24.4	)		(12	%)
Offshore Products		90.9			58.4			32.5			56	%		99.9			68.7			31.2			45	%		190.9			127.1			63.8			50	%
Tubular services		172.3			206.1			(33.8	)		(16	%)		200.7			195.6			5.1			3	%		372.9			401.7			(28.8	)		(7	%)

Total	$	355.8		$	378.2		$	(22.4	)		(6	%)	$	386.7		$	353.7		$	33.0			9	%	$	742.5		$	731.9		$	10.6			1	%

Gross margin
Well site services —
Well Site Services -
Accommodations	$	43.8		$	33.3		$	10.5			32	%	$	23.4		$	24.5		$	(1.1	)		(4	%)	$	67.2		$	57.8		$	9.4			16	%
Rental Tools		28.2			26.5			1.7			6	%		24.7			24.1			0.6			2	%		53.0			50.6			2.4			5	%
Drilling and Other		13.5			14.0			(0.5	)		(4	%)		15.3			16.0			(0.7	)		(4	%)		28.6			30.0			(1.4	)		(5	%)
Workover Services		—			3.2			(3.2	)		(100	%)		—			—			—			0	%		—			3.2			(3.2	)		(100	%)

Total Well Site Services		85.5			77.0			8.5			11	%		63.4			64.6			(1.2	)		(2	%)		148.8			141.6			7.2			5	%
Offshore Products		28.1			19.9			8.2			41	%		35.5			25.0			10.5			42	%		63.6			44.9			18.7			42	%
Tubular services		11.1			21.1			(10.0	)		(47	%)		13.7			20.1			(6.4	)		(32	%)		24.9			41.2			(16.3	)		(40	%)

Total	$	124.7		$	118.0		$	6.7			6	%	$	112.6		$	109.7		$	2.9			3	%	$	237.3		$	227.7		$	9.6			4	%

Gross margin as a percent of revenues
Well site services —
Well Site Services -
Accommodations		47	%		32	%								38	%		33	%								43	%		32	%
Rental Tools		53	%		53	%								49	%		51	%								51	%		52	%
Drilling and Other		44	%		50	%								42	%		50	%								42	%		50	%
Workover Services		—	%		38	%								—	%		—	%								—	%		38	%
Total Well Site Services		48	%		40	%								42	%		42	%								45	%		41	%
Offshore Products		24	%		25	%								26	%		27	%								25	%		26	%
Tubular services		6	%		9	%								6	%		9	%								6	%		9	%
Total		26	%		24	%								23	%		24	%								24	%		24	%

Rental tools revenues increased $4.0 million, or 8%9%, in the ~~first~~second quarter of 2007 compared to the ~~first~~second quarter of 2006 as a result of increased prices realized and capital additions made since the ~~first~~second quarter of 2006, which were only partially offset by decreased Canadian rental tool revenues in the ~~first~~second quarter of 2007 caused by ~~lower~~reduced Canadian drilling and completion activity when compared to the ~~first~~second quarter of 2006. Our drilling revenues increased ~~$2.9~~$4.6 million, or ~~10%~~14%, in the ~~first~~second quarter of 2007 compared to the ~~first~~second quarter of 2006 as a result of an increased rig fleet size ~~(five~~(four additional rigs) and higher rates, partially offset by lower utilization in the ~~first quarter of 2007. The sale of our workover services business in March 2006 caused an $8.5 million decrease in revenues in the first~~second quarter of 2007 compared to ~~the first quarter of~~ 2006.

Our accommodations ~~business~~ revenues decreased ~~$11.0~~$13.1 million, or ~~11%~~17%, as a result of decreased oil and gas ~~drilling related accommodations revenues due to lower~~ drilling activity levels in Canada and lower third party accommodations manufacturing revenues, which were only partially offset by higher revenues driven by increased activity in support of the oil sands developments in ~~Canada and the increased accommodations capacity we have placed in service since the first quarter of 2006.~~

Our offshore products revenues increased $40.7 million, or 52%, due to increased deepwater development spending and capital equipment upgrades by our customers. Our offshore products backlog increased to $373.4 million at March 31, 2007 compared to $349.3 million at December 31, 2006 and $220.8 million at March 31, 2006.Canada.

Cost of Sales.Our consolidated cost of sales ~~decreased $22.4~~increased $33.0 million, or 6%9%, in the ~~first~~second quarter of 2007 compared to the ~~first~~second quarter of 2006 primarily as a result of ~~decreases~~increases at ~~well site services~~offshore products of ~~$21.1~~$31.2 million, or ~~19%~~45%, and at tubular services of ~~$33.8~~$5.1 million, or ~~16%~~3%, which were partially offset by ~~an increase~~a decrease at ~~offshore products~~well site services of ~~$32.5~~$3.3 million, or ~~56%~~4%. Our overall gross margin as a percent of revenues ~~improved from~~was relatively constant at 23% in the second quarter of 2007 compared to 24% in the ~~first~~second quarter of ~~2006 to 26% in the first quarter of 2007.~~2006.

Tubular services cost of sales ~~decreased~~increased primarily as a result of ~~decreased~~increased tonnage shipped. Our tubular services gross margin as a percentage of revenues decreased from 9% to 6% in the ~~first~~second quarter of 2007 compared to the second quarter of 2006 as a result of lower ~~demand for our~~ OCTG mill pricing, higher industry wide inventory levels and a greater mix of relativity low margin carbon grade OCTG sales in 2007.

Our well site services gross margins as a percent of revenue ~~improved from 40%~~were flat at 42% in the ~~first~~second quarter of 2006 ~~to 48% in the first~~and second quarter of 2007. Our accommodations cost of sales decrease was driven by lower costs associated with fewer third party manufacturing projects in 2007 compared to 2006 and by lower activity in support of Canadian drilling operations in 2007. Our accommodations gross margin as a percentage of revenues improved from ~~32%~~33% in the ~~first~~second quarter of 2006 to ~~47%~~38% in the ~~first~~second quarter of 2007 because of lower manufacturing revenues, which generally earn lower margins than accommodations or catering work.

Our drilling services cost of sales ~~have~~ increased ~~$3.5~~$5.3 million, or ~~25%~~33%, in the ~~first~~second quarter of 2007 compared to the ~~first~~second quarter of 2006 as a result of an increase in the number of rigs that we operate, increased wages paid to our employees, increased transportation costs and the impact of price increases for repairs, supplies and other expenses to operate our rigs. Increased costs ~~and~~coupled with lower utilization in our areas of operations ~~adversely affected~~have reduced our drilling services gross margin ~~as a percentage of revenues which declined~~ from 50% in the ~~first~~second quarter of 2006 to ~~44%~~42% in the ~~first~~second quarter of 2007. ~~Workover services cost of sales were eliminated in the first quarter of 2007 as a result of the sale of that business in March 2006.~~

Our offshore products cost of sales increased, on a percentage basis, approximately in line with the increase in offshore products revenues.

Selling, General and Administrative Expenses.Selling, general and administrative expenses (SG&A) increased ~~$1.9~~$1.5 million, or 7%5.5%, in the ~~first~~second quarter of 2007 compared to the ~~first~~second quarter of 2006. The increase

Operating Income.Consolidated operating income ~~increased $3.7~~decreased $1.5 million, or 5%2%, in the ~~first~~second quarter of 2007 compared to the ~~first~~second quarter of 2006 primarily as a result of ~~increases~~decreases at well site services of ~~$6.6~~$4.3 million, or ~~12%~~10%, and at ~~offshore products~~tubular services of ~~$7.5~~$6.3 million, or ~~75%~~37%, which were partially offset by ~~decreased tubular services~~increased offshore products operating income of ~~$10.1~~$9.0 million, or ~~57% and the absence of $1.9 million of workover services operating income because that business was sold in March 2006.~~59%.

Interest Expense and Interest Income.Interest expense ~~increased~~decreased by ~~less than 1%~~$1.2 million, or 24%, in the ~~first~~second quarter of 2007 compared to the ~~first~~second quarter of ~~2006. Interest expense increased slightly~~2006 due to the impact of ~~higher interest rates levels which were partially offset by~~ lower debt levels. The weighted average interest rate on the Company’s revolving credit facility was ~~6.1%~~6.2% in the ~~first~~second quarter of 2007 ~~compared to 5.8% in~~and the ~~first~~second quarter of 2006. Interest income ~~increased~~ in 2007 and 2006 relate primarily ~~because of~~to the subordinated notes receivable obtained in consideration for the sale of our hydraulic workover business (see Note 11 to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q).

Equity in Earnings of Unconsolidated Affiliates.Our equity in earnings of unconsolidated affiliates is ~~higher~~lower in the ~~first~~second quarter of 2007 than in the ~~first~~second quarter of 2006 primarily because of the sale of approximately 15.0 million shares of our ~~workover services business and resultant~~investment in Boots & Coots in April 2007. As a result of this sale, our ownership interest in Boots & Coots ~~common stock,~~decreased to approximately 15%.

Income Tax Expense.Our income tax provision for the second quarter of 2007 totaled $27.1 million, or 34.1% of pretax income, compared to $21.5 million, or 32.2% of pretax income, for the second quarter of 2006. The effective tax rate was lower in the second quarter of 2006 compared to the second quarter of 2007 because of favorable Canadian tax law changes which were reflected in the 2006 period.

SIX MONTHS ENDED JUNE 30, 2007 COMPARED TO SIX MONTHS ENDED JUNE 30, 2006

We reported net income for the six months ended June 30, 2007 of $104.7 million, or $2.08 per diluted share. These results compare to $98.2 million, or $1.92 per diluted share, reported for the six months ended June 30, 2006. Net income for the first half of 2007 included a pre-tax gain of $12.8 million, or an after tax gain of $0.17 per diluted share, on the sale of 14.95 million shares of Boots & Coots International Well Control, Inc. (Boots & Coots). During the first half of 2006, we ~~account~~recognized an $11.3 million pre-tax gain or an after tax gain of $0.12 per diluted share from the sale of our workover business to Boots & Coots. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Revenues.Consolidated revenues increased $20.2 million, or 2%, in the first half of 2007 compared to the first half of 2006.

Our offshore products revenues increased $82.5 million, or 48%, due to increased deepwater development spending and capital equipment upgrades by our customers.

Tubular services revenues decreased $45.1 million, or 10%, in the first half of 2007 compared to the first half of 2006 as a result of an 8.5% decrease in tons shipped and a 1.8% decrease in average selling prices per ton.

Our well site services revenues decreased $17.2 million, or 5%, in the first half of 2007 compared to the first half of 2006.

Rental tools revenues increased $8.1 million, or 8%, in the first half of 2007 compared to the first half of 2006 as a result of increased prices realized and capital additions made since the first half of 2006, which were only partially offset by decreased Canadian rental tool revenues in the first half of 2007 caused by lower Canadian drilling and completion activity when compared to the first half of 2006. Our drilling revenues increased $7.4 million, or 12%, in the first half of 2007 compared to the first half of 2006 as a result of an increased rig fleet size

(four additional rigs) and higher rates, partially offset by lower utilization in the first half of 2007. The sale of our workover services business in March 2006 caused an $8.5 million decrease in revenues in the first half of 2007 compared to the first half of 2006.

Our accommodations business revenues decreased $24.2 million, or 13%, as a result of decreased oil and gas drilling activity levels in Canada and lower third party accommodations manufacturing revenues, which were only partially offset by higher revenues driven by increased activity in support of the oil sands developments in Canada.

Cost of Sales.Our consolidated cost of sales increased $10.6 million, or 1%, in the first half of 2007 compared to the first half of 2006 primarily as a result of an increase at offshore products of $63.8 million, or 50%, partially offset by decreases at tubular services of $28.8 million, or 7%, and well site services of $24.4 million, or 12%. Our overall gross margin as a percent of revenues was 24% in the first half of 2007 and 2006.

Tubular services cost of sales decreased as a result of decreased tonnage shipped which was partially offset by the impact of price increases for ~~under~~inventory purchased. Our tubular services gross margin as a percentage of revenues decreased from 9% to 6% in the ~~equity method~~first half of 2007 compared to the first half of 2006 as a result of lower OCTG mill pricing, higher industry wide inventory levels and a greater mix of relativity low margin carbon grade OCTG sales in 2007.

Our well site services gross margin as a percent of revenues increased from 41% to 45% in the first half of 2007 compared to the first half of 2006. Our accommodations cost of sales decreased due to lower costs associated with fewer third party manufacturing projects in 2007 compared to 2006 and reduced activity in support of Canadian drilling operations in 2007. Our accommodations gross margin as a percentage of revenues improved from 32% in the first half of 2006 to 43% in the first half of 2007 because of lower manufacturing revenues, which generally earn lower margins than accommodations or catering work.

Our drilling services cost of sales increased $8.8 million, or 29%, in the first half of 2007 compared to the first half of 2006 as a result of an increase in the number of rigs that we operate, the impact of price increases for repairs, supplies and other expenses to operate our rigs, increased transportation costs and increased wages paid to our employees. Increased costs coupled with lower utilization in our areas of operations have reduced our drilling services gross margin from 50% in the first half of 2006 to 42% in the first half of 2007.

Our offshore products cost of sales, on a percentage basis, increased approximately in line with the increase in offshore products revenues.

Selling, General and Administrative Expenses.SG&A increased $3.4 million, or 6%, in the first half of 2007 compared to the first half of 2006 due primarily to increased salaries, wages and benefits and an increase in headcount. SG&A was 5.7% of revenues in the six months ended June 30, 2007 compared to 5.4% of revenues in the six months ended June 30, 2006.

Depreciation and Amortization.Depreciation and amortization expense increased $4.7 million, or 18%, in the first half of 2007 compared to the same period in 2006 due primarily to capital expenditures made during the previous twelve months.

Operating Income.Consolidated operating income increased $2.2 million, or 1%, in the first half of 2007 compared to the first half of 2006 primarily as a result of increases at offshore products of $16.6 million, or 66%, and at well site services of $2.3 million, or 2%, which were partially offset by decreased tubular services operating income of $16.4 million, or 47%.

Interest Expense and Interest Income.Interest expense decreased by $1.2 million, or 12% in the first half of 2007 compared to the first half of 2006 due to lower debt levels. The weighted average interest rate on the Company’s revolving credit facility was 6.1% in the first half of 2007 compared to 6.0% in the first half of 2006. Interest income in 2007 and 2006 relates primarily to the subordinated notes receivable obtained in consideration for the sale of our hydraulic workover business (see Note 11 to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q).

Equity in Earnings of Unconsolidated Affiliates.Our equity in earnings of unconsolidated affiliates is lower in the first half of 2007 than in the first half of 2006 primarily because of the sale of approximately 15.0 million shares of our investment in Boots & Coots in April 2007. As a result of this sale, our ownership interest decreased to approximately 15%.

Income Tax Expense.Our income tax provision for the first ~~quarter~~half of 2007 totaled ~~$27.2~~$54.2 million, or 34.1% of pretax income, compared to ~~$34.2~~$55.7 million, or ~~39.2%~~36.2% of pretax income, for the first ~~quarter~~half of 2006. The effective tax rate was higher in the ~~quarter~~six months ended ~~March 31,~~June 30, 2006 principally because of the higher effective tax rate applicable to the gain on the sale of the workover services business.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures, such as 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 funding general working capital needs. In addition, capital is needed 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 ~~$51.3~~$121.4 million was provided by operations during the first ~~quarter~~half of 2007 compared to cash totaling ~~$18.7~~$61.8 million provided by operations during the first ~~quarter~~half of 2006. During the first half of 2007, ~~$20.3~~$2.3 million was utilized to fund working capital ~~for liquidation of relatively high year end payables levels~~associated with our growth, especially in our ~~OCTG business and for~~offshore products segment. These increased working capital needs were partially offset by a $39.8 million reduction in tubular services inventories in 2007. During the ~~build~~first half of ~~receivables in Canada caused by our growth in that region. During~~ 2006, ~~$38.4~~$50.8 million was used to fund working capital due ~~in part~~primarily to increases in receivables and inventories in our offshore products segment given the growth in activity compared to 2005.

Cash was used in investing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2007 and 2006 in the amount of ~~$37.3~~$70.3 million and ~~$30.2~~$60.4 million, respectively. Capital expenditures, including capitalized interest, totaled ~~$36.9~~$100.6 million and ~~$26.5~~$57.0 million during the ~~three~~six months ended ~~March 31,~~June 30, 2007 and 2006, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment. Net proceeds from the sale of 14.95 million shares of Boots & Coots International Well Control, Inc. common stock totaled $29.4 million. See Note 11 to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.

We currently expect to spend a total of approximately ~~$224~~$261 million for capital expenditures during 2007 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 proceeds from borrowings under our revolving credit facilities.

Net cash of ~~$20.2~~$61.1 million was used in financing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2007, primarily as a result of revolving credit facility repayments, other debt repayments and treasury stock purchases ~~and debt repayments~~ partially offset by proceeds from stock option exercises. A total of ~~$8.4~~$3.4 million was ~~provided~~used by financing activities during the ~~three~~six months ended ~~March 31, 2006, primarily as a result of borrowings under our credit line and exercises of stock options.~~June 30, 2006.

During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, an additional $50 million was approved and the duration of the program was extended to August 31, 2008. Through ~~March 31,~~June 30, 2007, a total of $57.3 million of our stock (2,064,432 shares), has been repurchased under this program, leaving a total of up to approximately $42.7 million remaining available under the program.

On December 5, 2006, we amended our existing credit agreement dated as of October 30, 2003 (the Credit Agreement). The amendment to the Credit Agreement increased the total commitments under the Credit Agreement from $325 million to $400 million and extended the maturity of the Credit Agreement to December 5, 2011. ~~The Credit Agreement permits the Company incremental borrowings of up to $100 million under the Credit Agreement, subject to lender approval, on the same terms and conditions.~~

As of ~~March 31,~~June 30, 2007, we had ~~$206.3~~$165.9 million outstanding under the Credit ~~Facility~~Agreement and an additional ~~$10.6~~$10.3 million of outstanding letters of credit, leaving ~~$183.1~~$223.8 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 ~~$8.9~~$9.0 million. As of ~~March 31,~~June 30, 2007, we had $0.9 million outstanding under these other facilities and an additional ~~$0.6~~$0.7 million of outstanding letters of credit leaving $7.4 million available to be drawn under these facilities. Our total debt represented ~~30.4%~~26.1% of the total of debt and shareholder’s equity at ~~March 31,~~June 30, 2007 compared to 32.2% at December 31, 2006 and ~~37.1%~~34.3% at ~~March 31,~~June 30, 2006.

Subsequent to June 30, 2007, we completed two acquisitions in our rental tool business for total consideration of $111.0 million, consisting primarily of cash funded by borrowings under our revolving Credit Agreement. Consideration included a total of $9.0 million of sellers' notes. These notes will be repayable in equal annual installments over a two year period beginning one year from the date of the closing of the respective transactions. (See Note 13 to the Unaudited Condensed Consolidated Statements in this Quarterly Form 10-Q).

As of June 30, 2007, we have reclassified the $175.0 million principal amount of our 2 3/8% Notes to a current liability because certain contingent conversion thresholds based on the Company’s stock price were met at that date and, as a result, note holders could present their notes for conversion only during the quarter subsequent to the June 30, 2007 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. As of June 30, 2007, the recent trading prices exceeded the conversion value of the 2 3/8% Notes due to the remaining imbedded conversion option of the holder. The trading price for the 2 3/8% Notes is dependent on current market conditions, the length of time until the first put / call date of the 2 3/8% Notes and general market liquidity, among other factors. Based on recent trading patterns of the 2 3/8% Notes, we do not currently expect any significant amount of the 2 3/8% Notes to covert over the next twelve months.

As noted above, subsequent to June 30, 2007, we completed two acquisitions in July and August 2007 for which the consideration included a total of $9.0 million of sellers' notes. These notes will be repayable in equal annual installments over a two year period beginning one year from the date of the closing of the respective transactions.

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. However, there is no assurance that we will be able to raise additional funds or be able to raise such funds on favorable terms.

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.

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.

The assessment of impairment on long-lived assets, including goodwill 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, which is other than a temporary decline in value, would be based

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.

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.

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.

Since the adoption of SFAS No. 123R, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An initial estimate of fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward and consistent vesting terms, option prices and option lives. Utilizing the Black Scholes model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change future assumptions for awards as we consider appropriate.

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 ~~March 31,~~June 30, 2007, we had floating rate obligations totaling approximately ~~$207.2~~$166.8 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 ~~March 31,~~June 30, 2007 levels, our consolidated interest expense would increase by a total of approximately ~~$2.1~~$1.7 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. In the past, we have hedged U.S. dollar balances and cash flows in our U.K. subsidiary; however, no active hedges exist as of ~~March 31,~~June 30, 2007. Results of operations have not been materially affected by foreign currency hedging activity.

information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to ~~allow disclosure as~~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.~~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 ~~March 31,~~June 30, 2007, 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.

PART II — OTHER INFORMATION

ITEM 1.Legal Proceedings

On February 18, 2005, we announced that we had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of our subsidiaries (the “Subsidiary”) to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in our previously reported fourth quarter 2004 results. We and independent counsel retained by our Audit Committee conducted separate investigations consisting of interviews and a thorough examination of the facts and circumstances in this matter. We voluntarily reported the results of our investigation to the Securities and Exchange Commission (the SEC) and fully cooperated with requests for information received from the SEC. On October 31, 2005, our counsel received a “Wells Notice” from the SEC staff indicating that it made a preliminary decision to recommend that the SEC bring a civil action against the Company alleging violations of provisions of the Securities and Exchange Act of 1934 (the Act) relating to the maintenance of books, records and internal accounting controls and procedures as set forth in Sections 13(b)(2)(A) and (B) of the Act. The Company reached a settlement agreement with the SEC on April 27, 2006. The Company consented to an Order by the SEC (the Order), without admitting or denying the findings in the Order, that required the Company to cease and desist from committing or causing violations of the “books and records” and “internal control provisions” of the laws of the Act. The settlement did not require the Company to pay a monetary penalty.

ITEM 1A.Risk Factors

Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2006 (the 2006 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 2006 Form ~~10-K.~~10-K except as detailed below.

Customer labor problems could adversely affect us

Our accommodations facilities serving oil sands development work in Northern Alberta, Canada house both union and non-union customer employees. If a union representing members employed by one or more of our customers threatens or engages in a strike, work stoppage or other slowdown, this could cause us to experience a disruption of our operations which could adversely affect our business, financial condition and results of operations.

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
January 1, 2007 – January 31, 2007 — — 1,824,432 $ 50,030,463

February 1, 2007 – February 28, 2007 — — 1,824,432 $ 50,030,463

March 1, 2007 - March 31, 2007 240,000 $ 30.40 2,064,432 $ 42,733,264 ⁽¹⁾

Total 240,000 $ 30.40 2,064,432 $ 42,733,264


					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, 2007 – April 30, 2007		—		—		2,064,432	$	42,733,264
May 1, 2007 – May 31, 2007		—		—		2,064,432	$	42,733,264
June 1, 2007 – June 30, 2007		—		—		2,064,432	$	42,733,264	⁽¹⁾
Total		—		—		2,064,432	$	42,733,264


(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.

ITEM 3.Defaults Upon Senior Securities

None

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

~~None~~The Company’s Annual Meeting of Stockholders was held on May 17, 2007 (1) to elect three Class III 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, 2007.

The Class III directors elected were Martin Lambert, Mark G. Papa and Stephen A. Wells. The number of affirmative votes and the number of votes withheld for the directors were:


Names	Number of Affirmative Votes		Number Withheld
Martin Lambert		34,281,914		10,991,096
Mark G. Papa		32,497,653		12,775,357
Stephen A. Wells		36,768,816		8,504,194

Following the annual meeting, Douglas E. Swanson, Cindy B. Taylor, S. James Nelson, Gary L. Rosenthal and William T. Van Kleef 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
45,235,040	26,215	11,756

ITEM 5.Other Information

None


~~Exhibit No.~~		~~Description~~
4.1	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to Oil States International, Inc.’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 SEC on March 30, 2001 (File No. 001-16337)).

4.3	—	First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to Oil States International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the SEC on March 13, 2003 (File No. 001-16337)).

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 International, Inc.’s Current Report on Form 8-K filed with the SEC on June 23, 2005 (File No. 001-16337)).

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 International, Inc.’s Current Report on Form 8-K filed with the SEC on June 23, 2005 (File No. 001-16337)).

4.6	—	Global Note representing $175,000,000 aggregate principal amount of 2³/₈% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 hereof) (incorporated by reference to Oil States International, Inc.’s Current Reports on Form 8-K filed with the SEC on June 23, 2005 and July 13, 2005, respectively (File No. 001-16337)).

10.25,*	—	Form of Executive Agreement between Oil States International, Inc. and named executive officer (Ron R. Green) effective May 17, 2007.

31.1*	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32.1***	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

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: May 2, 2007~~OIL STATES INTERNATIONAL, INC.
Date:August 2, 2007	By		/s/ BRADLEY J. DODSON
		Bradley J. Dodson
		Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)

							~~Bradley J. Dodson~~
Date:August 2, 2007	By						~~Vice President, Chief Financial Officer and~~
					~~Treasurer (Duly Authorized Officer and Principal~~
					~~Financial Officer)~~
				/s/ ROBERT W. HAMPTON
		~~Date: May 2, 2007~~Robert W. Hampton			By		~~/s/ ROBERT W. HAMPTON~~
						Senior Vice President — Accounting and Secretary (Duly Authorized Officer and Chief Accounting Officer)

INDEX TO EXHIBITS

~~Robert W. Hampton~~
Exhibit No.		Description

3.1	~~Senior Vice President~~ — ~~Accounting~~	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Oil States International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the SEC on March 30, 2001 (File No. 001-16337)).

3.2	~~Secretary (Duly Authorized Officer~~—	Amended and ~~Chief~~Restated Bylaws (incorporated by reference to Exhibit 3.2 to Oil States International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the SEC on March 30, 2001 (File No. 001-16337)).

3.3	~~Accounting Officer)~~—	Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to Oil States International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the SEC on March 30, 2001 (File No. 001-16337)).

~~EXHIBIT INDEX~~


4.1	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to Oil States International, Inc.’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 SEC on March 30, 2001 (File No. 001-16337)).

4.3	—	First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to Oil States International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the SEC on March 13, 2003 (File No. 001-16337)).

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 International, Inc.’s Current Report on Form 8-K filed with the SEC on June 23, 2005 (File No. 001-16337)).

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 International, Inc.’s Current Report on Form 8-K filed with the SEC on June 23, 2005 (File No. 001-16337)).

4.6	—	Global Note representing $175,000,000 aggregate principal amount of 2³/ 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 International, Inc.’s Current Reports on Form 8-K filed with the SEC on June 23, 2005 and July 13, 2005, respectively (File No. 001-16337)).

10.25,*	—	Form of Executive Agreement between Oil States International, Inc. and named executive officer (Ron R. Green) effective May 17, 2007.

31.1*	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32.1***	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.


Exhibit No.		Description

32.2***	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.


*		Filed herewith

**		Management contracts or compensatory plans or arrangements

***		Furnished ~~herewith.~~herewith


	Page No.
Part I — FINANCIAL INFORMATION

Item 1. Financial Statements:

Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Statements of Income for the Three and Six Month Periods Ended ~~March 31,~~June 30, 2007 and 2006		3
Consolidated Balance Sheets ~~– March 31,~~–June 30, 2007 (unaudited) and December 31, 2006		4
Unaudited Condensed Consolidated Statements of Cash Flows for the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2007 and 2006		5
Notes to Unaudited Condensed Consolidated Financial Statements		6 – 12

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		1213 – 1821

Item 3. Quantitative and Qualitative Disclosures About Market Risk		1821

Item 4. Controls and Procedures		~~18 - 19~~22

Part II — OTHER INFORMATION

Item 1. Legal Proceedings		1922

Item 1A. Risk Factors		1922

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities		2022 - 23

Item 3. Defaults Upon Senior Securities		2023

Item 4. Submission of Matters to a Vote of Security Holders		2023

Item 5. Other Information		2023

Item 6. Exhibits		2024

(a) Index of Exhibits		2024 – 2125

Signature Page		2226
Form of Executive Agreement - Ron R. Green
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to ~~18 U.S.C.~~ Section 1350
Certification of CFO Pursuant to ~~18 U.S.C.~~ Section 1350


	March 31,			December 31,			June 30,			December 31,
	2007			2006			2007			2006
	(Unaudited)						(Unaudited)
U.S. revolving credit facility, with available commitments up to $300 million and with an average interest rate of 6.3% for the three month period ended March 31, 2007	$	167,300		$	186,200
Canadian revolving credit facility, with available commitments up to $100 million and with an average interest rate of 5.3% for the three month period ended March 31, 2007		39,032			29,177
U.S. revolving credit facility, with available commitments up to $300 million and with an average interest rate of 6.4% for the six month period ended June 30, 2007							$	107,600		$	186,200
Canadian revolving credit facility, with available commitments up to $100 million and with an average interest rate of 5.3% for the six month period ended June 30, 2007								58,304			29,177
2 3/8% contingent convertible senior notes due 2025		175,000			175,000			175,000			175,000
Subordinated unsecured notes payable to sellers of businesses, interest ranging from 5% to 6%, maturing in 2007		5,435			6,689			1,385			6,689
Capital lease obligations and other debt		2,287			1,536			1,359			1,536

Total debt		389,054			398,602			343,648			398,602
Less: current maturities		(6,487	)		(6,873	)		(176,545	)		(6,873	)

Total long-term debt	$	382,567		$	391,729		$	167,103		$	391,729


Shares of common stock outstanding —– January 1, 2007	49,296,740

Shares issued upon exercise of stock options and vesting of stock awards	~~171,016~~566,480
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury	(~~6,549~~11,893	)
Repurchase of shares — held in treasury	(240,000	)

Shares of common stock outstanding ~~— March 31,~~–June 30, 2007	~~49,221,207~~49,611,327


	Average Rig Count for the						Average Rig Count for the
	Three Months Ended						Three Months Ended				Six Months Ended
	March 31,		December 31,		March 31,		June 30,		June 30,		June 30,		June 30,
	2007		2006		2006		2007		2006		2007		2006
U.S. Land		1,650		1,632		1,438		1,680		1,536		1,665		1,487
U.S. Offshore		83		87		81		77		96		80		89

Total U.S.		1,733		1,719		1,519
Total U.S								1,757		1,632		1,745		1,576
Canada (1)		532		440		665		139		282		336		474

Total North America		2,265		2,159		2,184		1,896		1,914		2,081		2,050


(1)		Subsequent to ~~the~~ March 1, 2006, the effective date of the sale of our workover services business (See Note 11), we have classified our equity interest in Boots & Coots and the notes receivable acquired in the transaction as “Drilling and ~~other “.~~other.”


(1)		Canadian rig count typically increases during the peak winter drilling season (December through March).