OIL STATES INTERNATIONAL, INC - Quarter Report: 2011 June (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2011


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: 001-16337

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. YES þ NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) YES þ NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):


Large Accelerated Filer þ		Accelerated Filer o		Non-Accelerated Filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO þ

The Registrant had 51,331,134 shares of common stock, par value $0.01, outstanding and 3,302,071 shares of treasury
stock as of July 29, 2011.

OIL STATES INTERNATIONAL, INC.

INDEX


	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 June 30, 2011 and 2010		3
Consolidated Balance Sheets — June 30, 2011 (unaudited) and December 31, 2010		4
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010		5
Notes to Unaudited Condensed Consolidated Financial Statements		6-15

Cautionary Statement Regarding Forward — Looking Statements		16

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16-26

Item 3. Quantitative and Qualitative Disclosures About Market Risk		26

Item 4. Controls and Procedures		26-27

Part II — OTHER INFORMATION

Item 1. Legal Proceedings		27

Item 1A. Risk Factors		27

Item 6. Exhibits		27

(a) Index of Exhibits		27-28

Signature Page		29
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION


ITEM 1.		*Financial Statements*

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)


	THREE MONTHS ENDED						SIX MONTHS ENDED
	JUNE 30,						JUNE 30,
	2011			2010			2011			2010
Revenues	$	820,317		$	594,532		$	1,580,758		$	1,126,877


Costs and expenses:
Cost of sales and services		616,778			469,482			1,191,176			875,992
Selling, general and administrative expenses		42,765			37,183			86,472			72,336
Depreciation and amortization expense		45,238			30,600			90,390			61,678
Other operating (income) expense		373			(486	)		2,781			(687	)

		705,154			536,779			1,370,819			1,009,319

Operating income		115,163			57,753			209,939			117,558

Interest expense, net of capitalized interest		(12,532	)		(3,500	)		(22,781	)		(6,971	)
Interest income		235			103			1,248			181
Other income/(expense)		490			(158	)		684			634

Income before income taxes		103,356			54,198			189,090			111,402
Income tax expense		(28,887	)		(16,590	)		(52,270	)		(33,379	)

Net income		74,469			37,608			136,820			78,023
Less: Net income attributable to noncontrolling interest		226			131			500			303

Net income attributable to Oil States International, Inc.	$	74,243		$	37,477		$	136,320		$	77,720


Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	1.45		$	0.75		$	2.67		$	1.55
Diluted	$	1.34		$	0.71		$	2.48		$	1.49

Weighted average number of common shares outstanding:
Basic		51,231			50,146			51,083			50,021
Diluted		55,270			52,455			55,061			52,188

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In Thousands)


	JUNE 30,			DECEMBER 31,
	2011			2010
	(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents	$	123,304		$	96,350
Accounts receivable, net		552,024			478,739
Inventories, net		592,679			501,435
Prepaid expenses and other current assets		29,350			23,480

Total current assets		1,297,357			1,100,004

Property, plant, and equipment, net		1,436,714			1,252,657
Goodwill, net		491,507			475,222
Other intangible assets, net		137,961			139,421
Other noncurrent assets		61,515			48,695

Total assets	$	3,425,054		$	3,015,999


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	315,672		$	304,739
Income taxes		7,429			4,604
Current portion of long-term debt and capitalized leases		192,556			181,175
Deferred revenue		54,598			60,847
Other current liabilities		6,541			2,810

Total current liabilities		576,796			554,175

Long-term debt and capitalized leases		884,750			731,732
Deferred income taxes		90,774			81,198
Other noncurrent liabilities		21,012			19,961

Total liabilities		1,573,332			1,387,066

Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock		546			541
Additional paid-in capital		531,618			508,429
Retained earnings		1,264,453			1,128,133
Accumulated other comprehensive income		150,264			84,549
Treasury stock		(96,201	)		(93,746	)

Total Oil States International, Inc. stockholders’ equity		1,850,680			1,627,906

Noncontrolling interest		1,042			1,027

Total stockholders’ equity		1,851,722			1,628,933

Total liabilities and stockholders’ equity	$	3,425,054		$	3,015,999

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)


	SIX MONTHS
	ENDED JUNE 30,
	2011			2010
Cash flows from operating activities:
Net income	$	136,820		$	78,023
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		90,390			61,678
Deferred income tax provision (benefit)		10,788			(4,909	)
Excess tax benefits from share-based payment arrangements		(6,198	)		(985	)
Non-cash compensation charge		7,198			6,848
Accretion of debt discount		3,823			3,560
Amortization of deferred financing costs		2,914			526
Other, net		(889	)		(1,748	)
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		(66,481	)		561
Inventories		(88,781	)		(51,066	)
Accounts payable and accrued liabilities		7,802			26,840
Taxes payable		9,977			(5,344	)
Other current assets and liabilities, net		(10,728	)		(28,129	)

Net cash flows provided by operating activities		96,635			85,855

Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		(212	)		—
Capital expenditures, including capitalized interest		(230,253	)		(76,077	)
Other, net		(850	)		1,853

Net cash flows used in investing activities		(231,315	)		(74,224	)

Cash flows from financing activities:
Revolving credit borrowings and (repayments), net		(428,682	)		—
6 ¹/2% senior notes issued		600,000			—
Term loan repayments		(7,494	)		—
Debt and capital lease repayments		(587	)		(255	)
Issuance of common stock from share-based payment arrangements		9,792			7,288
Excess tax benefits from share-based payment arrangements		6,198			985
Payment of financing costs		(12,640	)		—
Other, net		(2,456	)		(1,363	)

Net cash flows provided by financing activities		164,131			6,655

Effect of exchange rate changes on cash		(2,399	)		(5,005	)

Net increase in cash and cash equivalents from continuing operations		27,052			13,281
Net cash used in discontinued operations — operating activities		(98	)		(75	)
Cash and cash equivalents, beginning of period		96,350			89,742


Cash and cash equivalents, end of period	$	123,304		$	102,948

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

The accompanying unaudited condensed 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 (the 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.

The preparation of consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. 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.

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, 2010 (the 2010 Form 10-K).

2. RECENT ACCOUNTING PRONOUNCEMENTS

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 that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

In June 2011, the FASB issued amendments to disclosure requirements for the presentation of comprehensive income. This guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments require that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. The amendments should be applied retrospectively. For public entities, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is permitted, because compliance with the amendments is already permitted. The amendments do not require any transition disclosures.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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


	JUNE 30,			DECEMBER 31,
	2011			2010
Accounts receivable, net:
Trade	$	426,712		$	365,988
Unbilled revenue		124,038			113,389
Other		4,147			3,462

Total accounts receivable		554,897			482,839
Allowance for doubtful accounts		(2,873	)		(4,100	)

	$	552,024		$	478,739


	JUNE 30,			DECEMBER 31,
	2011			2010
Inventories, net:
Tubular goods	$	377,845		$	332,720
Other finished goods and purchased products		78,324			71,266
Work in process		56,401			45,662
Raw materials		89,224			60,241

Total inventories		601,794			509,889
Allowance for obsolescence		(9,115	)		(8,454	)

	$	592,679		$	501,435


	ESTIMATED	JUNE 30,			DECEMBER 31,
	USEFUL LIFE	2011			2010
Property, plant and equipment, net:
Land		$	46,424		$	43,411
Buildings and leasehold improvements	1-40 years		209,074			193,617
Machinery and equipment	2-29 years		330,657			311,217
Accommodations assets	3-15 years		952,413			840,002
Rental tools	4-10 years		179,789			166,245
Office furniture and equipment	1-10 years		38,946			36,325
Vehicles	2-10 years		87,913			82,783
Construction in progress			204,308			113,773

Total property, plant and equipment			2,049,524			1,787,373
Accumulated depreciation			(612,810	)		(534,716	)

		$	1,436,714		$	1,252,657


	JUNE 30,		DECEMBER 31,
	2011		2010
Accounts payable and accrued liabilities:
Trade accounts payable	$	241,479	$	224,543
Accrued compensation		38,421		47,760
Insurance liabilities		9,708		8,615
Accrued taxes, other than income taxes		8,132		4,887
Liabilities related to discontinued operations		2,170		2,268
Other		15,762		16,666

	$	315,672	$	304,739

4. EARNINGS PER SHARE

The calculation of earnings per share attributable to the Company is presented below (in thousands, except per share amounts):


	THREE MONTHS ENDED				SIX MONTHS ENDED
	JUNE 30,				JUNE 30,
	2011		2010		2011		2010
Basic earnings per share:
Net income attributable to Oil States International, Inc.	$	74,243	$	37,477	$	136,320	$	77,720

Weighted average number of shares outstanding		51,231		50,146		51,083		50,021

Basic earnings per share	$	1.45	$	0.75	$	2.67	$	1.55

Diluted earnings per share:
Net income attributable to Oil States International, Inc.	$	74,243	$	37,477	$	136,320	$	77,720

Weighted average number of shares outstanding		51,231		50,146		51,083		50,021
Effect of dilutive securities:
Options on common stock		679		631		703		615
2 3/8% Convertible Senior Subordinated Notes		3,200		1,507		3,094		1,364
Restricted stock awards and other		160		171		181		188

Total shares and dilutive securities		55,270		52,455		55,061		52,188

Diluted earnings per share	$	1.34	$	0.71	$	2.48	$	1.49

Our calculation of diluted earnings per share for the three and six months ended June 30, 2011 excludes 178,855 shares and 177,702 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, 2010 excludes 466,315 shares and 434,891 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards due to their antidilutive effect.

5. BUSINESS ACQUISITIONS AND GOODWILL

On December 30, 2010, we acquired all of the ordinary shares of The MAC Services Group Limited (The MAC), through a Scheme of Arrangement (the Scheme) under the Corporations Act of Australia. The MAC is headquartered in Sydney, Australia and supplies accommodations services to the Australian natural resources market. Under the terms of the Scheme, each shareholder of The MAC received $3.95 (A$3.90) per share in cash. This price represents a total purchase price of $638 million, net of cash acquired plus debt assumed of $87 million. The Company funded the acquisition with cash on hand and borrowings available under our five-year, $1.05 billion senior secured bank facilities. The MAC’s operations have been included as part of our accommodations segment beginning in 2011.

The following unaudited pro forma supplemental financial information presents the consolidated results of operations of the Company and The MAC as if the acquisition of The MAC had occurred on January 1, 2010. The Company has adjusted historical financial information to give effect to pro forma items that are directly attributable to the acquisition and are expected to have a continuing impact on the consolidated results. These items include adjustments to record the incremental amortization and depreciation expense related to the increase in fair values of the acquired assets, interest expense related to borrowings under the Company’s senior credit facilities to fund the acquisition and to reclassify certain items to conform to the Company’s financial reporting presentation. The unaudited pro forma results do not purport to be indicative of the results of operations had the transaction occurred on the date indicated or of future results for the combined entities (in thousands, except per share data):


	Three Months Ended		Six Months Ended
	June 30, 2010		June 30, 2010
	(Unaudited)
Revenues	$	621,203	$	1,178,856
Net income attributable to Oil States International, Inc.		37,828		77,571
Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	0.75	$	1.55
Diluted	$	0.72	$	1.49

Included in the pro forma results above for the three and six months ended June 30, 2010 are (1) depreciation of the increased recorded value of property, plant and equipment acquired as part of The MAC, totaling $2.2 million and $4.4 million, respectively, net of tax, or $0.04 and $0.08 per diluted share, respectively; (2) amortization expense for intangibles acquired as part of the purchase of The MAC, totaling $1.5 million and $3.0 million, respectively, net of tax, or $0.03 and $0.06 per diluted share, respectively; and (3) interest expense of $2.7 million and $5.4 million, respectively, net of tax, or $0.05 and $0.10 per diluted share, respectively.

On December 20, 2010, we also acquired all of the operating assets of Mountain West Oilfield Service and Supplies, Inc. and Ufford Leasing LLC (Mountain West) for total consideration of $47.1 million and estimated contingent consideration of $4.0 million. Headquartered in Vernal, Utah, with operations in the Rockies and the Bakken Shale region, Mountain West provides remote site workforce accommodations to the oil and gas industry. Mountain West has been included in the accommodations segment since its date of acquisition.

On October 5, 2010, we purchased all of the equity of Acute Technological Services, Inc. (Acute) for total consideration of $30.2 million. Headquartered in Houston, Texas and with additional operations in Brazil, Acute provides metallurgical and welding innovations to the oil and gas industry in support of critical, complex subsea component manufacturing and deepwater riser fabrication on a global basis. Acute has been included in the offshore products segment since its date of acquisition.

During the three and six months ended June 30, 2011, the Company recognized $0.3 million and $1.4 million, respectively, of costs in connection with the acquisitions that were expensed.

Changes in the carrying amount of goodwill for the six month period ended June 30, 2011 are as follows (in thousands):


	Well Site Services
				Drilling
	Rental			and								Offshore			Tubular
	Tools			Other			Subtotal			Accommodations		Products			Services			Total
Balance as of December 31, 2009

Goodwill	$	169,311		$	22,767		$	192,078		$	58,358	$	85,599		$	62,863		$	398,898
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—		—			(62,863	)		(180,158	)

		74,783			—			74,783			58,358		85,599			—			218,740
Goodwill acquired		—			—			—			239,080		15,242			—			254,322
Foreign currency translation and other changes		723			—			723			1,624		(187	)		—			2,160

		75,506			—			75,506			299,062		100,654			—			475,222


Balance as of December 31, 2010
Goodwill		170,034			22,767			192,801			299,062		100,654			62,863			655,380
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—		—			(62,863	)		(180,158	)

		75,506			—			75,506			299,062		100,654			—			475,222
Goodwill acquired		—			—			—			503		198			—			701
Foreign currency translation and other changes		457			—			457			14,973		154			—			15,584

		75,963			—			75,963			314,538		101,006			—			491,507


Balance as of June 30, 2011
Goodwill		170,491			22,767			193,258			314,538		101,006			62,863			671,665
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—		—			(62,863	)		(180,158	)

	$	75,963		$	—		$	75,963		$	314,538	$	101,006		$	—		$	491,507

6. DEBT

As of June 30, 2011 and December 31, 2010, long-term debt consisted of the following (in thousands):


	June 30,		December 31,
	2011		2010
	(Unaudited)
U.S. revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million and with an average interest rate of 2.8% for the six month period ended June 30, 2011	$	—	$	345,600
U.S. term loan, which matures December 10, 2015, of $200 million; 1.25% of aggregate principal repayable per quarter in 2011, 2.5% per quarter thereafter; average interest rate of 2.6% for the six month period ended June 30, 2011		195,000		200,000
Canadian revolving credit facility, which matures December 10, 2015, with available commitments up to $250 million and with an average interest rate of 3.9% for the six month period ended June 30, 2011		—		62,538
Canadian term loan, which matures December 10, 2015, of $100 million; 1.25% of aggregate principal repayable per quarter in 2011, 2.5% per quarter thereafter; average interest rate of 3.7% for the six month period ended June 30, 2011		101,524		100,955
Australian revolving credit facility, which matures October 15, 2013, of A$75 million		—		25,305
6 1/2% senior unsecured notes — due June 2019		600,000		—
23/8% contingent convertible senior subordinated notes, net — due 2025		166,931		163,108
Subordinated unsecured notes payable to sellers of businesses, fixed interest rate of 6%, which mature in 2012		4,000		4,000
Capital lease obligations and other debt		9,851		11,401

Total debt		1,077,306		912,907
Less: Current maturities		192,556		181,175

Total long-term debt and capitalized leases	$	884,750	$	731,732

On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% senior unsecured notes (6 1/2% Notes) due 2019 through a private placement to qualified institutional buyers.

The 6 1/2% Notes are senior unsecured obligations of the Company and guaranteed by our U.S. subsidiaries (the Guarantors) which bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.500% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The percentages of the principal amount are as follows:


Twelve Month Period Beginning	% of Principal
June 1,	Amount
2014		104.875	%
2015		103.250	%
2016		101.625	%
2017		100.000	%

In connection with the note offering, the Company, the Guarantors of the 6 1/2% Notes and the initial purchasers entered into a registration rights agreement at the closing of the offering. Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they will, subject to certain exceptions, use commercially reasonable efforts to file with the Commission and cause to become effective a registration statement relating to an offer to exchange the 6 1/2% Notes for an issue of Commission-registered 6 1/2% Notes with identical terms. If the exchange offer is not completed on or before the date that is 365 days after the closing date of this offering (the Target Registration Date), then the Company agreed to pay each holder of the 6 1/2% Notes liquidated damages in the form of additional interest in an amount equal to 0.25% per annum of the principal amount of notes held by such holder, with respect to the first 90 days after the Target Registration Date (which rate shall be increased by an additional 0.25% per annum for each subsequent 90-day period that such liquidated damages continue to accrue), in each case until the exchange offer is completed or the shelf registration statement is declared effective or is no longer required to be effective; provided, however, that at no time will the amount of liquidated damages accruing exceed in the aggregate 0.5% per annum. The maximum additional interest potentially payable pursuant to this provision would be $2.6 million.

The Company utilized approximately $515 million of the net proceeds of the 6 1/2% Notes offering in June 2011 to repay borrowings under its senior secured credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.

As of June 30, 2011, we classified the $175.0 million principal amount of our 2 3/8% Contingent Convertible Senior Subordinated Notes (2 3/8% Notes), net of unamortized discount, as a current liability because certain contingent conversion thresholds based on the Company’s stock price were met at that date and, as a result, 2 3/8% Note holders could present their notes for conversion during the quarter following the June 30, 2011 measurement date. If a 2 3/8% Note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they will receive cash up to $1,000 for each 2 3/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% Notes of 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. 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.

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


	June 30, 2011		December 31, 2010
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		8,069		11,892

Net carrying amount of the liability component	$	166,931	$	163,108

Unamortized Discount — 2 3/8% Notes

The effective interest rate is 7.17% for our 2 3/8% Notes. Interest expense on the 2 3/8% Notes, excluding amortization of debt issue costs, was as follows (in thousands):


	Three months ended				Six months ended
	June 30,				June 30,
	2011		2010		2011		2010
Interest expense	$	2,968	$	2,835	$	5,901	$	5,638


	June 30, 2011
Remaining period over which discount will be amortized	1.0 years
Conversion price	$	31.75
Number of shares to be delivered upon conversion (1)		3,321,836
Conversion value in excess of principal amount (in thousands) (1)	$	265,448
Derivative transactions entered into in connection with the convertible notes	None


(1)		Calculation is based on the Company’s June 30, 2011 closing stock price of $79.91.

On July 13, 2011, The MAC entered into a A$150 million revolving loan facility governed by a Facility Agreement (the Facility Agreement) between The MAC and National Australia Bank Limited and guaranteed by the Company. The Facility Agreement amends The MAC’s existing A$75 million revolving loan facility on substantially the same terms, including the maturity date of the Facility Agreement of November 30, 2013. As of June 30, 2011, there were no borrowings outstanding under the Australian facility.

The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, and debt instruments. The Company believes that the carrying values of these instruments, other than our 2 3/8% Notes, our 6 1/2% Notes and our debt under our revolving credit facilities, on the accompanying consolidated balance sheets approximate their fair values.

The fair values of our 2 3/8% and 6 1/2% Notes are estimated based on quoted prices in active markets (Level 1 fair value measurements). The carrying and fair values of these notes were as follows (in thousands):


				June 30, 2011				December 31, 2010
	Interest			Carrying		Fair		Carrying		Fair
	Rate			Value		Value		Value		Value
6 1/2% Notes
Principal amount due 2019		6 1/2	%	$	600,000	$	606,750	$	—	$	—

2 3/8% Notes
Principal amount due 2025		2 3/8	%	$	175,000	$	440,767	$	175,000	$	354,057
Less: unamortized discount					8,069		—		11,892		—

Net value				$	166,931	$	440,767	$	163,108	$	354,057

As of June 30, 2011, the Company had approximately $123.3 million of cash and cash equivalents and $727.4 million of the Company’s $1.0 billion U.S. and Canadian credit facilities available for future financing needs. The Company also had availability totaling A$75 million under its Australian credit facility. As of June 30, 2011, we had $18.5 million of outstanding letters of credit under these credit facilities.

Interest expense on the condensed consolidated statements of income is net of capitalized interest of $1.0 million and $2.5 million, respectively, for the three and six months ended June 30, 2011 and less than $0.1 million for the same periods in 2010.

7. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING

Comprehensive income for the three and six months ended June 30, 2011 and 2010 was as follows (in thousands):


	THREE MONTHS						SIX MONTHS
	ENDED JUNE 30,						ENDED JUNE 30,
	2011			2010			2011			2010
Net income	$	74,469		$	37,608		$	136,820		$	78,023
Other comprehensive income:
Foreign currency translation adjustment		35,052			(23,788	)		65,715			(15,203	)

Total other comprehensive income/(loss)		35,052			(23,788	)		65,715			(15,203	)

Comprehensive income		109,521			13,820			202,535			62,820
Comprehensive income attributable to noncontrolling interest		(226	)		(131	)		(500	)		(303	)

Comprehensive income attributable to Oil States International, Inc.	$	109,295		$	13,689		$	202,035		$	62,517

The increases in other comprehensive income in the three and six months ended June 30, 2011 compared to the same periods in 2010 were due primarily to the translation of our net Canadian and Australian accommodations assets at varying exchange rates.

Stock Activity


Shares of common stock outstanding — January 1, 2011	50,838,863

Shares issued upon exercise of stock options and vesting of stock awards	510,685
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury	(32,923	)

Shares of common stock outstanding — June 30, 2011	51,316,625

8. STOCK BASED COMPENSATION

During the first six months of 2011, we granted restricted stock awards totaling 210,134 shares valued at a total of $15.8 million. Of the restricted stock awards granted in the first six months of 2011, a total of 193,550 awards vest in four equal annual installments starting in February 2012. A total of 184,700 stock options with a ten-year term were awarded in the six months ended June 30, 2011 with an average exercise price of $75.37 and will vest in four equal annual installments starting in February 2012.

Stock based compensation pre-tax expense recognized in the six month periods ended June 30, 2011 and 2010 totaled $7.2 million and $6.8 million, or $0.10 and $0.10 per diluted share after tax, respectively. Stock based compensation pre-tax expense recognized in the three month periods ended June 30, 2011 and 2010 totaled $3.8 million and $3.1 million, or $0.05 and $0.04 per diluted share after tax, respectively. The total fair value of restricted stock awards that vested during the six months ended June 30, 2011 and 2010 was $12.2 million and $7.4 million, respectively. At June 30, 2011, $31.1 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.

9. INCOME TAXES

Income tax expense for interim periods is based on estimates of the effective tax rate for the entire fiscal year. The Company’s income tax provision for the three and six months ended June 30, 2011 totaled $28.9 million, or 27.9% of pretax income, and $52.3 million, or 27.6% of pretax income, respectively, compared to $16.6 million, or 30.6% of pretax income, and $33.4 million, or 30.0% of pretax income, respectively, for the three and six months ended June 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

10. SEGMENT AND RELATED INFORMATION

In accordance with current accounting standards regarding disclosures about segments of an enterprise and related information, the Company has identified the following reportable segments: well site services, accommodations, offshore products and tubular services. The Company’s reportable segments represent 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 accommodations segment supporting traditional oil and natural gas drilling activities are somewhat seasonal with increased activity occurring in the winter drilling season.

Financial information by business segment for each of the three and six months ended June 30, 2011 and 2010 is summarized in the following table (in thousands):


								Equity in
	Revenues from		Depreciation					income/(loss) of
	unaffiliated		and		Operating			unconsolidated			Capital
Three months ended June 30, 2011	customers		amortization		income (loss)			affiliates			expenditures		Total assets
Well site services —
Rental tools	$	112,658	$	10,299	$	25,103		$	—		$	18,654	$	410,370
Drilling services		40,998		4,806		6,370			—			5,754		116,672

Total well site services		153,656		15,105		31,473			—			24,408		527,042
Accommodations		202,943		26,195		57,750			(1	)		106,873		1,700,385
Offshore products		131,742		3,358		18,770			(228	)		3,519		588,472
Tubular services		331,976		377		16,956			231			2,780		521,675
Corporate and eliminations		—		203		(9,786	)		—			64		87,480

Total	$	820,317	$	45,238	$	115,163		$	2		$	137,644	$	3,425,054


								Equity in
	Revenues from		Depreciation					income/(loss) of
	unaffiliated		and		Operating			unconsolidated		Capital
Three months ended June 30, 2010	customers		amortization		income (loss)			affiliates		expenditures		Total assets
Well site services —
Rental tools	$	79,119	$	10,405	$	10,395		$	—	$	10,446	$	351,981
Drilling services		34,137		6,198		(1,070	)		—		3,546		114,071

Total well site services		113,256		16,603		9,325			—		13,992		466,052
Accommodations		121,956		10,707		31,300			—		20,029		615,982
Offshore products		106,005		2,770		16,087			—		1,942		484,852
Tubular services		253,315		341		9,297			34		2,752		405,654
Corporate and eliminations		—		179		(8,256	)		—		188		22,473

Total	$	594,532	$	30,600	$	57,753		$	34	$	38,903	$	1,995,013


								Equity in
	Revenues from		Depreciation					income/(loss) of
	unaffiliated		and		Operating			unconsolidated			Capital
Six months ended June 30, 2011	customers		amortization		income (loss)			affiliates			expenditures		Total assets
Well site services —
Rental tools	$	220,189	$	20,095	$	49,493		$	—		$	35,495	$	410,370
Drilling services		74,103		9,739		8,605			—			12,922		116,672

Total well site services		294,292		29,834		58,098			—			48,417		527,042
Accommodations		400,041		52,748		106,723			2			168,915		1,700,385
Offshore products		260,184		6,692		35,520			(228	)		7,574		588,472
Tubular services		626,241		728		30,002			279			5,151		521,675
Corporate and eliminations		—		388		(20,404	)		—			196		87,480

Total	$	1,580,758	$	90,390	$	209,939		$	53		$	230,253	$	3,425,054


								Equity in
	Revenues from		Depreciation					income/(loss) of
	unaffiliated		and		Operating			unconsolidated		Capital
Six months ended June 30, 2010	customers		amortization		income (loss)			affiliates		expenditures		Total assets
Well site services —
Rental tools	$	146,622	$	20,915	$	14,772		$	—	$	17,026	$	351,981
Drilling services		64,538		12,862		(3,052	)		—		4,537		114,071

Total well site services		211,160		33,777		11,720			—		21,563		466,052
Accommodations		267,489		21,283		78,668			—		45,441		615,982
Offshore products		208,998		5,575		28,708			—		5,980		484,852
Tubular services		439,230		685		15,512			64		2,843		405,654
Corporate and eliminations		—		358		(17,050	)		—		250		22,473

Total	$	1,126,877	$	61,678	$	117,558		$	64	$	76,077	$	1,995,013

11. 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.

Cautionary Statement Regarding Forward-Looking Statements

This quarterly report on Form 10-Q contains “certain forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Some of the information in the quarterly report may contain “forward-looking statements.” The “forward-looking statements” can be identified by the use of forward-looking terminology including “may,” “expect,” “anticipate,” “estimate,” “continue,” “believe,” or other similar words. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to “Part I, Item 1A. 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 2010 Form 10-K filed with the Commission on February 22, 2011. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations and are not guarantees of future performance. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.

In addition, in certain places in this quarterly report, we refer to reports published by third parties that purport to describe trends or developments in the energy industry. The Company does so for the convenience of our stockholders and in an effort to provide information available in the market that will assist the Company’s investors in a better understanding of the market environment in which the Company operates. However, the Company specifically disclaims any responsibility for the accuracy and completeness of such information and undertakes no obligation to update such information.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis together with our condensed 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 accommodations, offshore products, well site services and tubular services business segments. In our accommodations segment, we also support the mining industry in Australia. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers’ willingness to spend capital on the exploration for and development of oil, natural gas, coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, demand for our products and services is highly sensitive to current and expected commodity prices. Activity for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices. In contrast, activity for our well site services and tubular services segments responds more rapidly to shorter-term movements in oil and natural gas prices and, specifically, changes in North American drilling and completion activity. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the U.S. and internationally.

Our Business Segments

Our accommodations business is predominantly located in northern Alberta, Canada and Queensland, Australia and derives most of its business from resource companies who are developing and producing oil sands and coal resources and, to a lesser extent, other mineral resources. A significant portion of our accommodations segment revenues is generated by our large-scale lodge and village facilities. Where traditional accommodations and infrastructure are not accessible or cost effective, our semi-permanent lodge and village facilities provide comprehensive accommodations services similar to those found in an urban hotel. We typically contract our facilities to our customers on a fee per day covering lodging and meals that is based on the duration of their needs which can range

from several months to several years. In addition, we provide shorter-term remote site accommodations in smaller configurations utilizing our modular, mobile camp assets.

Generally, our customers for oil sands and mining accommodations are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of 10 to 30 years and, consequently, these investments are dependent on those customers’ longer-term view of commodity demand and prices. Oil sands development activity has increased in the past year and has had a positive impact on our accommodations segment. Recent announcements have led to extensions of existing accommodations contracts and incremental accommodations contracts for us in Canada. In addition, several major oil companies and national oil companies have acquired oil sands leases over the past twelve months that should bode well for future oil sands investment and, as a result, demand for oil sands accommodations. Our Australian accommodations business is significantly influenced by increased metallurgical coal demand, especially from China and India. We are expanding our Australian accommodations manufacturing capacity to meet increasing demand and prospects for increased customer room demands are likely.

Another factor that influences the financial results for our accommodations segment is the exchange rate between the U.S. dollar and the Canadian dollar and, to a lesser extent, the exchange rate between the U.S. dollar and the Australian dollar. Our accommodations segment has derived a majority of its revenues and operating income in Canada denominated in Canadian dollars. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. For the first six months of 2011, the Canadian dollar was valued at an average exchange rate of U.S. $1.02 compared to U.S. $0.97 for the first six months of 2010, an increase of 5%. This strengthening of the Canadian dollar had a positive impact on the translation of earnings generated from our Canadian subsidiaries and, therefore, the financial results of our accommodations segment.

Our offshore products segment is also influenced significantly by our customers’ longer term outlook for energy prices and provides highly engineered products for offshore oil and natural gas drilling and production systems and facilities. Sales of our offshore products and services depend primarily upon development of infrastructure for 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 spending, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices.

New order activity in our offshore products segment was limited beginning in the fourth quarter of 2008 and continued to decline throughout 2009 due to project postponements, cancellations and deferrals by customers as a result of the global economic recession and reduced oil prices. This reduction in order activity led to declines in our offshore products backlog and decreased revenues and profits in the first six months of 2010. With the improvement in oil prices over the last two years along with the improved outlook for long-term oil demand, we began experiencing increased bidding and quoting activity for our offshore products in the second half of 2010 and continuing throughout the first six months of 2011. As a result of this increased activity, our backlog in offshore products has increased from $215.7 million as of June 30, 2010 to $518.6 million as of June 30, 2011, a 140% increase.

Our well site services and tubular services segments are significantly influenced by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada. Over the past several years, this activity has been primarily driven by spending for natural gas exploration and production, particularly in the shale play regions of the U.S. using horizontal drilling and completion techniques. However, with the rise in oil prices, lower natural gas prices and the advancement of horizontal drilling and completion techniques, activity in North America is beginning to shift to a greater proportion of oil and liquids rich gas drilling. The oil rig count in the U.S. now totals approximately 1,000 rigs, the highest count in over 20 years, comprising approximately 53% of total U.S. drilling activity.

In our well site services segment, we provide rental tools and land drilling services. Demand for our drilling services is driven by land drilling activity in West Texas, where we primarily drill oil wells, and in the Rocky Mountains area in the U.S., where we drill both oil and natural gas wells. Our rental tools business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the rental tools business is dependant primarily upon the level and complexity of drilling, completion and workover activity throughout North America.

Through our tubular services segment, we distribute a broad range of casing and tubing used in the drilling and completion of oil and natural gas wells primarily in North America. Accordingly, sales and gross margins in our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled, movements in global steel input prices and the overall industry level of oil country tubular goods (OCTG) inventory and pricing. Historically, tubular services’ gross margin generally expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices.

Demand for our tubular services, land drilling and rental tool businesses is highly correlated to changes in the drilling rig count in the U.S. and, to a much lesser extent, Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.


	Average Drilling Rig Count for
	Three Months Ended				Six Months Ended
	June 30,		June 30,		June 30,		June 30,
	2011		2010		2011		2010
U.S. Land		1,799		1,469		1,744		1,385
U.S. Offshore		31		39		29		42

Total U.S.		1,830		1,508		1,773		1,427
Canada		188		166		387		318

Total North America		2,018		1,674		2,160		1,745

The average North American rig count for the three months ended June 30, 2011 increased by 344 rigs, or 21%, compared to the three months ended June 30, 2010 largely due to growth in the U.S. land rig count.

Steel and steel input prices influence the pricing decisions of our OCTG suppliers, thereby influencing the pricing and margins of our tubular services segment. OCTG marketplace supply and demand has become more balanced recently compared to the 2008 to 2009 period. Increased supplies of OCTG have met the increased demand caused by expanded drilling activity. Recent global steel prices have increased affecting the raw material costs of our OCTG suppliers. To date, we have incurred modest OCTG price increases, which we have been able to pass through to our customers. The OCTG Situation Report indicates that industry OCTG inventory levels peaked in the first quarter of 2009 at approximately twenty months’ supply on the ground and have trended down to approximately five to six months’ supply currently, which is considered closer to a normalized level measured against historical levels.

During 2010, U.S. mills began increasing production and imports of steel have increased in the first part of 2011, particularly goods imported from Canada and Korea followed by India, Mexico and Japan. We believe this increase in supply has been in response to the approximately 21% year-over-year increase in the drilling rig count in the U.S.

Other Factors that Influence our Business

While global demand for oil and natural gas are significant factors influencing our business generally, certain other factors also influence our business, such as the pace of worldwide economic growth and recovery in U.S. Gulf of Mexico drilling following the government imposed drilling moratorium.

We have witnessed unprecedented events in the U.S. Gulf of Mexico as a result of the Macondo well incident and resultant oil spill. As a result of the incident, in May 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, of the U.S. Department of the Interior implemented a moratorium on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico that effectively shut down new deepwater drilling activities in 2010. The moratorium was lifted during October 2010. However, the BOEMRE issued Notices to Lessees and Operators (NTLs), implemented additional safety and certification requirements applicable to plans for drilling activities in the U.S. waters, imposed additional requirements with respect to development and production activities in the U.S. waters, and delayed the approval of applications to drill in both deepwater and shallow-water areas. Despite the rescission of the moratorium, offshore drilling activity is being delayed by adjustments in operating procedures, compliance certifications, and lead times for permits and inspections, as a result of changes in the regulatory environment. In addition, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production. Uncertainties and delays caused by the new regulatory environment have and are expected to continue to have an overall negative effect on Gulf of Mexico drilling activity and, to a certain extent, the financial results of all of our business segments.

We continue to monitor the global economy, the demand for crude oil, coal and natural gas prices and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. We currently expect that our 2011 capital expenditures will total approximately $650 million compared to 2010 capital expenditures of $182 million. Our 2011 capital expenditures include funding to expand several of our Canadian and Australian accommodations facilities, to add incremental equipment in our rental tools segment, to increase our fleet of modular, mobile camp assets in Canada and the U.S. and to complete projects in progress at December 31, 2010, including (i) the construction of the Henday Lodge accommodations facility in the Canadian oil sands, (ii) continued expansion of our Wapasu Creek, Beaver River and Athabasca Lodge accommodations facilities in the Canadian oil sands and (iii) ongoing maintenance capital requirements. In our well site services segment, we continue to monitor industry capacity additions and will 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.

Consolidated Results of Operations (in millions)


	THREE MONTHS ENDED											SIX MONTHS ENDED
	JUNE 30,											JUNE 30,
							Variance											Variance
							2011 vs. 2010											2011 vs. 2010
	2011			2010			$		%			2011			2010			$		%
Revenues
Well site services -
Rental tools	$	112.7		$	79.1		$	33.6		42	%	$	220.2		$	146.6		$	73.6		50	%
Drilling services		41.0			34.2			6.8		20	%		74.1			64.6			9.5		15	%

Total well site services		153.7			113.3			40.4		36	%		294.3			211.2			83.1		39	%
Accommodations		202.9			121.9			81.0		66	%		400.1			267.5			132.6		50	%
Offshore products		131.7			106.0			25.7		24	%		260.2			209.0			51.2		24	%
Tubular services		332.0			253.3			78.7		31	%		626.2			439.2			187.0		43	%

Total	$	820.3		$	594.5		$	225.8		38	%	$	1,580.8		$	1,126.9		$	453.9		40	%

Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Rental tools	$	70.4		$	50.0		$	20.4		41	%	$	137.7		$	95.3		$	42.4		44	%
Drilling services		29.2			28.4			0.8		3	%		54.4			53.4			1.0		2	%

Total well site services		99.6			78.4			21.2		27	%		192.1			148.7			43.4		29	%
Accommodations		108.5			73.2			35.3		48	%		216.8			155.0			61.8		40	%
Offshore products		98.2			77.7			20.5		26	%		194.8			155.9			38.9		25	%
Tubular services		310.5			240.2			70.3		29	%		587.5			416.4			171.1		41	%

Total	$	616.8		$	469.5		$	147.3		31	%	$	1,191.2		$	876.0		$	315.2		36	%

Gross margin
Well site services -
Rental tools	$	42.3		$	29.1		$	13.2		45	%	$	82.5		$	51.3		$	31.2		61	%
Drilling services		11.8			5.8			6.0		103	%		19.7			11.2			8.5		76	%

Total well site services		54.1			34.9			19.2		55	%		102.2			62.5			39.7		64	%
Accommodations		94.4			48.7			45.7		94	%		183.3			112.5			70.8		63	%
Offshore products		33.5			28.3			5.2		18	%		65.4			53.1			12.3		23	%
Tubular services		21.5			13.1			8.4		64	%		38.7			22.8			15.9		70	%

Total	$	203.5		$	125.0		$	78.5		63	%	$	389.6		$	250.9		$	138.7		55	%

Gross margin as a percentage of revenues
Well site services -
Rental tools		38	%		37	%							37	%		35	%
Drilling services		29	%		17	%							27	%		17	%
Total well site services		35	%		31	%							35	%		30	%
Accommodations		47	%		40	%							46	%		42	%
Offshore products		25	%		27	%							25	%		25	%
Tubular services		6	%		5	%							6	%		5	%
Total		25	%		21	%							25	%		22	%

THREE MONTHS ENDED JUNE 30, 2011 COMPARED TO THREE MONTHS ENDED JUNE 30, 2010

We reported net income attributable to Oil States International, Inc. for the quarter ended June 30, 2011 of $74.2 million, or $1.34 per diluted share. These results compare to net income of $37.5 million, or $0.71 per diluted share, reported for the quarter ended June 30, 2010.

Revenues. Consolidated revenues increased $225.8 million, or 38%, in the second quarter of 2011 compared to the second quarter of 2010.

Our well site services segment revenues increased $40.4 million, or 36%, in the second quarter of 2011 compared to the second quarter of 2010. This increase was primarily due to significantly increased rental tools revenues. Our rental tools revenues increased $33.6 million, or 42%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value rentals, increased rental tools utilization and better pricing. Our drilling services revenues increased $6.8 million, or 20%, in the second quarter of 2011 compared to the second quarter of 2010 primarily as a result of increases in pricing with average day rates rising to $16.5 thousand per day in the second quarter of 2011 from $14.2 thousand per day in the second quarter of 2010.

Our accommodations segment reported revenues in the second quarter of 2011 that were $81.0 million, or 66%, above the second quarter of 2010. The increase in accommodations segment revenues resulted from the full quarter contribution from the recent acquisitions of The MAC and Mountain West and increased oil sands lodge revenues from increased room capacity. Revenues and average available rooms for our oil sands lodges increased 43% and 29%, respectively, in the second quarter of 2011 compared to the second quarter of 2010.

Our offshore products segment revenues increased $25.7 million, or 24%, in the second quarter of 2011 compared to the second quarter of 2010. This increase was primarily the result of higher revenues for production and subsea orders.

Tubular services segment revenues increased $78.7 million, or 31%, in the second quarter of 2011 compared to the second quarter of 2010. This increase was the result of an increase in tons shipped from 134,900 in 2010 to 173,300 in 2011, an increase of 38,400 tons, or 28%, driven by increased drilling activity.

Cost of Sales and Service. Our consolidated cost of sales increased $147.3 million, or 31%, in the second quarter of 2011 compared to the second quarter of 2010 as a result of increased cost of sales at our tubular services segment of $70.3 million, or 29%, an increase at our accommodations segment of $35.3 million, or 48%, an increase at our well site services segment of $21.2 million, or 27%, and an increase at our offshore products segment of $20.5 million, or 26%. Our consolidated gross margin as a percentage of revenues increased from 21% in the second quarter of 2010 to 25% in the second quarter of 2011 primarily due to the increased proportion of relatively higher margin accommodations segment revenues in 2011 compared to 2010 and higher margins realized in our accommodations business in Australia.

Our well site services segment cost of sales increased $21.2 million, or 27%, in the second quarter of 2011 compared to the second quarter of 2010 as a result of a $20.4 million, or 41%, increase in rental tools services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 31% in the second quarter of 2010 to 35% in the second quarter of 2011. Our rental tool gross margin as a percentage of revenues increased from 37% in the second quarter of 2010 to 38% in the second quarter of 2011 primarily due to a more favorable mix of higher value rentals and improved pricing along with higher fixed cost absorption as a result of increased rental tools utilization. Our drilling services cost of sales increased $0.8 million, or 3%, in the second quarter of 2011 compared to the second quarter of 2010. Our drilling services gross margin as a percentage of revenues increased from 17% in the second quarter of 2010 to 29% in the second quarter of 2011 primarily due to the increase in day rates.

Our accommodations segment cost of sales increased $35.3 million, or 48%, in the second quarter of 2011 compared to the second quarter of 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $13.1 million, or 19%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues. Our accommodations segment gross margin as a percentage of revenues increased from 40% in the second quarter of 2010 to 47% in the second quarter of 2011 primarily as a result of higher margins realized by our Australian operations.

Our offshore products segment cost of sales increased $20.5 million, or 26%, in the second quarter of 2011 compared to the second quarter of 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues decreased from 27% in the second quarter of 2010 to 25% in the second quarter of 2011 primarily due to product mix and lower service content in the second quarter of 2011.

Tubular services segment cost of sales increased by $70.3 million, or 29%, primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues increased from 5% in the second quarter of 2010 to 6% in the second quarter of 2011 due primarily to a 2% increase in revenue per ton.

Selling, General and Administrative Expenses. Selling, general and administrative expense (SG&A) increased $5.6 million, or 15%, in the second quarter of 2011 compared to the second quarter of 2010 due primarily to SG&A expense associated with the inclusion of The MAC, which added $2.7 million in SG&A expense in the second quarter of 2011, an increase in employee-related costs, higher ad valorem taxes and higher SG&A costs in our Canadian accommodations business due to the strengthening of the Canadian dollar. SG&A was 5.2% of revenues in the second quarter of 2011 compared to 6.3% of revenues in the second quarter of 2010.

Depreciation and Amortization. Depreciation and amortization expense increased $14.6 million, or 48%, in the second quarter of 2011 compared to the same period in 2010 due primarily to $12.2 million in depreciation and

amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made during the previous twelve months largely related to investments made in our Canadian accommodations business.

Operating Income. Consolidated operating income increased $57.4 million, or 99%, in the second quarter of 2011 compared to the second quarter of 2010 primarily as a result of an increase in operating income from our well site services segment of $22.1 million, or 238%, largely due to the more favorable mix of higher value rentals, improved pricing and increased rental tools utilization coupled with higher operating income in our accommodations segment due to the addition of operating income from The MAC and an increase in operating income from our oil sands lodges due to increased room capacity.

Interest Expense and Interest Income. Net interest expense increased by $8.9 million, or 262%, in the second quarter of 2011 compared to the second quarter of 2010 due to increased debt levels, including interest expense on the 6 1/2% Notes, and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our $1.05 billion credit facilities. The weighted average interest rate on the Company’s revolving credit facilities was 3.0% in the second quarters of 2011 and 2010.

Income Tax Expense. Our income tax provision for the three months ended June 30, 2011 totaled $28.9 million, or 27.9% of pretax income, compared to income tax expense of $16.6 million, or 30.6% of pretax income, for the three months ended June 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

SIX MONTHS ENDED JUNE 30, 2011 COMPARED TO THREE MONTHS ENDED JUNE 30, 2010

We reported net income attributable to Oil States International, Inc. for the six months ended June 30, 2011 of $136.3 million, or $2.48 per diluted share. These results compare to net income of $77.7 million, or $1.49 per diluted share, reported for the six months ended June 30, 2010.

Revenues. Consolidated revenues increased $453.9 million, or 40%, in the first half of 2011 compared to the first half of 2010.

Our well site services segment revenues increased $83.1 million, or 39%, in the first half of 2011 compared to the first half of 2010. This increase was primarily due to significantly increased rental tools revenues. Our rental tools revenues increased $73.6 million, or 50%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value rentals, increased rental tools utilization and better pricing. Our drilling services revenues increased $9.5 million, or 15%, in the first half of 2011 compared to the first half of 2010 primarily as a result of increases in pricing with average day rates rising to $15.9 thousand per day in the first half of 2011 from $14.0 thousand per day in the first half of 2010.

Our accommodations segment reported revenues in the first half of 2011 that were $132.6 million, or 50%, above the first half of 2010. The increase in accommodations segment revenues resulted from the contribution from the recent acquisitions of The MAC and Mountain West and increased oil sands lodge revenues from increased room capacity, partially offset by the Vancouver Olympics contract, which contributed $25.0 million in revenues in the first half of 2010, which was not repeated in 2011. Revenues and average available rooms for our oil sands lodges increased 39% and 27%, respectively, in the first half of 2011 compared to the first half of 2010.

Our offshore products segment revenues increased $51.2 million, or 24%, in the first half of 2011 compared to the first half of 2010. This increase was primarily the result of higher demand for production, subsea pipeline and elastomer products and the contribution from the acquisition of Acute.

Tubular services segment revenues increased $187.0 million, or 43%, in the first half of 2011 compared to the first half of 2010. This increase was the result of an increase in tons shipped from 236,100 in 2010 to 327,700 in 2011, an increase of 91,600 tons, or 39%, driven by increased drilling activity.

Cost of Sales and Service. Our consolidated cost of sales increased $315.2 million, or 36%, in the first half of 2011 compared to the first half of 2010 as a result of increased cost of sales at our tubular services segment of $171.1 million, or 41%, an increase at our accommodations segment of $61.8 million, or 40%, an increase at our well site services segment of $43.4 million, or 29%, and an increase at our offshore products segment of $38.9

million, or 25%. Our consolidated gross margin as a percentage of revenues increased from 22% in the first half of 2010 to 25% in the first half of 2011 primarily due to the increased proportion of relatively higher margin accommodations segment revenues in 2011 compared to 2010 and higher margins realized in our well site services, accommodations and tubular services segments, partially offset by the increased proportion of relatively lower margin tubular services segment revenues in 2011 compared to 2010.

Our well site services segment cost of sales increased $43.4 million, or 29%, in the first half of 2011 compared to the first half of 2010 as a result of a $42.4 million, or 44%, increase in rental tools services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 30% in the first half of 2010 to 35% in the first half of 2011. Our rental tools gross margin as a percentage of revenues increased from 35% in the first half of 2010 to 37% in the first half of 2011 primarily due to a more favorable mix of higher value rentals and improved pricing along with higher fixed cost absorption as a result of increased rental tools utilization. Our drilling services cost of sales increased $1.0 million, or 2%, in the first half of 2011 compared to the first half of 2010. Our drilling services gross margin as a percentage of revenues increased from 17% in the first half of 2010 to 27% in the first half of 2011 primarily due to the increase in day rates.

Our accommodations segment cost of sales increased $61.8 million, or 40%, in the first half of 2011 compared to the first half of 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $16.7 million, or 11%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues. Our accommodations segment gross margin as a percentage of revenues increased from 42% in the first half of 2010 to 46% in the first half of 2011 primarily due to higher margins realized by our Australian operations.

Our offshore products segment cost of sales increased $38.9 million, or 25%, in the first half of 2011 compared to the first half of 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues was 25% in the first half of 2010 and 2011.

Tubular services segment cost of sales increased by $171.1 million, or 41%, primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues increased from 5% in the first half of 2010 to 6% in the first half of 2011 due primarily to a 3% increase in revenue per ton.

Selling, General and Administrative Expenses. SG&A increased $14.1 million, or 20%, in the first half of 2011 compared to the first half of 2010 due primarily to SG&A expense associated with the inclusion of The MAC, which added $6.0 million in SG&A expense in the first half of 2011, increased employee-related costs and increased ad valorem taxes. SG&A was 5.5% of revenues in the first half of 2011 compared to 6.4% of revenues in the first half of 2010.

Depreciation and Amortization. Depreciation and amortization expense increased $28.7 million, or 47%, in the first half of 2011 compared to the same period in 2010 due primarily to $23.0 million in depreciation and amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made during the previous twelve months largely related to investments made in our Canadian accommodations business.

Operating Income. Consolidated operating income increased $92.4 million, or 79%, in the first half of 2011 compared to the first half of 2010 primarily as a result of an increase in operating income from our well site services segment of $46.4 million, or 396%, largely due to the more favorable mix of higher value rentals, improved pricing and increased rental tools utilization and the addition of operating income from The MAC. Operating income in the first half of 2011 included $1.4 million in acquisition related expenses for acquisitions closed in the fourth quarter of 2010.

Interest Expense and Interest Income. Net interest expense increased by $14.7 million, or 217%, in the first half of 2011 compared to the first half of 2010 due to increased debt levels, including interest expense on the 6 1/2% Notes, and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our $1.05 billion credit facilities. The weighted average interest rate on the Company’s revolving credit facilities was 3.0% in the first six months of 2011 compared to 2.5% in the first six months of 2010. Interest income increased as a result of increased cash balances in interest bearing accounts.

Income Tax Expense. Our income tax provision for the six months ended June 30, 2011 totaled $52.3 million, or 27.6% of pretax income, compared to income tax expense of $33.4 million, or 30.0% of pretax income, for the six months ended June 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures, which have in the past included expanding our accommodations facilities, expanding and upgrading our offshore products manufacturing facilities and equipment, increasing and replacing rental tools assets, adding drilling rigs, 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 and proceeds from borrowings.

Cash totaling $96.6 million was provided by operations during the first six months of 2011 compared to cash totaling $85.9 million provided by operations during the first six months of 2010. During the first six months of 2011, $148.2 million was used to fund working capital, primarily due to increased investments in working capital for our tubular services segment, increases in receivables in our Canadian accommodations business and increased raw materials inventory in our offshore products segment due to increased activity levels. During the first six months of 2010, $57.1 million was used to fund working capital, primarily due to increased OCTG inventory levels in our tubular services segment to meet increasing demand.

Cash was used in investing activities during the six months ended June 30, 2011 and 2010 in the amount of $231.3 million and $74.2 million, respectively. Capital expenditures totaled $230.3 million and $76.1 million during the six months ended June 30, 2011 and 2010, respectively. Capital expenditures in both years consisted principally of purchases of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments.

We currently expect to spend a total of approximately $650 million for capital expenditures during 2011 to expand our Canadian oil sands and Australian mining 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 cash available, internally generated funds and borrowings under our revolving credit facilities or other corporate borrowings. The foregoing capital expenditure budget does not include any funds for opportunistic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed attractive to the Company.

Net cash of $164.1 million was provided by financing activities during the six months ended June 30, 2011, primarily as a result of proceeds from the issuance of $600 million aggregate principal amount of 6 1/2% senior unsecured notes due in 2019 in the second quarter of 2011. We spent $12.6 million in financings costs in the first six months of 2011. A total of $6.7 million was provided by financing activities during the six months ended June 30, 2010, primarily as a result of the issuance of common stock as a result of stock option exercises.

We believe that cash on hand, cash flow 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 and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the economy, the financial markets and other factors, many of which are beyond our control. In addition, such additional debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to stockholders.

Stock Repurchase Program. On August 27, 2010, the Company announced that its Board of Directors authorized $100 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which expired on December 31, 2009. The Company presently has approximately 51.3 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2012. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. As of June 30, 2011, we had not repurchased any shares pursuant to this board authorization.

Credit Facilities. On December 10, 2010, we replaced our existing $500 million bank credit facility with $1.05 billion in senior credit facilities governed by the Amended and Restated Credit Agreement (Credit Agreement). The Credit Agreement consists of a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan. The new facilities increased the total commitments available from $500 million under the previous facilities to $1.05 billion. In connection with the execution of the Credit Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $325 million to U.S. $700 million (including $200 million in term loans), and the total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $175 million to U.S. $350 million (including $100 million in term loans). The maturity date of the Credit Agreement is December 10, 2015. The aggregate principal of the term loans is repayable at a rate of 1.25% per quarter in 2011 and 2.5% per quarter thereafter. We currently have 19 lenders in our Credit Agreement with commitments ranging from $26.6 million to $150 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, the lack of or delay in funding by a significant member of our banking group could negatively affect our liquidity position.

As of June 30, 2011, we had $296.5 million outstanding under the Credit Agreement and an additional $18.5 million of outstanding letters of credit, leaving $727.4 million available to be drawn under the facilities.

On July 13, 2011, The MAC entered into a A$150 million Facility Agreement with National Australia Bank Limited. The Facility Agreement replaces The MAC’s existing A$75 million revolving loan facility on substantially the same terms, including the maturity date of the Facility Agreement of November 30, 2013. As of June 30, 2011, there were no borrowings outstanding under this facility.

Our total debt represented 36.8% of our combined total debt and shareholders’ equity at June 30, 2011 compared to 35.9% at December 31, 2010 and 10.3% at June 30, 2010. As of June 30, 2011, the Company was in compliance with all of its debt convenants.

6 1/2% Notes. On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% Notes due 2019 through a private placement to qualified institutional buyers.

The 6 1/2% Notes are senior unsecured obligations of the Company and the Guarantors which bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.500% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount) equal to 104.875% for the twelve-month period beginning on June 1, 2014, 103.250% for the twelve-month period beginning June 1, 2015, 101.625% for the twelve-month period beginning June 1, 2016 and 100.00% beginning on June 1, 2017, plus accrued and unpaid interest to the redemption date.

In connection with the note offering, the Company, the Guarantors of the 6 1/2% Notes and the initial purchasers entered into a registration rights agreement at the closing of the offering. Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they will, subject to certain exceptions, use commercially reasonable efforts to file with the Commission and cause to become effective a registration statement relating to an offer to exchange the 6 1/2% Notes for an issue of Commission-registered 6 1/2% Notes with identical terms. If the exchange offer is not completed on or before the date that is 365 days after the closing date of this offering (the Target Registration Date), then the Company agreed to pay each holder of the 6 1/2% Notes liquidated damages in the form of additional interest in an amount equal to 0.25% per annum of the principal amount of notes held by such holder, with respect to the first 90 days after the Target Registration Date (which rate shall be increased by an additional 0.25% per annum for each subsequent 90-day period that such liquidated damages continue to accrue), in each case until the exchange offer is completed or the shelf registration statement is declared effective or is no longer required to be effective; provided, however, that at no time will the amount of liquidated damages accruing exceed in the aggregate 0.5% per annum. The maximum additional interest potentially payable pursuant to this provision would be $2.6 million.

On June 1, 2011, in connection with the issuance of the 6 1/2% Notes, the Company entered into an Indenture (the Indenture), among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee. The Indenture restricts the Company’s ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 6 1/2% Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The Indenture contains customary events of default. As of June 30, 2011, the Company was in compliance with all covenants of the 6 1/2% Notes.

2 3/8% Notes. As of June 30, 2011, we had classified the $175.0 million principal amount of our 2 3/8% Notes, net of unamortized discount, as a current liability because certain contingent conversion thresholds based on the

Company’s stock price were met at that date and, as a result, 2 3/8% Note holders could present their notes for conversion during the quarter following the June 30, 2011 measurement date. If a 2 3/8% Note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they would receive cash up to $1,000 for each 2 3/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% Notes of 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. 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, 2011, the recent trading prices of the 2 3/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. 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 convert over the next twelve months. Should a holder convert their 2 3/8% Notes, we would utilize our existing credit facilities to fund the cash portion of the conversion value.

Critical Accounting Policies

For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Form 10-K. These estimates require significant judgments, assumptions and estimates. We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. There have been no material changes to the judgments, assumptions and estimates upon which our critical accounting estimates are based.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

We have credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of June 30, 2011, we had floating-rate obligations totaling approximately $296.5 million drawn under our 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 rates increased by 1% from June 30, 2011 levels, our consolidated interest expense would increase by a total of approximately $3.0 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 (i) currencies other than the U.S. dollar, which is our functional currency or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks in areas outside the U.S., 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 six months of 2011, our realized foreign exchange losses were $1.9 million and are included in other operating (income) expense in the condensed consolidated statements of income.

Some of our foreign operations are conducted through whölly-owned foreign subsidiaries that have functional currencies other than the U.S. dollar. We currently have subsidiaries whose functional currencies are the Canadian dollar and Australian dollar. Assets and liabilities from these subsidiaries are translated into U.S. dollars at the exchange rate in effect at each balance sheet date. The resulting translation gains or losses are reflected as accumulated other comprehensive income (loss) in the shareholders’ equity section of our consolidated balance sheets.

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 Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed,

summarized and reported within the time periods specified in the rules and forms of the Commission. 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, 2011 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

During the three months ended June 30, 2011, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that 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

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 2010 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 2010 Form 10-K. The risks described in this Quarterly Report on Form 10-Q and our 2010 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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 (File No. 001-16337)).

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 (File No. 001-16337)).

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 (File No. 001-16337)).

4.1	—	Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).


Exhibit No.		Description
4.2	—	Supplemental Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

4.3	—	Registration Rights Agreement dated as of June 1, 2011 among the Company, the Guarantors and Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

10.1**	—	Assignment Letter between the Company and Ron Green effective May 3, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 6, 2011 (File No. 001-16337)).

10.2	—	Purchase Agreement dated as of May 26, 2011 among the Company, the Guarantors and Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

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.

101.INS***	—	XBRL Instance Document.

101.SCH***	—	XBRL Taxonomy Extension Schema Document.

101.CAL***	—	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF***	—	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB***	—	XBRL Taxonomy Extension Label Linkbase Document.

101.PRE***	—	XBRL Taxonomy Extension Presentation Linkbase Document.


*		Filed herewith

**		Management contracts or compensatory plans or arrangements

***		Furnished herewith.

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: August 2, 2011	By	/s/ BRADLEY J. DODSON
		Bradley J. Dodson
		Senior Vice President, Chief Financial Officer and
		Treasurer (Duly Authorized Officer and Principal Financial Officer)

Date: August 2, 2011	By	/s/ ROBERT W. HAMPTON
		Robert W. Hampton
		Senior Vice President — Accounting and
		Secretary (Duly Authorized Officer and Chief Accounting Officer)

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 (File No. 001-16337)).

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 (File No. 001-16337)).

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(File No. 001-16337)).

4.1	—	Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

4.2	—	Supplemental Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

4.3	—	Registration Rights Agreement dated as of June 1, 2011 among the Company, the Guarantors and Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

10.1**	—	Assignment Letter between the Company and Ron Green effective May 3, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 6, 2011 (File No. 001-16337)).

10.2	—	Purchase Agreement dated as of May 26, 2011 among the Company, the Guarantors and Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and Wells Fargo Securities, LLC, as representatives of the Initial Purchasers (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

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.

101.INS***		XBRL Instance Document.

101.SCH***		XBRL Taxonomy Extension Schema Document.

101.CAL***		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF***		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB***		XBRL Taxonomy Extension Label Linkbase Document.


Exhibit No.				Description
101.PRE***				XBRL Taxonomy Extension Presentation Linkbase Document


*		Filed herewith

**		Management contracts or compensatory plans or arrangements

***		Furnished herewith.

OIL STATES INTERNATIONAL, INC - Quarter Report: 2011 June (Form 10-Q)

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