Oil States International (OIS) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

OR

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

For the transition period from _________________________ to_________________________

Commission file number:  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,	77002
Houston, Texas	(Zip Code)
(Address of principal executive offices)

(713) 652-0582

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year,

if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES  [X]                   NO  [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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  [X]                   NO  [  ]

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   [X]		Accelerated Filer [  ]
Non-Accelerated Filer [  ] (Do not check if a smaller reporting company)		Smaller Reporting Company [  ]

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

YES  [  ]                  NO  [X ]

The Registrant had 54,741,285 shares of common stock, par value $0.01, outstanding and 3,565,490 shares of treasury stock as of August 2, 2012.

1

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, 2012 and 2011	3
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Six Month Periods Ended June 30, 2012 and 2011	4
	Consolidated Balance Sheets – June 30, 2012 (unaudited) and December 31, 2011	5
	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months EndedJune 30, 2012 and 2011	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7 – 24
Cautionary Statement Regarding Forward-Looking Statements		25
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25 – 36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36 – 37
Item 4.	Controls and Procedures	37
	Part II -- OTHER INFORMATION
Item 1.	Legal Proceedings	37 – 38
Item 1A.	Risk Factors	38
Item 2.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	39
Item 6.	Exhibits	39
	(a) Index of Exhibits	39 – 40
Signature Page		41

2

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 JUNE 30,						SIX MONTHS ENDED JUNE 30,
	2012			2011			2012			2011
Revenues	$	1,091,088		$	820,317		$	2,190,080		$	1,580,758
Costs and expenses:
Cost of sales and services		819,164			616,778			1,614,961			1,191,176
Selling, general and administrative expenses		48,853			42,765			96,592			86,472
Depreciation and amortization expense		54,218			45,238			104,884			90,390
Other operating (income) expense		(407	)		373			137			2,781
		921,828			705,154			1,816,574			1,370,819
Operating income		169,260			115,163			373,506			209,939
Interest expense, net of capitalized interest		(17,937	)		(12,532	)		(35,880	)		(22,781	)
Interest income		242			235			539			1,248
Equity in earnings of unconsolidated affiliates		220			2			640			53
Other income		4,308			488			6,044			631
Income before income taxes		156,093			103,356			344,849			189,090
Income tax expense		(44,617	)		(28,887	)		(97,901	)		(52,270	)
Net income		111,476			74,469			246,948			136,820
Less: Net income attributable to noncontrolling interest		242			226			650			500
Net income attributable to Oil States International, Inc.	$	111,234		$	74,243		$	246,298		$	136,320
Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	2.15		$	1.45		$	4.78		$	2.67
Diluted	$	2.01		$	1.34		$	4.45		$	2.48
Weighted average number of common shares outstanding:
Basic		51,637			51,231			51,533			51,083
Diluted		55,251			55,270			55,404			55,061

The accompanying notes are an integral part of

these financial statements.

3

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,
	2012			2011			2012			2011
Net income	$	111,476		$	74,469		$	246,948		$	136,820
Other comprehensive income (loss):
Foreign currency translation adjustment		(28,283	)		35,052			(3,037	)		65,715
Total other comprehensive income (loss)		(28,283	)		35,052			(3,037	)		65,715
Comprehensive income		83,193			109,521			243,911			202,535
Comprehensive income attributable to noncontrolling interest		(215	)		(239	)		(640	)		(538	)
Comprehensive income attributable to Oil States International, Inc.	$	82,978		$	109,282		$	243,271		$	201,997

The accompanying notes are an integral part of

these financial statements.

4

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands)

	JUNE 30, 2012			DECEMBER 31, 2011
	(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents	$	114,391		$	71,721
Accounts receivable, net		831,424			732,240
Inventories, net		733,803			653,698
Prepaid expenses and other current assets		21,568			32,000
Total current assets		1,701,186			1,489,659
Property, plant, and equipment, net		1,657,189			1,557,088
Goodwill, net		467,099			467,450
Other intangible assets, net		121,014			127,602
Other noncurrent assets		63,201			61,842
Total assets	$	4,009,689		$	3,703,641
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	297,476		$	252,209
Accrued liabilities		88,265			96,748
Income taxes		25,617			10,395
Current portion of long-term debt and capitalized leases		32,262			34,435
Deferred revenue		71,779			75,497
Other current liabilities		4,322			5,665
Total current liabilities		519,721			474,949
Long-term debt and capitalized leases		1,130,592			1,142,505
Deferred income taxes		107,358			97,377
Other noncurrent liabilities		26,449			25,538
Total liabilities		1,784,120			1,740,369
Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 55,266,720 shares and 54,803,539 shares issued, respectively, and 51,701,473 shares and 51,288,750 shares outstanding, respectively		553			548
Additional paid-in capital		568,729			545,730
Retained earnings		1,696,884			1,450,586
Accumulated other comprehensive income		71,334			74,371
Treasury stock, at cost, 3,565,247 and 3,514,789 shares, respectively		(113,171	)		(109,079	)
Total Oil States International, Inc. stockholders’ equity		2,224,329			1,962,156
Noncontrolling interest		1,240			1,116
Total stockholders’ equity		2,225,569			1,963,272
Total liabilities and stockholders’ equity	$	4,009,689		$	3,703,641

The accompanying notes are an integral part of

these financial statements.

5

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	SIX MONTHS ENDED JUNE 30,
	2012			2011
Cash flows from operatinqg activities:
Net income	$	246,948		$	136,820
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		104,884			90,390
Deferred income tax provision		4,991			10,788
Excess tax benefits from share-based payment arrangements		(6,014	)		(6,198	)
Gains on disposals of assets		(4,851	)		(763	)
Non-cash compensation charge		9,189			7,198
Accretion of debt discount		4,106			3,823
Amortization of deferred financing costs		3,600			2,914
Other, net		(547	)		(126	)
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		(99,243	)		(66,481	)
Inventories		(79,781	)		(88,781	)
Accounts payable and accrued liabilities		36,199			7,802
Taxes payable		29,137			9,977
Other current assets and liabilities, net		2,707			(10,728	)
Net cash flows provided by operating activities		251,325			96,635
Cash flows from investing activities:
Capital expenditures, including capitalized interest		(199,983	)		(230,253	)
Acquisitions of businesses, net of cash acquired		--			(212	)
Proceeds from disposition of property, plant and equipment		5,225			1,435
Other, net		(1,650	)		(2,285	)
Net cash flows used in investing activities		(196,408	)		(231,315	)
Cash flows from financing activities:
Revolving credit borrowings and (repayments), net		(951	)		(428,682	)
6 1/2% senior notes issued		--			600,000
Term loan repayments		(14,944	)		(7,494	)
Debt and capital lease repayments		(2,312	)		(587	)
Issuance of common stock from share-based payment arrangements		7,801			9,792
Excess tax benefits from share-based payment arrangements		6,014			6,198
Payment of financing costs		(23	)		(12,640	)
Tax withholdings related to net share settlements of restricted stock		(4,092	)		(2,456	)
Net cash flows provided by (used in) financing activities		(8,507	)		164,131
Effect of exchange rate changes on cash		(3,461	)		(2,399	)
Net increase in cash and cash equivalents from continuing operations		42,949			27,052
Net cash used in discontinued operations – operating activities		(279	)		(98	)
Cash and cash equivalents, beginning of period		71,721			96,350
Cash and cash equivalents, end of period	$	114,391		$	123,304

The accompanying notes are an integral part of these

financial statements.

6

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

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 condensed 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, 2011 (the 2011 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 non-owner 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 were effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The amendments do not require any transition disclosures. In December 2011, the FASB issued an amendment deferring the effective date of the requirement to present reclassification adjustments out of accumulated other comprehensive income on the face of the consolidated statement of income.  We adopted this standard in the quarterly Report on Form 10-Q for the three month period ended March 31, 2012.

7

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

3.     DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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

	JUNE 30, 2012			DECEMBER 31, 2011
Accounts receivable, net:
Trade	$	615,924		$	553,481
Unbilled revenue		217,190			180,273
Other		1,979			2,449
Total accounts receivable		835,093			736,203
Allowance for doubtful accounts		(3,669	)		(3,963	)
	$	831,424		$	732,240

	JUNE 30, 2012			DECEMBER 31, 2011
Inventories, net:
Tubular goods	$	476,650		$	420,519
Other finished goods and purchased products		86,661			80,184
Work in process		70,690			76,353
Raw materials		111,864			86,672
Total inventories		745,865			663,728
Allowance for obsolescence		(12,062	)		(10,030	)
	$	733,803		$	653,698

	ESTIMATED USEFUL LIFE (years)			JUNE 30, 2012			DECEMBER 31, 2011
Property, plant and equipment, net:
Land				$	49,282		$	48,989
Accommodations assets (1)	2	-	15		1,251,663			1,160,661
Buildings and leasehold improvements (1)	1	-	40		171,177			154,233
Machinery and equipment	1	-	29		375,128			355,798
Rental tools	4	-	10		227,195			199,084
Office furniture and equipment	1	-	10		51,075			48,081
Vehicles	2	-	10		111,993			100,554
Construction in progress					186,619			166,371
Total property, plant and equipment					2,424,132			2,233,771
Accumulated depreciation					(766,943	)		(676,683	)
				$	1,657,189		$	1,557,088

	JUNE 30, 2012		DECEMBER 31, 2011
Accrued liabilities:
Accrued compensation	$	48,061	$	61,394
Accrued interest		5,804		6,035
Insurance liabilities		12,558		12,396
Accrued taxes, other than income taxes		10,179		5,889
Liabilities related to discontinued operations		1,846		2,125
Other		9,817		8,909
	$	88,265	$	96,748

(1) As of December 31, 2011, we have reclassified $54.7 million in buildings and leasehold improvements to accommodations assets for comparability purposes.

8

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

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 JUNE 30,				SIX MONTHS ENDED JUNE 30,
	2012		2011		2012		2011
Basic earnings per share:
Net income attributable to Oil States International, Inc.	$	111,234	$	74,243	$	246,298	$	136,320
Weighted average number of shares outstanding		51,637		51,231		51,533		51,083
Basic earnings per share	$	2.15	$	1.45	$	4.78	$	2.67
Diluted earnings per share:
Net income attributable to Oil States International, Inc.	$	111,234	$	74,243	$	246,298	$	136,320
Weighted average number of shares outstanding		51,637		51,231		51,533		51,083
Effect of dilutive securities:
Options on common stock		484		679		531		703
2 3/8% Convertible Senior Subordinated Notes		3,030		3,200		3,196		3,094
Restricted stock awards and other		100		160		144		181
Total shares and dilutive securities		55,251		55,270		55,404		55,061
Diluted earnings per share	$	2.01	$	1.34	$	4.45	$	2.48

Our calculation of diluted earnings per share for the three and six months ended June 30, 2012 excludes 625,565 shares and 484,533 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, 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.

9

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

5.     BUSINESS ACQUISITIONS AND GOODWILL

See Note 13 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form  10-Q.

Changes in the carrying amount of goodwill for the six month period ended June 30, 2012 are as follows (in thousands):

	Well Site Services
	Rental Tools and Services			Drilling Services			Subtotal			Accommodations			Offshore Products			Tubular Services			Total
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 and purchase price adjustments		--			--			--			(9,826	)		315			--			(9,511	)
Foreign currency translation and other changes		(323	)		--			(323	)		2,087			(25	)		--			1,739
		75,183			--			75,183			291,323			100,944			--			467,450
Balance as of December 31, 2011
Goodwill		169,711			22,767			192,478			291,323			100,944			62,863			647,608
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		--			--			(62,863	)		(180,158	)
		75,183			--			75,183			291,323			100,944			--			467,450
Foreign currency translation and other changes		(29	)		--			(29	)		(373	)		51			--			(351	)
		75,154			--			75,154			290,950			100,995			--			467,099
Balance as of June 30, 2012
Goodwill		169,682			22,767			192,449			290,950			100,995			62,863			647,257
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		--			--			(62,863	)		(180,158	)
	$	75,154		$	--		$	75,154		$	290,950		$	100,995		$	--		$	467,099

6.     DEBT

As of June 30, 2012 and December 31, 2011, long-term debt consisted of the following (in thousands):

	June 30, 2012		December 31, 2011
	(Unaudited)
U.S. revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million and with a weighted average interest rate of 3.1% for the six month period ended June 30, 2012	$	73,500	$	68,065
U.S. term loan, which matures December 10, 2015, of $200 million; 2.5% of aggregate principal repayable per quarter; weighted average interest rate of 2.5% for the six month period ended June 30, 2012		180,000		190,000
Canadian revolving credit facility, which matures on December 10, 2015, with available commitments up to $250 million and with a weighted average interest rate of 4.3% for the six month period ended June 30, 2012		--		--
Canadian term loan, which matures December 10, 2015, of $100 million; 2.5% of aggregate principal repayable per quarter; weighted average interest rate of 3.5% for the six month period ended June 30, 2012		88,675		93,795
Australian revolving credit facility, which matures November 30, 2013, with available commitments up to A$150 million and with a weighted average interest rate of 6.4% for the six month period ended June 30, 2012		36,850		43,050
6 1/2% senior unsecured notes - due June 2019		600,000		600,000
2 3/8% contingent convertible senior subordinated notes, net due 2025		174,990		170,884
Subordinated unsecured notes payable to sellers of businesses, fixed interest rate of 6%, which mature in December 2012		2,000		4,000
Capital lease obligations and other debt		6,839		7,146
Total debt		1,162,854		1,176,940
Less: Current portion		32,262		34,435
Total long-term debt and capitalized leases	$	1,130,592	$	1,142,505

10

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

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, are guaranteed by our material U.S. subsidiaries (the Guarantors), 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 optional redemption prices as a percentage of principal amount are as follows:

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

The Company utilized approximately $515 million of the net proceeds of the 6 1/2% Note offering in June 2011 to repay borrowings outstanding under its U.S. and Canadian credit facilities (as defined below).  The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.

On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Contingent Convertible Senior Subordinated Notes (2 3/8% Notes) due 2025, totaling $174,990,000 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. In July 2012, rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $174,990,000 aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and 3,012,380 shares of the Company’s Common Stock.  As of June 30, 2012, we classified the $175.0 million principal amount of our 2 3/8% Notes as a noncurrent liability based on our ability and intent to refinance the 2 3/8% Notes utilizing borrowings available under our senior secured credit facilities.  See Note 13 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.   

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

	June 30, 2012		December 31, 2011
Carrying amount of the equity component in additional paid-in capital	$	28,434	$	28,434
Principal amount of the liability component	$	174,990	$	174,990
Less: Unamortized discount		--		4,106
Net carrying amount of the liability component	$	174,990	$	170,884

The discount on the 2 3/8% Notes was fully amortized as of June 30, 2012 in consideration of the expected conversion of these notes in July 2012.

11

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

The effective interest rate of 7.17% was applied as of the issuance date for our 2 3/8% Notes in accordance with ASC 470-20 – Debt with Conversion and Other Options.  Interest expense on the 2 3/8% Notes, excluding amortization of debt issue costs, was as follows (in thousands):

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
Interest expense	$	3,111	$	2,968	$	6,185	$	5,901

	June 30, 2012
Remaining period over which discount will be amortized	Discount is fully amortized
Conversion price	$	31.75
Number of shares to be delivered upon conversion (1)		2,868,143
Conversion value in excess of principal amount (in thousands) (1)	$	189,871
Derivative transactions entered into in connection with the convertible notes	None

(1) Calculation is based on the Company’s June 29, 2012 closing stock price of $66.20.  See Note 13 to the Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.

On July 13, 2011, The MAC Services Group Pty Limited (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, which is guaranteed by the Company. The Facility Agreement amended 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, 2012, we had A$36 million outstanding under the Australian credit facility leaving A$114 million available to be drawn under this 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 and our 6 1/2% Notes, 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 and analysis of similar debt instruments (Level 2 fair value measurements).  The Company changed from a Level 1 fair value measurement standard to a Level 2 fair value measurement standard in the second quarter of 2012 in consideration of the daily trading volume of our debt instruments.  The carrying values and fair values of these notes were as follows (in thousands):

			June 30, 2012				December 31, 2011
	Interest Rate		Carrying Value		Fair Value		Carrying Value		Fair Value
6 1/2% Notes
Principal amount due 2019		6 1/2%	$	600,000	$	636,000	$	600,000	$	625,128
2 3/8% Notes
Principal amount due 2025		2 3/8%	$	174,990	$	366,693	$	174,990	$	411,396
Less:  unamortized discount				-		-		4,106		-
Net value			$	174,990	$	366,693	$	170,884	$	411,396

As of June 30, 2012, the estimated fair value of the Company's debt outstanding under its credit facilities was estimated to be at fair value.

As June 30, 2012, the Company had approximately $114.4 million of cash and cash equivalents and $648.6 million of the Company’s U.S. and Canadian credit facilities available for future financing needs.  The Company also had availability totaling A$114 million under its Australian credit facility.  As of June 30, 2012, we had $31.8 million of outstanding letters of credit.

12

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Interest expense on the condensed consolidated statements of income is net of capitalized interest of $1.2 million and $2.5 million, respectively, for the three and six months ended June 30, 2012 and $1.0 million and $2.5 million, respectively, for the same periods in 2011.

7.     CHANGES IN COMMON STOCK OUTSTANDING

Shares of common stock outstanding – January 1, 2012	51,288,750
Shares issued upon exercise of stock options and vesting of restricted stock awards	463,181
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury	(50,458	)
Shares of common stock outstanding – June 30, 2012	51,701,473

8.     STOCK BASED COMPENSATION

During the first six months of 2012, we granted restricted stock awards totaling 289,993 shares valued at a total of $24.3 million.  Of the restricted stock awards granted in the first half of 2012, a total of 206,000 awards vest in four equal annual installments beginning in February 2013, 47,625 awards are performance shares that may vest in February 2015 in an amount that will depend on the Company’s achievement of specified performance objectives, 23,625 awards vest 100% in February 2016 and 12,464 awards vest 100% in May 2013.  The performance based awards have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital for the three year period 2012 to 2014.  During the six months ended June 30, 2012, the Company also granted 54,950 units of phantom shares under the newly created Canadian Long-Term Incentive Plan, which provides for the granting of units of phantom shares to key Canadian employees. These awards vest in three equal annual installments beginning in February 2013 and are accounted for as a liability.  Participants granted units of phantom shares are entitled to a lump sum cash payment equal to the fair market value of a share of the Company’s Common Stock on the vesting date.  A total of 155,250 stock options with a ten-year term were awarded in the six months ended June 30, 2012 with an average exercise price of $84.52 that will vest in four equal annual installments starting in February 2013.

Stock based compensation pre-tax expense recognized in the six month periods ended June 30, 2012 and 2011 totaled $9.2 million and $7.2 million, or $0.12 and $0.10 per diluted share after tax, respectively.  Stock based compensation pre-tax expense recognized in the three month periods ended June 30, 2012 and 2011 totaled $4.8 million and $3.8 million, or $0.07 and $0.05 per diluted share after tax, respectively.  The total fair value of restricted stock awards that vested during the six months ended June 30, 2012 and 2011 was $15.6 million and $12.2 million, respectively. At June 30, 2012, $44.8 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, 2012 totaled $44.6 million, or 28.6% of pretax income, and $97.9 million, or 28.4% of pretax income, respectively, compared to $28.9 million, or 27.9% of pretax income, and $52.3 million, or 27.6% of pretax income, respectively, for the three and six months ended June 30, 2011.  The modest increase in the effective tax rate from the prior year was largely the result of higher domestic earnings as a percentage of total earnings.  Our domestic earnings are taxed at a higher rate than our foreign earnings.

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 technologies 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.  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 impacted by seasonally higher activity during the Canadian winter drilling season occurring in the first calendar quarter.

13

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Financial information by business segment for each of the three and six months ended June 30, 2012 and 2011 is summarized in the following table (in thousands):

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings of unconsolidated affiliates		Capital expenditures		Total assets
Three months ended June 30, 2012
Well site services –
Rental tools and services	$	125,079	$	12,433	$	28,974		$	--	$	19,349	$	489,942
Drilling services		51,456		5,950		8,358			--		4,961		131,273
Total well site services		176,535		18,383		37,332			--		24,310		621,215
Accommodations		260,966		31,609		83,207			--		62,217		1,928,076
Offshore products		191,638		3,434		36,589			67		10,977		704,508
Tubular services		461,949		573		24,054			153		281		714,130
Corporate and eliminations		--		219		(11,922	)		--		796		41,760
Total	$	1,091,088	$	54,218	$	169,260		$	220	$	98,581	$	4,009,689

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings of unconsolidated affiliates			Capital expenditures		Total assets
Three months ended June 30, 2011
Well site services –
Rental tools and services	$	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

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings of unconsolidated affiliates		Capital expenditures		Total assets
Six months ended June 30, 2012
Well site services –
Rental tools and services	$	260,633	$	23,873	$	62,768		$	--	$	37,874	$	489,942
Drilling services		98,862		11,021		15,817			--		13,524		131,273
Total well site services		359,495		34,894		78,585			--		51,398		621,215
Accommodations		562,786		61,560		202,232			--		126,125		1,928,076
Offshore products		377,358		6,852		69,090			252		20,963		704,508
Tubular services		890,441		1,144		46,475			388		296		714,130
Corporate and eliminations		--		434		(22,876	)		--		1,201		41,760
Total	$	2,190,080	$	104,884	$	373,506		$	640	$	199,983	$	4,009,689

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings of unconsolidated affiliates			Capital expenditures		Total assets
Six months ended June 30, 2011
Well site services –
Rental tools and services	$	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

14

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

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.

12.   CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Certain wholly-owned subsidiaries, as detailed below (the Guarantor Subsidiaries), have fully and unconditionally guaranteed all of the 6 1/2% Notes issued in 2011 and all of the 2 3/8% Notes issued in 2005.

The following condensed consolidating financial information is included so that separate financial statements of the Guarantor Subsidiaries are not required to be filed with the Commission. The condensed consolidating financial information presents investments in both consolidated and unconsolidated affiliates using the equity method of accounting.

The following condensed consolidating financial information presents: consolidating statements of income and comprehensive income for each of the three and six month periods ended June 30, 2012 and 2011, condensed consolidating balance sheets as of June 30, 2012 and December 31, 2011 and the statements of cash flows for each of the six months ended June 30, 2012 and 2011 of (a) the Company (parent/guarantor), (b) Acute Technological Services, Inc., Capstar Holding, L.L.C., Capstar Drilling, Inc., General Marine Leasing, L.L.C., Oil States Energy Services L.L.C., Oil States Energy Services Holding, Inc., Oil States Energy Services International Holding, L.L.C., Oil States Management, Inc., Oil States Industries, Inc., Oil States Skagit SMATCO, L.L.C., PTI Group USA L.L.C., PTI Mars Holdco 1, L.L.C., Sooner Inc., Sooner Pipe, L.L.C., Sooner Holding Company, Specialty Rental Tools & Supply, L.L.C., Stinger Wellhead Protection, Incorporated, and Well Testing, Inc., (the Guarantor Subsidiaries), (c) the non-guarantor subsidiaries, (d) consolidating adjustments necessary to consolidate the Company and its subsidiaries and (e) the Company on a consolidated basis.  Note:  As of January 1, 2012, Specialty Rental Tools & Supply, L.L.C., Stinger Wellhead Protection, Incorporated, and Well Testing, Inc. were combined to form Oil States Energy Services L.L.C.

We have corrected the presentation of our condensed consolidating statements of income for the three and six month periods ended June 30, 2011, our condensed consolidating balance sheet as of December 31, 2011 and our statement of cash flows for the six month period ended June 30, 2011 to properly reflect the investment in and equity earnings of certain non-guarantor subsidiaries by certain guarantor subsidiaries in accordance with SEC Regulation S-X, which were previously only presented in the Parent/Guarantor column.  We have also corrected other immaterial amounts previously disclosed to properly present (i) the activity and balances of a certain guarantor subsidiary in the Guarantor Subsidiaries column which was previously presented in the Parent/Guarantor column and (ii) the activity and balances of a certain non-guarantor subsidiary in the Non-Guarantors column which was previously presented in the Guarantor Subsidiaries column.  The effect of these corrections increased net income for the Guarantor Subsidiaries and Non-Guarantor Subsidiaries by $26 million and $1 million, respectively, for three month periods ended June 30, 2011 and $47 million and $5 million, respectively, for the six month periods ended June 30, 2011.  The effect of the correction to the Guarantor Subsidiaries’ investments in unconsolidated affiliates balance at December 31, 2011 was an increase of $1,034 million.  These changes had no impact on consolidated results as previously reported.

15

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Three Months Ended June 30, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
REVENUES
Operating revenues	$	—	$	774,316	$	316,772	$	—	$	1,091,088
Intercompany revenues		—		7,516		3,413		(10,929)		—
Total revenues		—		781,832		320,185		(10,929)		1,091,088
OPERATING EXPENSES
Cost of sales and services		—		645,387		175,945		(2,168)		819,164
Intercompany cost of sales and services		—		5,306		3,085		(8,391)		—
Selling, general and administrative expenses		394		31,440		17,019		—		48,853
Depreciation and amortization expense		219		23,082		30,922		(5)		54,218
Other operating (income) expense		143		(71)		(479)		—		(407)
Operating income (loss)		(756)		76,688		93,693		(365)		169,260
Interest expense, net of capitalized interest		(16,803)		(216)		(17,669)		16,751		(17,937)
Interest income		5,033		56		11,904		(16,751)		242
Equity in earnings (loss) of unconsolidated affiliates		123,055		67,555		74		(190,464)		220
Other income		—		3,971		337		—		4,308
Income before income taxes		110,529		148,054		88,339		(190,829)		156,093
Income tax provision		705		(24,613)		(20,709)		—		(44,617)
Net income		111,234		123,441		67,630		(190,829)		111,476
Other comprehensive income:
Foreign currency translation adjustment		(28,283)		(21,244)		(21,244)		42,488		(28,283)
Total other comprehensive income		(28,283)		(21,244)		(21,244)		42,488		(28,283)
Comprehensive income		82,951		102,197		46,386		(148,341)		83,193
Comprehensive income attributable to noncontrolling interest		—		—		(215)		—		(215)
Comprehensive income attributable to Oil States International, Inc.	$	82,951	$	102,197	$	46,171	$	(148,341)	$	82,978

16

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Three Months Ended June 30, 2011
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
REVENUES
Operating revenues	$	—	$	582,948	$	237,369	$	—	$	820,317
Intercompany revenues		—		1,645		216		(1,861)		—
Total revenues		—		584,593		237,585		(1,861)		820,317
OPERATING EXPENSES
Cost of sales and services		—		480,126		137,528		(876)		616,778
Intercompany cost of sales and services		—		778		207		(985)		—
Selling, general and administrative expenses		376		28,899		13,490		—		42,765
Depreciation and amortization expense		203		19,300		25,737		(2)		45,238
Other operating (income)expense		(295)		304		364		—		373
Operating income (loss)		(284)		55,186		60,259		2		115,163
Interest expense		(11,061)		(342)		(17,978)		16,849		(12,532)
Interest income		2,648		21		14,415		(16,849)		235
Equity in earnings of unconsolidated affiliates		82,287		41,808		(229)		(123,864)		2
Other income (expense)		—		274		214		—		488
Income before income taxes		73,590		96,947		56,681		(123,862)		103,356
Income tax provision		654		(14,649)		(14,892)		—		(28,887)
Net income		74,244		82,298		41,789		(123,862)		74,469
Other comprehensive income:
Foreign currency translation adjustment		35,052		62,507		18,751		(81,258)		35,052
Total other comprehensive income		35,052		62,507		18,751		(81,258)		35,052
Comprehensive income		109,296		144,805		60,540		(205,120)		109,521
Comprehensive income attributable to noncontrolling interest		—		—		(222)		(17)		(239)
Comprehensive income attributable to Oil States International, Inc.	$	109,296	$	144,805	$	60,318	$	(205,137)	$	109,282

17

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Six Months Ended June 30, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
REVENUES
Operating revenues	$	—	$	1,527,538	$	662,542	$	—	$	2,190,080
Intercompany revenues		—		12,554		3,443		(15,997)		—
Total revenues		—		1,540,092		665,985		(15,997)		2,190,080
OPERATING EXPENSES
Cost of sales and services		—		1,256,544		362,368		(3,951)		1,614,961
Intercompany cost of sales and services		—		8,528		3,130		(11,658)		—
Selling, general and administrative expenses		825		62,415		33,352		—		96,592
Depreciation and amortization expense		435		44,168		60,290		(9)		104,884
Other operating (income) expense		(25)		(646)		808		—		137
Operating income (loss)		(1,235)		169,083		206,037		(379)		373,506
Interest expense, net of capitalized interest		(33,640)		(433)		(36,114)		34,307		(35,880)
Interest income		10,105		78		24,663		(34,307)		539
Equity in earnings (loss) of unconsolidated affiliates		269,672		148,959		252		(418,243)		640
Other income		—		5,599		445		—		6,044
Income before income taxes		244,902		323,286		195,283		(418,622)		344,849
Income tax provision		1,396		(53,194)		(46,103)		—		(97,901)
Net income		246,298		270,092		149,180		(418,622)		246,948
Other comprehensive income:
Foreign currency translation adjustment		(3,037)		(2,693)		(2,683)		5,376		(3,037)
Total other comprehensive income		(3,037)		(2,693)		(2,683)		5,376		(3,037)
Comprehensive income		243,261		267,399		146,497		(413,246)		243,911
Comprehensive income attributable to noncontrolling interest		—		—		(635)		(5)		(640)
Comprehensive income attributable to Oil States International, Inc.	$	243,261	$	267,399	$	145,862	$	(413,251)	$	243,271

18

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)Condensed Consolidating Statements of Income and Comprehensive Income

	Six Months Ended June 30, 2011
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
REVENUES
Operating revenues	$	—	$	1,106,232	$	474,526	$	—	$	1,580,758
Intercompany revenues		—		3,301		531		(3,832)		—
Total revenues		—		1,109,533		475,057		(3,832)		1,580,758
OPERATING EXPENSES
Cost of sales and services		—		913,322		279,454		(1,600)		1,191,176
Intercompany cost of sales and services		—		1,851		381		(2,232)		—
Selling, general and administrative expenses		755		57,528		28,189		—		86,472
Depreciation and amortization expense		388		40,806		49,199		(3)		90,390
Other operating (income)expense		743		183		1,854		1		2,781
Operating income (loss)		(1,886)		95,843		115,980		2		209,939
Interest expense		(19,472)		(688)		(40,435)		37,814		(22,781)
Interest income		5,218		24		33,819		(37,813)		1,248
Equity in earnings of unconsolidated affiliates		151,163		82,953		(226)		(233,837)		53
Other income (expense)		—		424		207		—		631
Income before income taxes		135,023		178,556		109,345		(233,834)		189,090
Income tax provision		1,297		(27,334)		(26,233)		—		(52,270)
Net income		136,320		151,222		83,112		(233,834)		136,820
Other comprehensive income:
Foreign currency translation adjustment		65,715		87,815		44,070		(131,885)		65,715
Total other comprehensive income		65,715		87,815		44,070		(131,885)		65,715
Comprehensive income		202,035		239,037		127,182		(365,719)		202,535
Comprehensive income attributable to noncontrolling interest		—		—		(515)		(23)		(538)
Comprehensive income attributable to Oil States International, Inc.	$	202,035	$	239,037	$	126,667	$	(365,742)	$	201,997

19

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Balance Sheets

	June 30, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	(250)	$	2,268	$	112,373	$	—	$	114,391
Accounts receivable, net		53		507,894		323,478		(1)		831,424
Inventories, net		—		592,245		142,139		(581)		733,803
Prepaid expenses and other current assets		4,749		6,584		10,235		—		21,568
Total current assets		4,552		1,108,991		588,225		(582)		1,701,186
Property, plant and equipment, net		2,296		499,189		1,155,860		(156)		1,657,189
Goodwill, net		—		172,598		294,501		—		467,099
Other intangible assets, net		—		29,708		91,306		—		121,014
Investments in unconsolidated affiliates		2,369,063		1,435,551		3,674		(3,798,174)		10,114
Long-term intercompany receivables (payables)		779,166		(403,043)		(376,123)		—		—
Other noncurrent assets		38,584		523		13,980		—		53,087
Total assets	$	3,193,661	$	2,843,517	$	1,771,423	$	(3,798,912)	$	4,009,689
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	15,193	$	198,649	$	83,634	$	—	$	297,476
Accrued liabilities		17,144		43,280		27,841		—		88,265
Income taxes		(104,277)		113,989		15,905		—		25,617
Current portion of long-term debt and capitalized leases		20,018		2,328		9,916		—		32,262
Deferred revenue		—		38,698		33,081		—		71,779
Other current liabilities		—		4,039		283		—		4,322
Total current liabilities		(51,922)		400,983		170,660				519,721
Long-term debt and capitalized leases		1,008,500		6,320		115,772		—		1,130,592
Deferred income taxes		1,400		57,837		48,121		—		107,358
Other noncurrent liabilities		11,354		8,789		6,755		(449)		26,449
Total liabilities		969,332		473,929		341,308		(449)		1,784,120
Stockholders’ equity		2,224,329		2,369,588		1,429,088		(3,798,676)		2,224,329
Non-controlling interest		—		—		1,027		213		1,240
Total stockholders’ equity		2,224,329		2,369,588		1,430,115		(3,798,463)		2,225,569
Total liabilities and stockholders’ equity	$	3,193,661	$	2,843,517	$	1,771,423	$	(3,798,912)	$	4,009,689

20

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Balance Sheets

	December 31, 2011
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	(295)	$	1,736	$	70,280	$	—	$	71,721
Accounts receivable, net		974		461,097		270,170		(1)		732,240
Inventories, net		—		539,067		114,823		(192)		653,698
Prepaid expenses and other current assets		10,143		8,538		13,319		—		32,000
Total current assets		10,822		1,010,438		468,592		(193)		1,489,659
Property, plant and equipment, net		1,530		459,414		1,096,310		(166)		1,557,088
Goodwill, net		—		172,598		294,852		—		467,450
Other intangible assets, net		—		31,372		96,230		—		127,602
Investments in unconsolidated affiliates		2,088,062		1,269,457		1,710		(3,351,468)		7,761
Long-term intercompany receivables (payables)		836,853		(453,156)		(383,697)		—		—
Other noncurrent assets		41,235		457		12,389		—		54,081
Total assets	$	2,978,502	$	2,490,580	$	1,586,386	$	(3,351,827)	$	3,703,641
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	19,418	$	162,762	$	70,029	$	—	$	252,209
Accrued liabilities		17,804		48,819		30,125		—		96,748
Income taxes		(59,396)		61,060		8,731		—		10,395
Current portion of long-term debt and capitalized leases		20,018		4,404		10,013		—		34,435
Deferred revenue		—		47,227		28,270		—		75,497
Other current liabilities		—		5,382		283		—		5,665
Total current liabilities		(2,156)		329,654		147,451		—		474,949
Long-term debt and capitalized leases		1,008,969		6,437		127,099		—		1,142,505
Deferred income taxes		(1,072)		57,677		40,772		—		97,377
Other noncurrent liabilities		10,605		8,635		6,747		(449)		25,538
Total liabilities		1,016,346		402,403		322,069		(449)		1,740,369
Stockholders’ equity		1,962,156		2,088,177		1,263,410		(3,351,587)		1,962,156
Non-controlling interest		—		—		907		209		1,116
Total stockholders’ equity		1,962,156		2,088,177		1,264,317		(3,351,378)		1,963,272
Total liabilities and stockholders’ equity	$	2,978,502	$	2,490,580	$	1,586,386	$	(3,351,827)	$	3,703,641

21

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(79,674)	$	157,868	$	173,131	$	—	$	251,325
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(1,198)		(82,503)		(116,282)		—		(199,983)
Proceeds from disposition of property, plant and equipment		—		4,567		658		—		5,225
Other, net		(6)		(5,695)		4,051		—		(1,650)
Net cash provided by (used in) investing activities		(1,204)		(83,631)		(111,573)		—		(196,408)
CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		5,434		—		(6,385)		—		(951)
Term loan repayments		(10,000)		—		(4,944)		—		(14,944)
Debt and capital lease payments		(11)		(2,211)		(90)		—		(2,312)
Issuance of common stock from share-based payment arrangements		7,801		—		—		—		7,801
Excess tax benefits from share-based payment arrangements		6,014		—		—		—		6,014
Proceeds from (funding of) accounts and notes with affiliates, net		75,800		(71,216)		(4,584)		—		—
Tax withholdings related to net share settlements of restricted stock		(4,092)		—		—		—		(4,092)
Other, net		(23)		—		—		—		(23)
Net cash provided by (used in) financing activities		80,923		(73,426)		(16,004)		—		(8,507)
Effect of exchange rate changes on cash		—		—		(3,461)		—		(3,461)
Net change in cash and cash equivalents from continuing operations		45		811		42,093		—		42,949
Net cash used in discontinued operations operating activities		—		(279)		—		—		(279)
Cash and cash equivalents, beginning of period		(295)		1,736		70,280		—		71,721
Cash and cash equivalents, end of period	$	(250)	$	2,268	$	112,373	$	—	$	114,391

22

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2011
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(38,791)	$	57,999	$	77,427	$	—	$	96,635
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(195)		(62,356)		(167,702)				(230,253)
Acquisitions of businesses, net of cash acquired		—		(212)		—		—		(212)
Proceeds from disposition of property, plant and equipment		—		1,052		383		—		1,435
Other, net		—		(147)		(2,138)		—		(2,285)
Net cash used in investing activities		(195)		(61,663)		(169,457)		—		(231,315)
CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings and (repayments), net		(346,742)		—		(81,940)		—		(428,682)
6 1/2% senior notes issued		600,000		—		—		—		600,000
Term loan repayments		(5,000)		—		(2,494)		—		(7,494)
Debt and capital lease payments		(10)		(230)		(347)		—		(587)
Issuance of common stock from share-based payment arrangements		9,792		—		—		—		9,792
Excess tax benefits from share-based payment arrangements		6,198		—		—		—		6,198
Payment of financing costs		(12,640)		—		—		—		(12,640)
Proceeds from (funding of) accounts and notes with affiliates, net		(177,803)		14,922		162,881		—		—
Tax withholdings related to net share settlements of restricted stock		(2,456)		—		—		—		(2,456)
Other, net		—		(3)		3		—		—
Net cash provided by financing activities		71,339		14,689		78,103		—		164,131
Effect of exchange rate changes on cash		—		—		(2,399)		—		(2,399)
Net change in cash and cash equivalents from continuing operations		32,353		11,025		(16,326)		—		27,052
Net cash used in discontinued operations operating activities		—		(98)		—		—		(98)
Cash and cash equivalents, beginning of period		(227)		1,216		95,361		—		96,350
Cash and cash equivalents, end of period	$	32,126	$	12,143	$	79,035	$	—	$	123,304

23

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

13.  SUBSEQUENT EVENTS

On July 2, 2012, we acquired Piper Valve Systems, Ltd (Piper).  Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects located offshore, onshore and subsea.  Piper's valve technology will complement our offshore products segment, allowing us to integrate their valve products and services in various subsea applications and increase our suite of global deepwater product and service offerings.  Subject to customary post-closing adjustments, total transaction consideration was $48.0 million, funded from amounts available under the Company’s U.S. and Canadian credit facilities.

On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $174,990,000 in aggregate principal amount, on July 6, 2012 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. The 2 3/8% Notes were convertible by the holders thereof into shares of the Company’s Common Stock at the conversion rate of 31.496 shares of Common Stock for each $1,000 principal amount of 2 3/8% Notes converted. Rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $174,990,000 aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and 3,012,380 shares of the Company’s Common Stock. No gain or loss was recognized on the conversion.  Dilution attributable to the 2 3/8% Notes was reflected in the diluted share count for the three and six months ended June 30, 2012.  See Note 4 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.

Set forth below is a chart that describes the aggregate principal amount of 2 3/8% Notes converted on each Conversion Date and the resulting number of shares of Common Stock issued in connection with such conversions:

Conversion Date	Principal Amount of 2 3/8% Notes Converted		Number of Shares of Common Stock Issued
July 24, 2012	$	52,684,000		899,713
July 25, 2012		47,917,000		824,036
July 26, 2012		74,389,000		1,288,631
Total	$	174,990,000		3,012,380

24

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 known material factors that could affect our results, please refer to Part II, Item 1A. Risk Factors in this report and "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 2011 Form 10-K filed with the Commission on February 17, 2012.  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.

Macroeconomic Environment and Outlook

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 support both the oil and gas and mining industries.  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, principally that of crude oil, coal and, to a lesser extent, natural gas.

25

In the first quarter of 2012, the price of crude oil increased to over $100 per barrel as positive economic news related to growth rates projected in China and other emerging markets, consumer spending and U.S. consumer confidence indicated that an economic recovery was underway.  However, the spot price of crude oil decreased during the second quarter of 2012 and is currently trading at approximately $90 per barrel for West Texas Intermediates (WTI) crude and around $106 per barrel for Intercontinental Exchange (ICE) Brent crude.  Successful shale oil drilling in the U.S. has led to robust oil production causing supply bottlenecks at Cushing, Oklahoma, which have contributed to WTI trading at a significant discount to Brent crude pricing.  If U.S. oil production grows significantly and continues to exceed pipeline transportation capacity, we could see additional downward pressure on oil prices triggering lower future U.S. drilling activity.  Despite some signs of an improving economy in the United States, the world’s largest consumer of crude oil, global economic risks remain due to fiscal and financial uncertainty in various European countries, a prolonged level of relatively high unemployment in the U.S. and other advanced economies and inflation risks in certain emerging markets.  Recent WTI and Brent crude pricing trends are as follows:

	Average Price (per bbl)
	WTI		Brent Crude
Quarter ended
6/30/2012	$	93.38	$	108.90
3/31/2012		102.85		118.54
12/31/2011		94.03		109.31
9/30/2011		89.71		112.47
6/30/2011		102.51		117.12
3/31/2011		93.93		104.90
12/31/2010		85.10		86.80
9/30/2010		76.01		76.41
6/30/2010		77.86		78.67

Prices for natural gas in the United States continue to be weak due to the rise in production from unconventional natural gas resources in North America, largely due to increases in onshore shale production resulting from technological advancements in horizontal drilling and hydraulic fracturing.  Natural gas prices are currently trading at or below $3.25 per Mcf.  Natural gas inventories in the U.S. continue to be over-stocked, particularly given an unseasonably warm winter season.  The U.S. gas-related working rig count has declined from more than 800 rigs at the beginning of 2012 to less than 520 rigs currently.  Increases in the supply of natural gas, whether the supply comes from conventional or unconventional production or associated gas production from oil wells, will likely constrain prices for natural gas and result in fewer rigs drilling for gas in the near-term.

Growing Chinese and Indian steel production in the first half of 2012 is expected to support metallurgical coal pricing for the remainder of 2012.  After decreasing over the past year, metallurgical coal prices are expected to remain at these levels during the remainder of the year.  Urbanization and infrastructure investment from the Chinese government should fuel continued strength in steel demand in the foreseeable future.  Beyond China, Indian steel consumption is expected to grow as India's five-year growth plan calls for significant investments to expand its infrastructure.

Various oil and gas industry analysts have projected that 2012 global exploration and production expenditures are expected to increase over calendar year 2011 levels.  North American capital spending plans are expected to be focused in onshore areas while international exploration and production budgets are expected to primarily be spent offshore.

Overview

Demand for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices.  In contrast, demand for our well site services and tubular services segments responds 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 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 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 basis covering lodging and meals that is based on the duration of their needs which can range from several months to several years.  In addition, primarily in Canada and the U.S., we provide shorter-term remote site accommodations in smaller configurations utilizing our modular, mobile camp assets.

Generally, our oil sands and mining accommodations’ customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of 10 to in excess of 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 of new and expanded oil sands projects will create the opportunity for extensions of existing accommodations contracts and incremental accommodations contracts for us in Canada.  In addition, several major oil companies and national oil companies have announced joint ventures to develop oil sands leases 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, Japan and India.  Despite coal prices weakening recently, we expect Chinese metallurgical coal demand to continue to increase in 2012 compared to 2011 as the country continues to industrialize.  We are expanding our Australian accommodations capacity to meet this increasing demand.  We are also expanding accommodations deployed to support onshore North American drilling and completion activity in several of the active shale play regions.

26

Our offshore products segment 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.

The improvement in oil prices over the last two years, along with the outlook for long-term oil demand, resulted in increased bidding and quoting activity for our offshore products in the latter part of 2010 that continued throughout 2011 and the first half of 2012.  As a result of this increased activity, backlog in our offshore products segment increased from $519 million as of June 30, 2011 to a record $562 million as of June 30, 2012.  Offshore products’ backlog totaled $535 million as of December 31, 2011.  We anticipate global deepwater spending to continue to include new award opportunities coming from Brazil, West Africa, the U.S. Gulf of Mexico, South East Asia and Australia over the next twelve months.

Our well site services businesses are significantly influenced by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada and the rest of the world.  Until recently, overall industry 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, considering current oil prices, lower natural gas prices and the advancement of horizontal drilling and completion techniques, activity in North America has shifted to a greater proportion of oil and liquids-rich drilling.  According to rig count data published by Baker Hughes Incorporated, the oil rig count in the U.S. now totals approximately 1,400 rigs, the highest oil-related rig count in over 20 years, comprising approximately 73% of total U.S. drilling activity.

In our well site services business segment, we predominantly provide rental tools and services and, to a lesser extent, land drilling services.  Our rental tools and services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells.  Activity for the rental tools and services business is dependent primarily upon the level and complexity of drilling, completion and workover activity throughout North America.  Well complexity has increased as the number of productive zones completed in connection with horizontal drilling has increased.  Demand for our drilling services is driven by land drilling activity in our primary drilling markets in West Texas, where we primarily drill oil wells, and in the Rocky Mountains area in the U.S., where we drill both liquids-rich and natural gas wells.

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 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.  Our tubular services business has historically been our most cyclical business segment.  The strong U.S. land drilling activity in 2011 and in the first half of 2012 along with the return of drilling in the U.S. Gulf of Mexico have led to increased tubular services volumes and revenues.

We have a diversified product and service offering, which has led to exposure to activities conducted throughout the oil and gas cycle.  Demand for our tubular services, land drilling and rental tools and services businesses is highly correlated to changes in the drilling rig count in the United States 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.

27

	Average Drilling Rig Count for
	Three Months Ended				Six Months Ended
	June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011
U.S. Land – Oil		1,351		929		1,294		866
U.S. Land – Natural gas and other		572		870		642		878
U.S. Offshore		47		31		45		29
Total U.S.		1,970		1,830		1,981		1,773
Canada		173		188		382		387
Total North America		2,143		2,018		2,363		2,160

The average North American rig count for the six months ended June 30, 2012 increased by 203 rigs, or 9.4%, compared to the six months ended June 30, 2011 largely due to growth in the U.S. land oil rig count partially offset by a decline in natural gas drilling.

A 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 and, since 2011, Australia.  These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes.  Although U.S. dollar and Australian dollar exchange rates were comparable in the first half of 2012 and 2011, the Canadian dollar was valued at an average exchange rate of U.S. $0.99 in the first half of 2012 compared to U.S. $1.02 for the first half of 2011, a decrease of 3%.  This weakening of the Canadian dollar had a proportionately negative impact on the translation of earnings generated from our Canadian subsidiary and, therefore, the financial results of our accommodations segment.

Steel and steel input prices influence the pricing decisions of our OCTG suppliers, thereby impacting the pricing and margins of our tubular services segment.  During 2011 and 2012, OCTG marketplace supply and demand became more balanced compared to the previous two years.  Increased supplies of OCTG have met the increased demand created by expanded drilling activity.  Throughout 2011 and into the first half of 2012, imports of OCTG have increased, particularly goods imported from Canada and Korea followed by India, Mexico and Japan.  Additionally, domestic OCTG mill capacity is expected to increase in 2012.  This projected increase in OCTG production has led to a decline in OCTG prices during the first half of 2012.  This increase in supply has been in response to the 12% year-over-year increase in the drilling rig count in the U. S.  The OCTG Situation Report suggests that industry OCTG inventory levels peaked in the first quarter of 2009 at approximately twenty months’ supply on the ground and have trended down to approximately four to four-and-a half months' supply currently, which is considered closer to a normalized level when measured against historical levels.  We have expanded our physical infrastructure and installed new enterprise-wide computer systems in 2011 and 2012 to support our growth, optimize our financial returns and ensure ongoing customer service in our OCTG distribution business.  We remain focused on working capital management and returns on invested capital in our tubular services segment and will continue to monitor industry inventory levels, forecasted drilling and completion activity and OCTG prices.

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 the recovery in U.S. Gulf of Mexico drilling following the lifting of the government imposed drilling moratorium.

Although higher than 2011, the drilling rig count in the U.S. Gulf of Mexico remains below historical levels following the Macondo well incident and resultant oil spill in the U.S. Gulf of Mexico.  A rescission of a moratorium on offshore drilling activity was effective in late 2010; however, substantial increases in activity were 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, more stringent regulatory environment continued to have an overall adverse effect on Gulf of Mexico drilling activity in 2011.  Beginning in the third quarter of 2011, however, U.S. Gulf of Mexico drilling activity has shown signs of a slow, but steady, recovery as permitting levels have been steadily improving.  New well permitting has increased from 43 permits issued in the first half of 2011 to 104 permits issued in the first half of 2012.

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We continue to monitor the global economy, the demand for crude oil, coal and natural gas 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 2012 capital expenditures will total approximately $600 million to $700 million compared to 2011 capital expenditures of $487 million.  Our 2012 capital expenditures include funding 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.  Approximately two-thirds of our total expected 2012 capital expenditures will be spent in our accommodations segment.  In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on an evaluation of both the market outlook and industry fundamentals.
 

Consolidated Results of Operations (in millions)

	THREE MONTHS ENDED JUNE 30,										SIX MONTHS ENDED JUNE 30,
							Variance 2012 vs. 2011										Variance
	2012			2011			$		%			2012			2011		$		%
Revenues
Well site services -
Rental tools and services	$	125.1		$	112.7		$	12.4	11	%	$	260.6		$	220.2		$	40.4	18	%
Drilling services		51.4			41.0			10.4	25	%		98.9			74.1			24.8	33	%
Total well site services		176.5			153.7			22.8	15	%		359.5			294.3			65.2	22	%
Accommodations		261.0			202.9			58.1	29	%		562.8			400.1			162.7	41	%
Offshore products		191.6			131.7			59.9	45	%		377.4			260.2			117.2	45	%
Tubular services		462.0			332.0			130.0	39	%		890.4			626.2			264.2	42	%
Total	$	1,091.1		$	820.3		$	270.8	33	%	$	2,190.1		$	1,580.8		$	609.3	39	%
Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Rental tools and services	$	78.3		$	70.4		$	7.9	11	%	$	162.9		$	137.7		$	25.2	18	%
Drilling services		36.4			29.2			7.2	25	%		70.5			54.4			16.1	30	%
Total well site services		114.7			99.6			15.1	15	%		233.4			192.1			41.3	21	%
Accommodations		132.7			108.5			24.2	22	%		272.2			216.8			55.4	26	%
Offshore products		138.8			98.2			40.6	41	%		275.0			194.8			80.2	41	%
Tubular services		433.0			310.5			122.5	39	%		834.4			587.5			246.9	42	%
Total	$	819.2		$	616.8		$	202.4	33	%	$	1,615.0		$	1,191.2		$	423.8	36	%
Gross margin
Well site services -
Rental tools and services	$	46.8		$	42.3		$	4.5	11	%	$	97.7		$	82.5		$	15.2	18	%
Drilling services		15.0			11.8			3.2	27	%		28.4			19.7			8.7	44	%
Total well site services		61.8			54.1			7.7	14	%		126.1			102.2			23.9	23	%
Accommodations		128.3			94.4			33.9	36	%		290.6			183.3			107.3	59	%
Offshore products		52.8			33.5			19.3	58	%		102.4			65.4			37.0	57	%
Tubular services		29.0			21.5			7.5	35	%		56.0			38.7			17.3	45	%
Total	$	271.9		$	203.5		$	68.4	34	%	$	575.1		$	389.6		$	185.5	48	%
Gross margin as a percentage of revenues
Well site services -
Rental tools and services		37	%		38	%						37	%		37	%
Drilling services		29	%		29	%						29	%		27	%
Total well site services		35	%		35	%						35	%		35	%
Accommodations		49	%		47	%						52	%		46	%
Offshore products		28	%		25	%						27	%		25	%
Tubular services		6	%		6	%						6	%		6	%
Total		25	%		25	%						26	%		25	%

THREE MONTHS ENDED JUNE 30, 2012 COMPARED TO THREE MONTHS ENDED JUNE 30, 2011

We reported net income attributable to the Company for the quarter ended June 30, 2012 of $111.2 million, or $2.01 per diluted share.  These results compare to net income attributable to the Company of $74.2 million, or $1.34 per diluted share, reported for the quarter ended June 30, 2011.  Second quarter 2012 results included a pre-tax gain of $2.5 million, or $0.03 per diluted share after-tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012.

Revenues.  Consolidated revenues increased $270.8 million, or 33%, in the second quarter of 2012 compared to the second quarter of 2011.

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Our well site services segment revenues increased $22.8 million, or 15%, in the second quarter of 2012 compared to the second quarter of 2011 primarily due to increases in both rental tools and services revenues and drilling services revenues.  Our rental tools and services revenues increased $12.4 million, or 11%, in the second quarter of 2012 compared to the second quarter of 2011 primarily due to increased demand for completion services supporting the 8% increase in the U.S. rig count, a more favorable mix of higher value rentals and services, increased equipment utilization, additional capital investment in rental equipment and greater service intensity.  Our drilling services revenues increased $10.4 million, or 25%, in the second quarter of 2012 compared to the second quarter of 2011 primarily as a result of increases in pricing, with average day rates rising to $18,500 per day for the second quarter of 2012 up from $16,500 per day for the second quarter of 2011, and increased utilization of our rigs from an average of approximately 80% for the second quarter of 2011 to an average of approximately 92% for the second quarter of 2012.

Our accommodations segment reported revenues in the second quarter of 2012 that were $58.1 million, or 29%, higher than the second quarter of 2011.  Higher accommodations revenues were generated primarily from expanded room capacity in Canada and Australia.  Revenues and average available rooms for lodges and villages increased 41% and 29%, respectively, in the second quarter of 2012 compared to the second quarter of 2011.

Our offshore products segment revenues increased $59.9 million, or 45%, in the second quarter of 2012 compared to the second quarter of 2011.  This increase was primarily the result of higher levels of manufacturing and service activity, along with an improved revenue mix favoring our production equipment and connector products.  Backlog reached a new record level, totaling $562 million at June 30, 2012 compared to $519 million reported at June 30, 2011.

Our tubular services segment revenues increased $130.0 million, or 39%, in the second quarter of 2012 compared to the second quarter of 2011.  This increase was primarily a result of an increase in tons shipped from 173,300 in 2011 to 230,000 in 2012, an increase of 56,700 tons, or 33%, driven by the 8% increase in U.S. drilling and completion activity, particularly increased activity in the Permian, Eagle Ford and Gulf of Mexico markets coupled with increased service intensity.  We also reported a 5% increase in realized revenues per ton shipped in the second quarter of 2012 compared to the second quarter of 2011.

Cost of Sales and Service.  Our consolidated cost of sales increased $202.4 million, or 33%, in the second quarter of 2012 compared to the second quarter of 2011 as a result of increased cost of sales at our tubular services segment of $122.5 million, or 39%, an increase at our offshore products segment of $40.6 million, or 41%, an increase at our accommodations segment of $24.2 million, or 22%, and an increase at our well site services segment of $15.1 million, or 15%.  These cost of sales increases were directly related to the increases in segmental revenues.  Our consolidated gross margin as a percentage of revenues was 25% in both the second quarter of 2012 and 2011.

Our well site services segment cost of sales increased $15.1 million, or 15%, in the second quarter of 2012 compared to the second quarter of 2011 as a result of a $7.9 million, or 11%, increase in rental tools and services cost of sales and a $7.2 million, or 25%, increase in drilling services cost of sales.  Our well site services segment gross margin as a percentage of revenues was 35% in both the second quarter of 2012 and 2011.  Our rental tools and services gross margin as a percentage of revenues was consistent at 37% in the second quarter of 2012 compared to 38% in the second quarter of 2011.  Our drilling services gross margin as a percentage of revenues was also consistent at 29% in the second quarters of 2012 and 2011 despite increased rig utilization and pricing due to increased repair and maintenance costs.

Our accommodations segment cost of sales increased $24.2 million, or 22%, in the second quarter of 2012 compared to the second quarter of 2011 primarily due to increased revenues and room capacity in both Canada and Australia.  Our accommodations segment gross margin as a percentage of revenues increased from 47% in the second quarter of 2011 to 49% in the second quarter of 2012 primarily due to a 10% increase in revenue per available room (RevPar) in the second quarter of 2012 compared to the second quarter of 2011.  The increase in the RevPar in 2012 compared to 2011 was primarily due to increased occupancy levels.

Our offshore products segment cost of sales increased $40.6 million, or 41%, in the second quarter of 2012 compared to the second quarter of 2011 primarily due to increased revenues.  Our offshore products segment gross margin as a percentage of revenues increased from 25% in the second quarter of 2011 to 28% in the second quarter of 2012 primarily due to the improved revenue mix of production equipment and connector products sales combined with improved cost absorption.

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Our tubular services segment cost of sales increased by $122.5 million, or 39%, in the second quarter of 2012 compared to the second quarter of 2011 primarily as a result of an increase in tons shipped.  Our tubular services segment gross margin as a percentage of revenues remained constant at 6% in both the second quarter of 2012 and 2011.

Selling, General and Administrative Expenses.  Selling, general and administrative expense increased $6.1 million, or 14%, in the second quarter of 2012 compared to the second quarter of 2011 primarily due to increased employee-related costs, commissions expense and professional fees.

Depreciation and Amortization.  Depreciation and amortization expense increased $9.0 million, or 20%, in the second quarter of 2012 compared to the second quarter of 2011 primarily due to capital expenditures made during the previous twelve months largely related to investments in our Canadian and Australian accommodations and rental tools and services businesses.

Operating Income.  Consolidated operating income increased $54.1 million, or 47%, in the second quarter of 2012 compared to the second quarter of 2011 primarily as a result of an increase in operating income from our accommodations segment of $25.5 million, or 44%, primarily as a result of expanded room capacity in Canada and Australia, and an increase in operating income from our offshore products segment of $17.8 million, or 95%.  In addition, operating income from our tubular services segment increased $7.1 million, or 42%, primarily as a result of the increase in tons shipped.  Operating income from our well site services segment increased $5.9 million, or 19%, largely due to a more favorable mix and increased activity in our rental tools and services business and increased rig utilization and dayrates in our drilling services business.

Interest Expense and Interest Income.  Net interest expense increased by $5.4 million, or 44%, in the second quarter of 2012 compared to the second quarter of 2011 primarily due to interest expense associated with the 6 1/2% Notes which were issued on June 1, 2011.  The weighted average interest rate on borrowings outstanding under the Company’s U.S. and Canadian credit facilities was 3.0% in the second quarters of 2012 and 2011.

Income Tax Expense.  Our income tax provision for the three months ended June 30, 2012 totaled $44.6 million, or 28.6% of pretax income, compared to income tax expense of $28.9 million, or 27.9% of pretax income, for the three months ended June 30, 2011.  The increase in the effective tax rate from the prior year was largely the result of higher domestic earnings as a percentage of total earnings.  Our domestic earnings are taxed at a higher rate than our foreign earnings.

SIX MONTHS ENDED JUNE 30, 2012 COMPARED TO SIX MONTHS ENDED JUNE 30, 2011

We reported net income attributable to the Company for the six months ended June 30, 2012 of $246.3 million, or $4.45 per diluted share, including a gain of $17.9 million, or $0.23 per diluted share after-tax, from a favorable contract settlement reported in our U.S. accommodations business and a pre-tax gain of $2.5 million, or $0.03 per diluted share after-tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012.  These results compare to net income attributable to the Company of $136.3 million, or $2.48 per diluted share, reported for the six months ended June 30, 2011.

Revenues.  Consolidated revenues increased $609.3 million, or 39%, in the first half of 2012 compared to the first half of 2011.

Our well site services segment revenues increased $65.2 million, or 22%, in the first half of 2012 compared to the first half of 2011 primarily due to increases in both rental tools and services revenues and drilling services revenues.  Our rental tools and services revenues increased $40.4 million, or 18%, in the first half of 2012 compared to the first half of 2011 primarily due to increased demand for completion services supporting the 12% increase in the U.S. rig count, a more favorable mix of higher value rentals and services, increased equipment utilization, additional capital investment in rental equipment and greater service intensity.  Our drilling services revenues increased $24.8 million, or 33%, in the first half of 2012 compared to the first half of 2011 primarily as a result of increased utilization of our rigs from an average of approximately 76% in for the first half of 2011 to an average of approximately 90% during the first half of 2012, and increases in pricing, with average day rates rising to $18,200 per day for the first half of 2012 up from $15,900 per day for the first half of 2011.

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Our accommodations segment reported revenues in the first half of 2012 that were $162.7 million, or 41%, above the first half of 2011.  The increase in accommodations revenue primarily resulted from increased revenues from expanded room capacity in Canada and Australia along with $18.3 million in revenue from a favorable contract settlement reported in our U.S. accommodations business.  Revenues and average available rooms for our lodges and villages increased 44% and 32%, respectively, in the first half of 2012 compared to the first half of 2011.

Our offshore products segment revenues increased $117.2 million, or 45%, in the first half of 2012 compared to the first half of 2011.  This increase was primarily the result of higher levels of manufacturing and service activity, along with an improved revenue mix favoring our production equipment and connector products.

Our tubular services segment revenues increased $264.2 million, or 42%, in the first half of 2012 compared to the first half of 2011.  This increase was primarily a result of an increase in tons shipped from 327,700 in 2011 to 435,400 in 2012, an increase of 107,700 tons, or 33%, driven by the 12% increase in U.S. drilling and completion activity, particularly increased activity in the Permian, Eagle Ford and Gulf of Mexico markets coupled with increased service intensity.  We also reported a 7% increase in realized revenues per ton shipped in the first half of 2012 compared to the first half of 2011.

Cost of Sales and Service.  Our consolidated cost of sales increased $423.8 million, or 36%, in the first half of 2012 compared to the first half of 2011 as a result of increased cost of sales at our tubular services segment of $246.9 million, or 42%, an increase at our offshore products segment of $80.2 million, or 41%, an increase at our accommodations segment of $55.4 million, or 26%, and an increase at our well site services segment of $41.3 million, or 21%.  These cost of sales increases were directly related to the increases in segmental revenues.  Our consolidated gross margin as a percentage of revenues increased from 25% in the first half of 2011 to 26% in the first half of 2012 primarily due to the increased proportion of relatively higher margin accommodations and rental tools and services revenues and higher margins realized in our accommodations and offshore products segments, partially offset by an increased proportion of relatively lower margin tubular services segment revenues in the first half of 2012 compared to the first half of 2011.

Our well site services segment cost of sales increased $41.3 million, or 21%, in the first half of 2012 compared to the first half of 2011 as a result of a $25.2 million, or 18%, increase in rental tools and services cost of sales and a $16.1 million, or 30%, increase in drilling services cost of sales.  Our well site services segment gross margin as a percentage of revenues remained constant at 35% in the first half of 2012 and 2011.  Our rental tools and services gross margin as a percentage of revenues was 37% in the first half of 2012 and 2011.  Our drilling services gross margin as a percentage of revenues increased from 27% in the first half of 2011 to 29% in the first half of 2012 primarily due to increased day rates, rig utilization and cost absorption.

Our accommodations segment cost of sales increased $55.4 million, or 26%, in the first half of 2012 compared to the first half of 2011 primarily due to increased revenues and room capacity in both Canada and Australia.  Our accommodations segment gross margin as a percentage of revenues increased from 46% in the first half of 2011 to 52% in the first half of 2012 primarily due to a 9% increase in RevPar in the first half of 2012 compared to the first half of 2011 and, to a lesser extent, the favorable contract settlement reported in our U.S. accommodations business.  The increase in the RevPar in 2012 compared to 2011 was primarily due to increased occupancy levels.  Excluding the favorable contract settlement, our accommodations segment gross margin as a percentage of revenues would have been 48% in the first half of 2012.

Our offshore products segment cost of sales increased $80.2 million, or 41%, in the first half of 2012 compared to the first half of 2011 primarily due to increased revenues.  Our offshore products segment gross margin as a percentage of revenues increased from 25% in the first half of 2011 to 27% in the first half of 2012 primarily due to the improved revenue mix of production equipment and connector products sales combined with improved cost absorption.

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Our tubular services segment cost of sales increased by $246.9 million, or 42%, in the first half of 2012 compared to the first half of 2011 primarily as a result of an increase in tons shipped.  Our tubular services segment gross margin as a percentage of revenues remained at high levels in the second quarter of 2012 with 6.3% compared to 6.5% reported in the second quarter of 2011 primarily due to higher-end OCTG product mix and stable mill pricing.

Selling, General and Administrative Expenses.  Selling, general and administrative expense increased $10.1 million, or 12%, in the first half of 2012 compared to the first half of 2011 primarily due to increased employee-related costs and commissions expense.

Depreciation and Amortization. Depreciation and amortization expense increased $14.5 million, or 16%, in the first half of 2012 compared to the first half of 2011 primarily due to capital expenditures made during the previous twelve months largely related to investments in our Canadian and Australian accommodations and rental tools and services businesses.

Operating Income.  Consolidated operating income increased $163.6 million, or 78%, in the first half of 2012 compared to the first half of 2011 primarily as a result of an increase in operating income from our accommodations segment of $95.5 million, or 89%, due to expanded room capacity in Canada and Australia, along with the favorable contract settlement reported in our U.S. accommodations business, an increase in operating income from our offshore products segment of $33.6 million, or 95%, and an increase in operating income from our well site services segment of $20.5 million, or 35%, largely due to a more favorable mix and increased activity in our rental tools and services business and increased rig utilization and dayrates in our drilling services business.  In addition, operating income from our tubular services segment increased $16.5 million, or 55%, primarily as a result of the increase in tons shipped.

Interest Expense and Interest Income.  Net interest expense increased by $13.8 million, or 64%, in the first half of 2012 compared to the first half of 2011 primarily due to interest expense on the 6 1/2% Notes due in 2019 which were issued on June 1, 2011.  The weighted average interest rate on borrowings outstanding under the Company’s U.S. and Canadian credit facilities was 3.2% in the first half of 2012 compared to 3.0% in the first half of 2011.  Interest income decreased as a result of decreased cash balances in interest bearing accounts.

Income Tax Expense.  Our income tax provision for the six months ended June 30, 2012 totaled $97.9 million, or 28.4% of pretax income, compared to income tax expense of $52.3 million, or 27.6% of pretax income, for the six months ended June 30, 2011.  The increase in the effective tax rate from the prior year was largely the result of higher domestic earnings as a percentage of total earnings.  Our domestic earnings are taxed at a higher rate than our foreign earnings.

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, replacing and increasing rental tool assets, funding new product development and for general working capital needs. In addition, capital has been used to repay debt and fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings, and capital markets transactions.

Cash totaling $251.3 million was provided by operations during the first six months of 2012 compared to cash totaling $96.6 million provided by operations during the first six months of 2011.  During the first six months of 2012, $111.0 million was used to fund working capital, primarily due to increased investments in working capital for our tubular services business and increases in receivables in our Canadian accommodations business.  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.

Cash was used in investing activities during the six months ended June 30, 2012 and 2011 in the amounts of $196.4 million and $231.3 million, respectively.  Capital expenditures totaled $200.0 million and $230.3 million during the six months ended June 30, 2012 and 2011, respectively.  Capital expenditures in both years consisted principally of purchases and installation of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments and Australian mining related accommodations facilities.

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We currently expect to spend a total of approximately $600 million to $700 million for capital expenditures during 2012 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.  Approximately two-thirds of our total estimated 2012 capital expenditures are expected to be spent in our accommodations segment.  We expect to fund these capital expenditures with cash available, internally generated funds and borrowings under our U.S. and Canadian credit facilities.  The foregoing capital expenditure budget does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company.  At June 30, 2012, we had cash totaling $112.8 million held by foreign subsidiaries, primarily in Canada and the United Kingdom, where we have assumed permanent reinvestment of earnings and where we have not recorded a U.S. tax liability upon the assumed repatriation of foreign earnings.  We believe these cash balances will be utilized for future investment outside the United States.

On July 2, 2012, we acquired Piper Valve Systems, Ltd (Piper).  Subject to customary post-closing adjustments, total transaction consideration was $48.0 million, funded from amounts available under the Company’s U.S. and Canadian credit facilities.

Net cash of $8.5 million was used in financing activities during the six months ended June 30, 2012, primarily as a result of repayments on our U.S. and Canadian term loans, partially offset by proceeds from the issuance of common stock from share-based payment arrangements.  A total 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 2019 in the second quarter of 2011 partially offset by repayments of our revolving credit facility.

On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $174,990,000 in aggregate principal amount, on July 6, 2012 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. All 2 3/8% Noteholders elected to convert their 2 3/8% Notes - see Note 13 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.

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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 global economy, the global 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.  As of June 30, 2012, the Company had approximately 51.7 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.  Through June 30, 2012, a total of $12.6 million of our stock (209,300 shares) had been repurchased under the current authorization, leaving a total remaining authorization of up to approximately $87.4 million available.

Credit Facilities.  Our current bank credit facilities consist of a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan.  The U.S. and Canadian credit facilities contain total commitments available of $1.05 billion, including Total U.S. Commitments (as defined in the Credit Agreement) of U.S. $700 million (including $200 million in U.S. term loans), and Total Canadian Commitments (as defined in the Credit Agreement) of U.S. $350 million (including $100 million in Canadian term loans).  The maturity date of the Credit Agreement is December 10, 2015. The current principal balance of the term loans is repayable at a rate of 2.5% per quarter of the aggregate principal amount until maturity on December 10, 2015 when the remaining principal is due.  We currently have 19 lenders in our Credit Agreement with commitments ranging from $25.3 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, 2012, we had $342.2 million outstanding under the Credit Agreement and an additional $27.9 million of outstanding letters of credit, leaving $648.6 million available to be drawn under the U.S. and Canadian facilities.  In July 2012, we repaid our 2 3/8% Notes and reduced availability by $175 million.

On July 13, 2011, The MAC entered into a A$150 million Facility Agreement with National Australia Bank Limited. The Facility Agreement amended 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, 2012, we had A$36 million outstanding under the Australian credit facility leaving A$114 million available to be drawn under this facility.

Our total debt represented 34.3% of our combined total debt and stockholders’ equity at June 30, 2012 compared to 37.5% at December 31, 2011 and 36.8% at June 30, 2011.  As of June 30, 2012 and after repayment of the 2 3/8% Notes, the Company was in compliance with all of its debt covenants.

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

The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), 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 optional redemption prices as a percentage of principal amount are as follows:

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

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

On June 1, 2011, in connection with the issuance of the 6 1/2% Notes, the Company entered into an Indenture (the Indenture) with 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, 2012, the Company was in compliance with all covenants of the 6 1/2% Notes.

2 3/8% Notes.  If certain contingent conversion thresholds based on the Company’s stock price are met and a 2 3/8% Note holder chooses to present its notes for conversion during a future quarter prior to the first put/call date in July 2012, then it 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.  As of June 30, 2012, the contingent conversion thresholds were met and, as a result, 2 3/8% Note holders could present their notes for conversion during the quarter following the June 30, 2012 measurement date.  As of June 30, 2012, the recent trading prices of the 2 3/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder.  As of June 30, 2012, we had classified the $175.0 million principal amount of our  2 3/8% Notes as a noncurrent liability based on our ability and intent to refinance the 2 3/8% Notes utilizing borrowings available under our U.S. and Canadian credit facilities.

On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $174,990,000 in aggregate principal amount, on July 6, 2012 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. The 2 3/8% Notes were convertible by the holders thereof into shares of the Company’s Common Stock at the conversion rate of 31.496 shares of Common Stock for each $1,000 principal amount of 2 3/8% Notes converted. Rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $174,990,000 aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and 3,012,380 shares of the Company’s Common Stock.

Set forth below is a chart that describes the aggregate principal amount of 2 3/8% Notes converted on each Conversion Date and the resulting number of shares of Common Stock issued in connection with such conversions:

Conversion Date	Principal Amount of 2 3/8% Notes Converted		Number of Shares of Common Stock Issued
July 24, 2012	$	52,684,000		899,713
July 25, 2012		47,917,000		824,036
July 26, 2012		74,389,000		1,288,631
Total	$	174,990,000		3,012,380

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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 2011 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, 2012, we had floating-rate obligations totaling approximately $379.0 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 floating interest rates increased by 1%, our consolidated interest expense would increase by a total of approximately $3.8 million annually based on our floating debt obligations as of June 30, 2012.

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. (primarily in our offshore products segment), 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 2012, our reported foreign exchange losses were $0.4 million and are included in “Other operating expense” in the consolidated statements of income.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in 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, 2012 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

Effective January 1, 2012, we reorganized our rental tools and services operations by merging several separate legal entities into one entity, realigning management and combining three formerly separate accounting groups into one accounting group with one accounting system.  This reorganization resulted in changes in our disclosure controls and procedures that were implemented during the first quarter of 2012 to ensure that information required to be disclosed and reported by this business was recorded, processed, summarized and reported accurately and on a timely basis.

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During the three months ended June 30, 2012, 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) or in other factors, which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1.  Legal Proceedings

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 2011 Form 10-K includes a detailed discussion of our risk factors.  The risks described in this Quarterly Report on Form 10-Q and our 2011 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.  There have been no significant changes to our risk factors as set forth in our 2011 Form 10-K except for the additional risk factors below:

We could be subject to additional regulatory initiatives in the U.S. Gulf of Mexico that could subject us to increased costs and liabilities.

Offshore U.S. Gulf of Mexico exploration and production operations have been subject to additional, more stringent environmental and safety-related regulations and other regulatory initiatives issued by the Bureau of Ocean Energy Management (BOEM), the Bureau of Safety and Environmental Enforcement (BSEE) and the Office of Natural Resource Revenue (ONRR), in addition to their regulatory predecessors, in the aftermath of the Macondo well incident in April 2010.  In addition, governmental officials responsible for one or more of the aforementioned regulatory bodies have publically stated that their authority extends beyond oil and gas operators to include service and equipment contractors as well.  This governmental assertion of broad legal authority to govern contractors’ activity is a new development, may be subject to future clarification and may result in the development and implementation of various regulatory compliance programs governing contractor activities.  We are uncertain about the potential breadth of future regulatory initiatives, if implemented, or the specific responsibilities that may arise from these initiatives, but expect that the implementation of new or more stringent initiatives may subject us and other contractors to increased costs and liabilities to comply, which could have a significant adverse effect on our expectations.  We believe that offshore contractors and service providers, including ourselves, will closely monitor rulemaking in this area to ensure ongoing compliance.

Exchange rate fluctuations could adversely affect our results of operations and financial position.

In the ordinary course of our business, we enter into purchase and sales commitments that are denominated in currencies that differ from the functional currency used by our operating subsidiaries. Currency exchange rate fluctuations can create volatility in our consolidated financial position, results of operations and/or cash flows. Although we may enter into foreign exchange agreements with financial institutions in order to reduce our exposure to fluctuations in currency exchange rates, these transactions, if entered into, will not eliminate that risk entirely. To the extent that we are unable to match sales received in foreign currencies with expenses paid in the same currency, exchange rate fluctuations could have a negative impact on our consolidated financial position, results of operations and/or cash flows. Additionally, because our consolidated financial results are reported in U.S. dollars, if we generate net sales or earnings within entities whose functional currency is not the U.S. dollar, the translation of such amounts into U.S. dollars can result in an increase or decrease in the amount of our net sales and earnings. With respect to our potential exposure to foreign currency fluctuations and devaluations, for the six months ended June 30, 2012, approximately 30% of our sales originated from subsidiaries outside of the U.S. in currencies including, among others, the Canadian dollar, the Australian dollar and the pound sterling. As a result, a material decrease in the value of these currencies relative to the U.S. dollar may have a negative impact on our reported sales, net income and cash flows. Any currency controls implemented by local monetary authorities in countries where we currently operate could also adversely affect our business, financial condition and results of operations.

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ITEM 2.  Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Purchases of Equity Securities

Period	Total Number of Shares Purchased			Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Program		Approximate Dollar Value of Shares That May Yet Be Purchased Under the Program (1)
April 1, 2012 – April 30, 2012		--			--			--	$	87,367,801
May 1, 2012 – May 31, 2012		282	(2)	$	68.57	(3)		--	$	87,367,801
June 1, 2012 – June 30, 2012		9,524	(2)	$	69.58	(4)		--	$	87,367,801
Total		9,806		$	69.55			--	$	87,367,801

(1)   On August 27, 2010, we announced a share repurchase program of up to $100,000,000.  The share repurchase program expires on September 1, 2012.

(2)   Shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.

(3)   The price paid per share was based on the weighted average closing price of our Company’s common stock on May 15, 2012 and May 17, 2012, which represent the dates the restrictions lapsed on such shares.

(4)   The price paid per share was based on the weighted average closing price of our Company’s common stock on June 16, 2012 and June 19, 2012, which represents the date the restrictions lapsed on such shares.

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)).

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.

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SIGNATURES

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

OIL STATES INTERNATIONAL, INC.

Date:	August 3, 2012	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 3, 2012	By	/s/ ROBERT W. HAMPTON
			Robert W. Hampton
			Senior Vice President -- Accounting and
			Secretary (Duly Authorized Officer and Chief Accounting Officer)

40

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)).

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.