Edgar Filing: OIL STATES INTERNATIONAL, INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2011


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

For the transition period from ______________ to ______________

Commission file number: 001-16337

OIL STATES INTERNATIONAL, INC.

(Exact name of registrant as specified in its charter)


Delaware		76-0476605

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


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

(Address of principal executive offices)		(Zip Code)

(713) 652-0582

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year,
if changed since last report)

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

YES o NO þ

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)

YES þ NO o

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

(Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a 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 o NO þ

The Registrant had 51,232,208 shares of common stock, par value $0.01, outstanding and 3,514,789
shares of treasury stock as of November 3, 2011.

OIL STATES INTERNATIONAL, INC.

INDEX


	Page No.
Part I — FINANCIAL INFORMATION

Item 1. Financial Statements:

Condensed Consolidated Financial Statements

Unaudited Condensed Consolidated Statements of Income for the Three and Nine Month Periods Ended September 30, 2011 and 2010		3

Consolidated Balance Sheets — September 30, 2011 (unaudited) and December 31, 2010		4

Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		5

Notes to Unaudited Condensed Consolidated Financial Statements		6—23

Cautionary Statement Regarding Forward-Looking Statements		24

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		24—35

Item 3. Quantitative and Qualitative Disclosures About Market Risk		35

Item 4. Controls and Procedures		36

Part II — OTHER INFORMATION

Item 1. Legal Proceedings		36

Item 1A. Risk Factors		36

Item 2. Purchases of Equity Securities By the Issuer and Affiliated Purchasers		37

Item 6. Exhibits		37—38

(a) Index of Exhibits		37—38

Signature Page		39
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

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


	THREE MONTHS ENDED						NINE MONTHS ENDED
	SEPTEMBER 30,						SEPTEMBER 30,
	2011			2010			2011			2010
Revenues	$	902,621		$	588,347		$	2,483,379		$	1,715,225

Costs and expenses:
Cost of sales and services		665,855			448,602			1,857,031			1,324,594
Selling, general and administrative expenses		45,430			37,142			131,902			109,479
Depreciation and amortization expense		46,929			30,410			137,318			92,088
Other operating (income) expense		(57	)		1,803			2,724			1,116

		758,157			517,957			2,128,975			1,527,277

Operating income		144,464			70,390			354,404			187,948
Interest expense, net of capitalized interest		(16,760	)		(3,534	)		(39,541	)		(10,505	)
Interest income		174			134			1,422			316
Equity in earnings (loss) of unconsolidated affiliates		(204	)		80			(151	)		144
Other income		885			17			1,515			587

Income before income taxes		128,559			67,087			317,649			178,490
Income tax expense		(36,487	)		(20,609	)		(88,757	)		(53,988	)

Net income		92,072			46,478			228,892			124,502
Less: Net income attributable to noncontrolling interest		221			132			721			436

Net income attributable to Oil States International, Inc.	$	91,851		$	46,346		$	228,171		$	124,066

Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	1.79		$	0.92		$	4.46		$	2.48
Diluted	$	1.67		$	0.88		$	4.15		$	2.37
Weighted average number of common shares outstanding:
Basic		51,264			50,282			51,144			50,108
Diluted		54,960			52,538			55,028			52,304

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In Thousands)


	SEPTEMBER 30,			DECEMBER 31,
	2011			2010
	(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents	$	118,851		$	96,350
Accounts receivable, net		579,449			478,739
Inventories, net		602,830			501,435
Prepaid expenses and other current assets		27,714			23,480

Total current assets		1,328,844			1,100,004
Property, plant, and equipment, net		1,455,807			1,252,657
Goodwill, net		465,624			475,222
Other intangible assets, net		125,164			139,421
Other noncurrent assets		61,573			48,695

Total assets	$	3,437,012		$	3,015,999

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	329,903		$	304,739
Income taxes		6,883			4,604
Current portion of long-term debt and capitalized leases		197,522			181,175
Deferred revenue		67,607			60,847
Other current liabilities		5,694			2,810

Total current liabilities		607,609			554,175
Long-term debt and capitalized leases		900,476			731,732
Deferred income taxes		98,688			81,198
Other noncurrent liabilities		19,490			19,961

Total liabilities		1,626,263			1,387,066
Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock		547			541
Additional paid-in capital		538,783			508,429
Retained earnings		1,356,304			1,128,133
Accumulated other comprehensive income		23,179			84,549
Treasury stock		(108,917	)		(93,746	)

Total Oil States International, Inc. stockholders’ equity		1,809,896			1,627,906

Noncontrolling interest		853			1,027

Total stockholders’ equity		1,810,749			1,628,933

Total liabilities and stockholders’ equity	$	3,437,012		$	3,015,999

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)


	NINE MONTHS
	ENDED SEPTEMBER 30,
	2011			2010
Cash flows from operating activities:
Net income	$	228,892		$	124,502
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		137,318			92,088
Deferred income tax provision		16,281			920
Excess tax benefits from share-based payment arrangements		(7,966	)		(2,126	)
Non-cash compensation charge		10,829			9,687
Accretion of debt discount		5,787			5,388
Amortization of deferred financing costs		4,699			790
Other, net		(1,666	)		(1,667	)
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		(109,415	)		10,912
Inventories		(104,421	)		(81,146	)
Accounts payable and accrued liabilities		28,137			28,513
Taxes payable		11,343			(10,922	)
Other current assets and liabilities, net		3,256			(23,554	)

Net cash flows provided by operating activities		223,074			153,385

Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		(212	)		—
Capital expenditures, including capitalized interest		(371,165	)		(120,952	)
Other, net		(823	)		1,925

Net cash flows used in investing activities		(372,200	)		(119,027	)

Cash flows from financing activities:
Revolving credit borrowings and (repayments), net		(395,908	)		—
6 ¹/2% senior notes issued		600,000			—
Term loan repayments		(11,246	)		—
Debt and capital lease repayments		(966	)		(357	)
Issuance of common stock from share-based payment arrangements		11,559			14,165
Purchase of treasury stock		(12,632	)		—
Excess tax benefits from share-based payment arrangements		7,966			2,126
Payment of financing costs		(13,152	)		—
Other, net		(2,551	)		(1,406	)

Net cash flows provided by financing activities		183,070			14,528

Effect of exchange rate changes on cash		(11,325	)		(143	)

Net increase in cash and cash equivalents from continuing operations		22,619			48,743
Net cash used in discontinued operations — operating activities		(118	)		(105	)
Cash and cash equivalents, beginning of period		96,350			89,742

Cash and cash equivalents, end of period	$	118,851		$	138,380

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

The accompanying unaudited condensed consolidated financial statements of Oil States International, Inc. and its wholly-owned subsidiaries (referred to in this report as we or the Company) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the Commission) pertaining to interim financial information. Certain information in footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted pursuant to these rules and regulations. The unaudited financial statements included in this report reflect all the adjustments, consisting of normal recurring adjustments, which the Company considers necessary for a fair presentation of the results of operations for the interim periods covered and for the financial condition of the Company at the date of the interim balance sheet. Results for the interim periods are not necessarily indicative of results for the full year.

The preparation of consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. If the underlying estimates and assumptions, upon which the financial statements are based, change in future periods, actual amounts may differ from those included in the accompanying condensed consolidated financial statements.

The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2010 (the 2010 Form 10-K).

2. RECENT ACCOUNTING PRONOUNCEMENTS

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

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

In September 2011, the FASB issued an accounting standards update which is intended to simplify goodwill impairment testing by giving an entity the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. An entity has the option to bypass such qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests

performed, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. The Company plans to early adopt this standard for its annual goodwill impairment tests in 2011. We do not expect that the adoption of this standard will have a material effect on our consolidated financial statements.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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


	SEPTEMBER 30,			DECEMBER 31,
	2011			2010
Accounts receivable, net:
Trade	$	425,107		$	365,988
Unbilled revenue		155,515			113,389
Other		1,569			3,462

Total accounts receivable		582,191			482,839
Allowance for doubtful accounts		(2,742	)		(4,100	)

	$	579,449		$	478,739


	SEPTEMBER 30,			DECEMBER 31,
	2011			2010
Inventories, net:
Tubular goods	$	375,114		$	332,720
Other finished goods and purchased products		76,444			71,266
Work in process		60,439			45,662
Raw materials		100,499			60,241

Total inventories		612,496			509,889
Allowance for obsolescence		(9,666	)		(8,454	)

	$	602,830		$	501,435


	ESTIMATED	SEPTEMBER 30,			DECEMBER 31,
	USEFUL LIFE	2011			2010
Property, plant and equipment, net:
Land		$	42,923		$	43,411
Buildings and leasehold improvements	1-40 years		203,671			193,617
Machinery and equipment	2-29 years		335,208			311,217
Accommodations assets	3-15 years		964,709			840,002
Rental tools	4-10 years		192,116			166,245
Office furniture and equipment	1-10 years		44,204			36,325
Vehicles	2-10 years		89,227			82,783
Construction in progress			217,024			113,773

Total property, plant and equipment			2,089,082			1,787,373
Accumulated depreciation			(633,275	)		(534,716	)

		$	1,455,807		$	1,252,657


	SEPTEMBER 30,		DECEMBER 31,
	2011		2010
Accounts payable and accrued liabilities:
Trade accounts payable	$	234,653	$	224,543
Accrued compensation		48,068		47,760
Accrued interest		14,599		2,772
Accrued taxes, other than income taxes		11,555		4,887
Insurance liabilities		9,226		8,615
Liabilities related to discontinued operations		2,150		2,268
Other		9,652		13,894

	$	329,903	$	304,739

4. EARNINGS PER SHARE

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


	THREE MONTHS ENDED				NINE MONTHS ENDED
	SEPTEMBER 30,				SEPTEMBER 30,
	2011		2010		2011		2010
Basic earnings per share:
Net income attributable to Oil States International, Inc.	$	91,851	$	46,346	$	228,171	$	124,066

Weighted average number of shares outstanding		51,264		50,282		51,144		50,108

Basic earnings per share	$	1.79	$	0.92	$	4.46	$	2.48

Diluted earnings per share:
Net income attributable to Oil States International, Inc.	$	91,851	$	46,346	$	228,171	$	124,066

Weighted average number of shares outstanding		51,264		50,282		51,144		50,108
Effect of dilutive securities:
Options on common stock		592		611		666		614
2 3/8% Convertible Senior Subordinated Notes		2,944		1,492		3,044		1,406
Restricted stock awards and other		160		153		174		176

Total shares and dilutive securities		54,960		52,538		55,028		52,304

Diluted earnings per share	$	1.67	$	0.88	$	4.15	$	2.37

Our calculation of diluted earnings per share for the three and nine months ended September 30, 2011 excludes 184,529 shares and 179,977 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards due to their antidilutive effect. Our calculation of diluted earnings per share for the three and nine months ended September 30, 2010 excludes 454,681 shares and 441,488 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards due to their antidilutive effect.

5. BUSINESS ACQUISITIONS AND GOODWILL

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

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


	Three Months		Nine Months
	Ended		Ended
	September 30,		September 30,
	2010		2010
	(Unaudited)
Revenues	$	618,348	$	1,797,205
Net income attributable to Oil States International, Inc.		47,068		124,639
Net income per share attributable to Oil States International, Inc.
common stockholders
Basic	$	0.94	$	2.49
Diluted	$	0.90	$	2.38

Included in the pro forma results above for the three and nine months ended September 30, 2010 are (1) depreciation of the increased recorded fair value of property, plant and equipment acquired as part of The MAC, totaling $2.2 million and $6.6 million, respectively, net of tax, or $0.04 and $0.13 per diluted share, respectively; (2) amortization expense for intangibles acquired as part of the acquisition of The MAC, totaling $1.5 million and $4.5 million, respectively, net of tax, or $0.03 and $0.09 per diluted share, respectively; and (3) interest expense of $2.7 million and $8.1 million, respectively, net of tax, or $0.05 and $0.15 per diluted share, respectively.

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

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

During the three and nine months ended September 30, 2011, the Company recognized $0.2 million and $1.6 million, respectively, of costs in connection with these acquisitions that were expensed.

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


	Well Site Services
	Rental			Drilling and									Offshore			Tubular
	Tools			Other			Subtotal			Accommodations			Products			Services			Total
Balance as of December 31, 2009
Goodwill	$	169,311		$	22,767		$	192,078		$	58,358		$	85,599		$	62,863		$	398,898
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—			—			(62,863	)		(180,158	)

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

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

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

		75,506			—			75,506			299,062			100,654			—			475,222
Goodwill acquired		—			—			—			757			315			—			1,072
Foreign currency translation and other changes		(623	)		—			(623	)		(10,038	)		(9	)		—			(10,670	)

		74,883			—			74,883			289,781			100,960			—			465,624

Balance as of September 30, 2011
Goodwill		169,411			22,767			192,178			289,781			100,960			62,863			645,782
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—			—			(62,863	)		(180,158	)

	$	74,883		$	—		$	74,883		$	289,781		$	100,960		$	—		$	465,624

6. DEBT

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


	September 30, 2011		December 31, 2010
	(Unaudited)
U.S. revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million and with an average interest rate of 2.8% for the nine month period ended September 30, 2011	$	—	$	345,600
U.S. term loan, which matures December 10, 2015, of $200 million; 1.25% of aggregate principal repayable per quarter in 2011, 2.5% per quarter thereafter; average interest rate of 2.6% for the nine month period ended September 30, 2011		192,500		200,000
Canadian revolving credit facility, which matures December 10, 2015, with available commitments up to $250 million and with an average interest rate of 3.9% for the nine month period ended September 30, 2011		—		62,538
Canadian term loan, which matures December 10, 2015, of $100 million; 1.25% of aggregate principal repayable per quarter in 2011, 2.5% per quarter thereafter; average interest rate of 3.6% for the nine month period ended September 30, 2011		93,026		100,955
Australian revolving credit facility, which matures October 15, 2013, with available commitments up to A$150 million and with an average interest rate of 7.0% for the nine months ended September 30, 2011		30,206		25,305
6 1/2% senior unsecured notes — due June 2019		600,000		—
23/8% contingent convertible senior subordinated notes, net — due 2025		168,885		163,108
Subordinated unsecured notes payable to sellers of businesses, fixed interest rate of 6%, which mature in 2012		4,000		4,000
Capital lease obligations and other debt		9,381		11,401

Total debt		1,097,998		912,907
Less: Current maturities		197,522		181,175

Total long-term debt and capitalized leases	$	900,476	$	731,732

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

The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our 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	%

In connection with the note offering, the Company, the Guarantors of the 6 1/2% Notes and the initial purchasers entered into a registration rights agreement at the closing of the offering. Pursuant to the registration rights agreement, the Company and the Guarantors agreed, subject to certain exceptions, to use commercially reasonable efforts to file with the Commission and cause to become effective a registration statement relating to an offer to exchange the 6 1/2% Notes for an issue of Commission-registered 6 1/2% Notes with substantially identical terms. All of the 6 1/2% Notes were so exchanged in October 2011.

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 senior secured credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.

As of September 30, 2011, we classified the $175.0 million principal amount of our 2 3/8% Contingent Convertible Senior Subordinated Notes (2 3/8% Notes), net of unamortized discount, as of current liability based on the first put/call date of July 6, 2012. If certain contingent conversion thresholds based on the Company’s stock price are met and a 2 3/8% Note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they will receive cash up to $1,000 for each 2 3/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% Notes of 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. As of September 30, 2011, 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 September 30, 2011 measurement date. During the quarter ended September 30, 2011, a holder converted 10 of our 2 3/8% Notes (principal amount of $10,000) for cash of $10,000 plus 189 shares of our common stock.

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


	September 30,		December 31,
	2011		2010
Carrying amount of the equity component in additional paid-in capital	$	28,434	$	28,449


Principal amount of the liability component	$	174,990	$	175,000
Less: Unamortized discount		6,105		11,892

Net carrying amount of the liability component	$	168,885	$	163,108

Unamortized Discount — 2 3/8% Notes

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2011		2010		2011		2010
Interest expense	$	3,003	$	2,867	$	8,904	$	8,505


	September 30, 2011
Remaining period over which discount will be amortized	9 months
Conversion price	$	31.75
Number of shares to be delivered upon conversion (1)		2,074,918
Conversion value in excess of principal amount (in thousands) (1)	$	105,655
Derivative transactions entered into in connection with the convertible notes	None


(1)		Calculation is based on the Company’s September 30, 2011 closing stock price of $50.92.

On July 13, 2011, The MAC entered into a A$150 million revolving loan facility governed by a Facility Agreement (the Facility Agreement) between The MAC and National Australia Bank Limited, 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 September 30, 2011, we had $30.2 million outstanding under the Australian facility.

The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, and debt instruments. The Company believes that the carrying values of these instruments, other than our 2 3/8%

Notes 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 in active markets (Level 1 fair value measurements). The carrying and fair values of these notes were as follows (in thousands):


				September 30, 2011				December 31, 2010
	Interest			Carrying		Fair		Carrying		Fair
	Rate			Value		Value		Value		Value
6 1/2% Notes
Principal amount due 2019		6 1/2	%	$	600,000	$	599,628	$	—	$	—

2 3/8% Notes
Principal amount due 2025		2 3/8	%	$	174,990	$	296,188	$	175,000	$	354,057
Less: unamortized discount					6,105		—		11,892		—

Net value				$	168,885	$	296,188	$	163,108	$	354,057

As of September 30, 2011, the Company had approximately $118.9 million of cash and cash equivalents and $729.6 million of the Company’s U.S. and Canadian revolving credit and term loan facilities available for future financing needs. The Company also had availability totaling A$119.0 million under its Australian credit facility. As of September 30, 2011, we had $23.7 million of outstanding letters of credit drawn under these credit facilities.

Interest expense on the condensed consolidated statements of income is net of capitalized interest of $1.6 million and $4.0 million, respectively, for the three and nine months ended September 30, 2011 and less than $0.1 and $0.1 million, respectively, for the three and nine months ended September 30, 2010.

7. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING

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


	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30,						ENDED SEPTEMBER 30,
	2011			2010			2011			2010
Net income	$	92,072		$	46,478		$	228,892		$	124,502
Other comprehensive income (loss):
Foreign currency translation adjustment		(127,085	)		23,441			(61,370	)		8,238

Total other comprehensive income/(loss)		(127,085	)		23,441			(61,370	)		8,238

Comprehensive income/(loss)		(35,013	)		69,919			167,522			132,740
Comprehensive income attributable to noncontrolling interest		(221	)		(132	)		(721	)		(436	)

Comprehensive income/(loss) attributable to Oil States International, Inc.	$	(35,234	)	$	69,787		$	166,801		$	132,304

The foreign currency translation adjustments are due primarily to the translation of our net Canadian and Australian accommodations assets at varying exchange rates.

Stock Activity


Shares of common stock outstanding — January 1, 2011	50,838,863
Shares issued upon exercise of stock options and vesting of stock awards	604,102
Repurchase of shares — transferred to treasury	(209,300	)
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury	(33,952	)
Shares issued upon redemption of 2 3/8% Notes	189

Shares of common stock outstanding — September 30, 2011	51,199,902

8. STOCK BASED COMPENSATION

During the first nine months of 2011, we granted restricted stock awards totaling 214,184 shares valued at a total of $16.1 million. Of the restricted stock awards granted in the first nine months of 2011, a total of 197,404 awards vest in four equal annual installments starting in February 2012. A total of 184,700 stock options with a ten-year term were awarded in the nine months ended September 30, 2011 with an average exercise price of $75.37 and will vest in four equal annual installments starting in February 2012.

Stock based compensation pre-tax expense recognized in the three month periods ended September 30, 2011 and 2010 totaled $3.6 million and $2.8 million, or $0.05 and $0.04 per diluted share after tax, respectively. Stock based compensation pre-tax expense recognized in the nine month periods ended September 30, 2011 and 2010 totaled $10.8 million and $9.7 million, or $0.15 and $0.13 per diluted share after tax, respectively. The total fair value of restricted stock awards that vested during the nine months ended September 30, 2011 and 2010 was $12.9 million and $7.7 million, respectively. At September 30, 2011, $27.4 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 nine months ended September 30, 2011 totaled $36.5 million, or 28.4% of pretax income, and $88.8 million, or 27.9% of pretax income, respectively, compared to $20.6 million, or 30.7% of pretax income, and $54.0 million, or 30.2% of pretax income, respectively, for the three and nine months ended September 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

10. SEGMENT AND RELATED INFORMATION

In accordance with current accounting standards regarding disclosures about segments of an enterprise and related information, the Company has identified the following reportable segments: well site services, accommodations, offshore products and tubular services. The Company’s reportable segments represent strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. The separate business lines within the well site services segment have been disclosed to provide additional detail for that segment. Results of a portion of our accommodations segment supporting traditional oil and natural gas drilling activities are somewhat seasonal with increased activity occurring in the winter drilling season.

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


								Equity in
	Revenues from							income/(loss) of
	unaffiliated		Depreciation and		Operating income			unconsolidated
	customers		amortization		(loss)			affiliates			Capital expenditures		Total assets
Three months ended September 30, 2011
Well site services —
Rental tools	$	127,217	$	10,364	$	32,939		$	—		$	24,155	$	435,281
Drilling services		45,550		5,033		7,973			—			8,890		124,610

Total well site services		172,767		15,397		40,912			—			33,045		559,891
Accommodations		227,783		27,395		71,727			—			101,604		1,662,776
Offshore products		139,525		3,421		24,854			(487	)		4,416		602,636
Tubular services		362,546		515		17,934			283			1,709		527,964
Corporate and eliminations		—		201		(10,963	)		—			138		83,745

Total	$	902,621	$	46,929	$	144,464		$	(204	)	$	140,912	$	3,437,012


								Equity in
	Revenues from							income/(loss) of
	unaffiliated		Depreciation and		Operating income			unconsolidated
	customers		amortization		(loss)			affiliates		Capital expenditures		Total assets
Three months ended September 30, 2010
Well site services —
Rental tools	$	91,856	$	9,839	$	14,446		$	—	$	11,308	$	369,050
Drilling services		33,869		5,807		487			—		2,082		109,339

Total well site services		125,725		15,646		14,933			—		13,390		478,389
Accommodations		127,719		11,560		37,679			—		28,283		655,983
Offshore products		102,376		2,739		14,570			—		2,130		494,235
Tubular services		232,527		291		12,003			80		964		432,977
Corporate and eliminations		—		174		(8,795	)		—		108		27,325

Total	$	588,347	$	30,410	$	70,390		$	80	$	44,875	$	2,088,909


								Equity in
	Revenues from							income/(loss) of
	unaffiliated		Depreciation and		Operating income			unconsolidated
	customers		amortization		(loss)			affiliates			Capital expenditures		Total assets
Nine months ended September 30, 2011
Well site services —
Rental tools	$	347,406	$	30,459	$	82,432		$	—		$	59,650	$	435,281
Drilling services		119,653		14,773		16,578			—			21,812		124,610

Total well site services		467,059		45,232		99,010			—			81,462		559,891
Accommodations		627,824		80,143		178,451			2			270,519		1,662,776
Offshore products		399,709		10,112		60,374			(715	)		11,990		602,636
Tubular services		988,787		1,243		47,936			562			6,860		527,964
Corporate and eliminations		—		588		(31,367	)		—			334		83,745

Total	$	2,483,379	$	137,318	$	354,404		$	(151	)	$	371,165	$	3,437,012


								Equity in
	Revenues from							income/(loss) of
	unaffiliated		Depreciation and		Operating income			unconsolidated
	customers		amortization		(loss)			affiliates		Capital expenditures		Total assets
Nine months ended September 30, 2010
Well site services —
Rental tools	$	238,477	$	30,753	$	29,219		$	—	$	28,334	$	369,050
Drilling services		98,408		18,670		(2,565	)		—		6,619		109,339

Total well site services		336,885		49,423		26,654			—		34,953		478,389
Accommodations		395,208		32,842		116,347			—		73,724		655,983
Offshore products		311,375		8,314		43,278			—		8,110		494,235
Tubular services		671,757		976		27,514			144		3,807		432,977
Corporate and eliminations		—		533		(25,845	)		—		358		27,325

Total	$	1,715,225	$	92,088	$	187,948		$	144	$	120,952	$	2,088,909

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 by Oil States International, Inc. 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 for each of the three and nine month periods ended September 30, 2011 and 2010, condensed consolidating balance sheets as September 30, 2011 and December 31, 2010 and the statements of cash flows for each of the nine months ended September 30, 2011 and 2010 of (a) the Company parent/guarantor, (b) Acute Technological Services, Inc., Capstar Drilling LP, L.L.C., Capstar Holding, L.L.C., Capstar Drilling, Inc., Capstar Drilling GP, L.L.C., General Marine Leasing, LLC, Oil States Energy Services, Inc., Oil States Management, Inc., Oil States Industries, Inc., Oil States Skagit SMATCO, LLC, PTI Group USA LLC, PTI Mars Holdco 1, LLC, 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.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Statements of Income


	Three Months Ended September 30, 2011
	Oil States						Other						Consolidated Oil
	International,						Subsidiaries						States
	Inc. (Parent/			Guarantor			(Non-			Consolidating			International,
	Guarantor)			Subsidiaries			Guarantors)			Adjustments			Inc.
	(In thousands)
REVENUES
Operating revenues	$	—		$	630,169		$	272,640		$	(188	)	$	902,621
Intercompany revenues		—			9,399			56			(9,455	)		—

Total revenues		—			639,568			272,696			(9,643	)		902,621


OPERATING EXPENSES
Cost of sales and services		—			514,381			153,080			(1,606	)		665,855
Intercompany cost of sales and services		—			7,842			58			(7,900	)		—
Selling, general and administrative expenses		10,053			21,129			14,248			—			45,430
Depreciation and amortization expense		200			19,846			26,888			(5	)		46,929
Other operating (income)/expense		710			(61	)		(706	)		—			(57	)

Operating income (loss)		(10,963	)		76,431			79,128			(132	)		144,464

Interest expense, net of capitalized interest		(16,338	)		(288	)		(18,085	)		17,951			(16,760	)
Interest income		5,071			7			13,047			(17,951	)		174
Equity in earnings (loss) of unconsolidated affiliates		113,414			10,465			(487	)		(123,596	)		(204	)
Other income		—			245			640			—			885

Income before income taxes		91,184			86,860			74,243			(123,728	)		128,559
Income tax provision		667			(18,939	)		(18,215	)		—			(36,487	)

Net income		91,851			67,921			56,028			(123,728	)		92,072
Less: Net income attributable to non-controlling interest		—			—			216			5			221

Net income attributable to Oil States International, Inc.	$	91,851		$	67,921		$	55,812		$	(123,733	)	$	91,851

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Statements of Income


	Three Months Ended September 30, 2010
	Oil States						Other						Consolidated Oil
	International,						Subsidiaries						States
	Inc. (Parent/			Guarantor			(Non-			Consolidating			International,
	Guarantor)			Subsidiaries			Guarantors)			Adjustments			Inc.
	(In thousands)
REVENUES
Operating revenues	$	—		$	426,179		$	162,168		$	—		$	588,347
Intercompany revenues		—			3,544			430			(3,974	)		—

Total revenues		—			429,723			162,598			(3,974	)		588,347


OPERATING EXPENSES
Cost of sales and services		—			349,840			100,172			(1,410	)		448,602
Intercompany cost of sales and services		—			2,415			149			(2,564	)		—
Selling, general and administrative expenses		8,173			20,547			8,422			—			37,142
Depreciation and amortization expense		174			17,728			12,510			(2	)		30,410
Other operating expense		448			222			1,133			—			1,803

Operating income (loss)		(8,795	)		38,971			40,212			2			70,390

Interest expense		(3,295	)		(144	)		(131	)		36			(3,534	)
Interest income		—			3			167			(36	)		134
Equity in earnings of unconsolidated affiliates		57,793			3,860			—			(61,573	)		80
Other income/(expense)		—			51			(34	)		—			17

Income before income taxes		45,703			42,741			40,214			(61,571	)		67,087
Income tax provision		643			(9,923	)		(11,329	)		—			(20,609	)

Net income		46,346			32,818			28,885			(61,571	)		46,478
Less: Net income attributable to non-controlling interest		—			—			130			2			132

Net income attributable to Oil States International, Inc.	$	46,346		$	32,818		$	28,755		$	(61,573	)	$	46,346

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Statements of Income


	Nine Months Ended September 30, 2011
	Oil States						Other						Consolidated Oil
	International,						Subsidiaries						States
	Inc. (Parent/			Guarantor			(Non-			Consolidating			International,
	Guarantor)			Subsidiaries			Guarantors)			Adjustments			Inc.
	(In thousands)
REVENUES
Operating revenues	$	—		$	1,736,401		$	747,166		$	(188	)	$	2,483,379
Intercompany revenues		—			12,699			588			(13,287	)		—

Total revenues		—			1,749,100			747,754			(13,475	)		2,483,379


OPERATING EXPENSES
Cost of sales and services		—			1,427,704			432,533			(3,206	)		1,857,031
Intercompany cost of sales and services		—			9,693			440			(10,133	)		—
Selling, general and administrative expenses		28,987			60,532			42,383			—			131,902
Depreciation and amortization expense		588			60,652			76,086			(8	)		137,318
Other operating (income)/expense		1,791			(219	)		1,150			2			2,724

Operating income (loss)		(31,366	)		190,738			195,162			(130	)		354,404

Interest expense, net of capitalized interest		(35,810	)		(976	)		(58,520	)		55,765			(39,541	)
Interest income		10,288			6,569			40,329			(55,764	)		1,422
Equity in earnings of unconsolidated affiliates		283,096			23,446			(714	)		(305,979	)		(151	)
Other income/(expense)		—			669			846			—			1,515

Income before income taxes		226,208			220,446			177,103			(306,108	)		317,649
Income tax provision		1,963			(47,893	)		(42,827	)		—			(88,757	)

Net income		228,171			172,553			134,276			(306,108	)		228,892
Less: Net income attributable to non-controlling interest		—			—			693			28			721

Net income attributable to Oil States International, Inc.	$	228,171		$	172,553		$	133,583		$	(306,136	)	$	228,171

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Statements of Income


	Nine Months Ended September 30, 2010
	Oil States						Other						Consolidated Oil
	International,						Subsidiaries						States
	Inc. (Parent/			Guarantor			(Non-			Consolidating			International
	Guarantor)			Subsidiaries			Guarantors			Adjustments			Inc.
	(In thousands)
REVENUES
Operating revenues	$	—		$	1,179,234		$	535,991		$			$	1,715,225
Intercompany revenues		—			21,751			557			(22,308	)		—

Total revenues		—			1,200,985			536,548			(22,308	)		1,715,225


OPERATING EXPENSES
Cost of sales and services		—			995,882			334,884			(6,172	)		1,324,594
Intercompany cost of sales and services		—			15,933			203			(16,136	)		—
Selling, general and administrative expenses		24,966			58,549			25,964			—			109,479
Depreciation and amortization expense		532			55,877			35,684			(5	)		92,088
Other operating (income)/expense		347			(42	)		811			—			1,116

Operating income (loss)		(25,845	)		74,786			139,002			5			187,948

Interest expense		(9,794	)		(435	)		(380	)		104			(10,505	)
Interest income		—			50			369			(103	)		316
Equity in earnings of unconsolidated affiliates		157,843			21,016			—			(178,715	)		144
Other income/(expense)		—			1,001			(414	)		—			587

Income before income taxes		122,204			96,418			138,577			(178,709	)		178,490
Income tax provision		1,862			(17,241	)		(38,609	)		—			(53,988	)

Net income		124,066			79,177			99,968			(178,709	)		124,502
Less: Net income attributable to non-controlling interest		—			—			436			—			436

Net income attributable to Oil States International, Inc.	$	124,066		$	79,177		$	99,532		$	(178,709	)	$	124,066

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Balance Sheets


	September 30, 2011
	Oil States						Other						Consolidated Oil
	International,						Subsidiaries						States
	Inc. (Parent/			Guarantor			(Non-			Consolidating			International,
	Guarantor)			Subsidiaries			Guarantors)			Adjustments			Inc.
				(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	30,317		$	10,915		$	77,619		$	—		$	118,851
Accounts receivable, net		—			351,200			228,249			—			579,449
Inventories, net		—			493,913			108,943			(26	)		602,830
Prepaid expenses and other current assets		1,442			11,210			15,062			—			27,714

Total current assets		31,759			867,238			429,873			(26	)		1,328,844

Property, plant and equipment, net		1,715			437,321			1,016,903			(132	)		1,455,807
Goodwill, net		—			172,375			293,249			—			465,624
Other intangible assets, net		—			31,399			93,765			—			125,164
Investments in unconsolidated affiliates		1,981,524			220,157			1,020			(2,195,750	)		6,951
Long-term intercompany receivables (payables)		680,168			(326,652	)		(360,480	)		6,964			—
Other noncurrent assets		41,927			437			12,258			—			54,622

Total assets	$	2,737,093		$	1,402,275		$	1,486,588		$	(2,188,944	)	$	3,437,012


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	28,727		$	201,964		$	99,213		$	(1	)	$	329,903
Income taxes		(62,762	)		63,999			5,646			—			6,883
Current portion of long-term debt and capitalized leases		186,397			2,432			8,693			—			197,522
Deferred revenue		—			47,467			20,140			—			67,607
Other current liabilities		—			5,592			102			—			5,694

Total current liabilities		152,362			321,454			133,794			(1	)		607,609

Long-term debt and capitalized leases		775,032			9,463			115,981			—			900,476
Deferred income taxes		(9,328	)		56,758			51,258			—			98,688
Other noncurrent liabilities		9,131			10,152			656			(449	)		19,490

Total liabilities		927,197			397,827			301,689			(450	)		1,626,263

Stockholders’ equity		1,809,896			1,004,448			1,184,241			(2,188,689	)		1,809,896
Non-controlling interest		—			—			658			195			853

Total stockholders’ equity		1,809,896			1,004,448			1,184,899			(2,188,494	)		1,810,749

Total liabilities and stockholders’ equity	$	2,737,093		$	1,402,275		$	1,486,588		$	(2,188,944	)	$	3,437,012

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Balance Sheets


	December 31, 2010
	Oil States						Other						Consolidated Oil
	International,						Subsidiaries						States
	Inc. (Parent/			Guarantor			(Non-			Consolidating			International,
	Guarantor			Subsidiaries			Guarantors)			Adjustments			Inc.
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	(180	)	$	1,170		$	95,360		$	—		$	96,350
Accounts receivable, net		852			303,771			174,116			—			478,739
Inventories, net		—			429,427			72,008			—			501,435
Prepaid expenses and other current assets		6,243			10,796			6,441			—			23,480

Total current assets		6,915			745,164			347,925			—			1,100,004

Property, plant and equipment, net		1,930			394,335			856,422			(30	)		1,252,657
Goodwill, net		—			171,135			304,087			—			475,222
Other intangible assets, net		—			34,894			104,527			—			139,421
Investments in unconsolidated affiliates		1,723,711			200,652			569			(1,918,995	)		5,937
Long-term intercompany receivables (payables)		567,560			(50,475	)		(524,050	)		6,965			—
Other noncurrent assets		33,562			336			8,860			—			42,758

Total assets	$	2,333,678		$	1,496,041		$	1,098,340		$	(1,912,060	)	$	3,015,999


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	28,650		$	202,503		$	73,585		$	1		$	304,739
Income taxes		(31,363	)		30,919			5,048			—			4,604
Current portion of long-term debt and capitalized leases		173,122			2,424			5,629			—			181,175
Deferred revenue		—			44,981			15,866			—			60,847
Other current liabilities		—			1,727			1,083			—			2,810

Total current liabilities		170,409			282,554			101,211			1			554,175

Long-term debt and capitalized leases		536,747			9,774			185,211			—			731,732
Deferred income taxes		(10,816	)		48,642			43,372			—			81,198
Other noncurrent liabilities		9,432			10,141			837			(449	)		19,961

Total liabilities		705,772			351,111			330,631			(448	)		1,387,066

Stockholders’ equity		1,627,906			1,144,930			766,848			(1,911,778	)		1,627,906
Non-controlling interest		—			—			861			166			1,027

Total stockholders’ equity		1,627,906			1,144,930			767,709			(1,911,612	)		1,628,933

Total liabilities and stockholders’ equity	$	2,333,678		$	1,496,041		$	1,098,340		$	(1,912,060	)	$	3,015,999

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Statements of Cash Flows


	Nine Months Ended September 30, 2011
	Oil States						Other						Consolidated Oil
	International,						Subsidiaries						States
	Inc. (Parent/			Guarantor			(Non-			Consolidating			International,
	Guarantor)			Subsidiaries			Guarantors)			Adjustments			Inc.
	(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(66,088	)	$	169,441		$	119,831			(110	)	$	223,074

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(334	)		(98,697	)		(272,244	)		110			(371,165	)
Acquisitions of businesses, net of cash acquired		—			(212	)		—			—			(212	)
Other, net		—			(1,388	)		565			—			(823	)

Net cash provided by (used in) investing activities		(334	)		(100,297	)		(271,679	)		110			(372,200	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		(346,742	)		—			(49,166	)		—			(395,908	)
6 1 / 2% senior notes issued		600,000			—			—			—			600,000
Term loan repayments		(7,500	)		—			(3,746	)		—			(11,246	)
Debt and capital lease payments		(14	)		(344	)		(608	)		—			(966	)
Issuance of common stock from share-based payment arrangements		11,559			—			—			—			11,559
Purchase of treasury stock		(12,632	)		—			—			—			(12,632	)
Excess tax benefits from share-based payment arrangements		7,966			—			—			—			7,966
Payment of financing costs		(13,129	)		—			(23	)		—			(13,152	)
Proceeds from (funding of) accounts and notes with affiliates, net		(140,039	)		(58,937	)		198,976			—			—
Other, net		(2,550	)		—			(1	)		—			(2,551	)

Net cash provided by (used in) financing activities		96,919			(59,281	)		145,432			—			183,070

Effect of exchange rate changes on cash		—			—			(11,325	)		—			(11,325	)

Net change in cash and cash equivalents from continuing operations		30,497			9,863			(17,741	)		—			22,619
Net cash used in discontinued operations operating activities		—			(118	)		—			—			(118	)
Cash and cash equivalents, beginning of period		(180	)		1,170			95,360			—			96,350


Cash and cash equivalents, end of period	$	30,317		$	10,915		$	77,619			—		$	118,851

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)

Condensed Consolidating Statements of Cash Flows


	Nine Months Ended September 30, 2010
	Oil States						Other					Consolidated Oil
	International,						Subsidiaries					States
	Inc. (Parent/			Guarantor			(Non-			Consolidating		International,
	Guarantor)			Subsidiaries			Guarantors)			Adjustments		Inc.
				(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(63,754	)	$	74,540		$	142,599			—	$	153,385

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(358	)		(44,756	)		(75,838	)		—		(120,952	)
Other, net		(1	)		1,878			48			—		1,925

Net cash provided by (used in) investing activities		(359	)		(42,878	)		(75,790	)		—		(119,027	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Debt and capital lease payments		(22	)		(296	)		(39	)		—		(357	)
Issuance of common stock from share-based payment arrangements		14,165			—			—			—		14,165
Excess tax benefits from share-based payment arrangements		2,126			—			—			—		2,126
Proceeds from (funding of) accounts and notes with affiliates, net		41,865			(29,504	)		(12,361	)		—		—
Other, net		(1,404	)		2			(4	)		—		(1,406	)

Net cash provided by (used in) financing activities		56,730			(29,798	)		(12,404	)		—		14,528

Effect of exchange rate changes on cash		—			—			(143	)		—		(143	)

Net change in cash and cash equivalents from continuing operations		(7,383	)		1,864			54,262			—		48,743
Net cash used in discontinued operations operating activities		—			(105	)		—			—		(105	)
Cash and cash equivalents, beginning of period		7,148			148			82,446			—		89,742


Cash and cash equivalents, end of period	$	(235	)	$	1,907		$	136,708			—	$	138,380

Cautionary Statement Regarding Forward-Looking Statements

This quarterly report on Form 10-Q contains “certain forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Some of the information in the quarterly report may contain “forward-looking statements.” The “forward-looking statements” can be identified by the use of forward-looking terminology including “may,” “expect,” “anticipate,” “estimate,” “continue,” “believe,” or other similar words. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to “Part I, Item 1A. Risk Factors” and the financial statement line item discussions set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2010 Form 10-K filed with the Commission on February 22, 2011. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations and are not guarantees of future performance. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.

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


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

You should read the following discussion and analysis together with our condensed consolidated financial statements and the notes to those statements included elsewhere in this quarterly report on Form 10-Q.

Overview

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

During the quarter ended September 30, 2011, crude oil prices continued to exhibit volatility due to concerns about potential decreases in demand if the global economic recovery continues to lose momentum due to prolonged levels of high unemployment and weak consumer confidence and spending, along with fiscal uncertainty in the United States and Europe.

Our Business Segments

Our accommodations business is predominantly located in northern Alberta, Canada and Queensland, Australia and derives most of its business from resource companies who are developing and producing oil sands and coal

resources and, to a lesser extent, other mineral resources. A significant portion of our accommodations revenues is generated by our large-scale lodge and village facilities. Where traditional accommodations and infrastructure are not accessible or cost effective, our semi-permanent lodge and village facilities provide comprehensive accommodations services similar to those found in an urban hotel. We typically contract our facilities to our customers on a fee per day covering lodging and meals that is based on the duration of their needs which can range from several months to several years. In addition, we provide shorter-term remote site accommodations in smaller configurations utilizing our modular, mobile camp assets.

Generally, our customers for oil sands and mining accommodations are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of 10 to 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 have led to extensions of existing accommodations contracts and incremental accommodations contracts for us in Canada. In addition, several major oil companies and national oil companies have acquired oil sands leases over the past twelve months that should bode well for future oil sands investment and, as a result, demand for oil sands accommodations. Our Australian accommodations business is significantly influenced by increased metallurgical coal demand, especially from China and India. Metallurgical coal prices in China have strengthened recently and Chinese metallurgical coal demand is expected to increase for the second half of 2011 compared to the first half and likely result in another annual metallurgical coal import record. We are expanding our Australian accommodations capacity to meet increasing demand. Accommodations deployed to support onshore U.S. drilling activity in several of the active shale play regions have also favorably affected our results.

Another factor that influences the financial results for our accommodations segment is the exchange rate between the U.S. dollar and the Canadian dollar and, to a lesser extent, the exchange rate between the U.S. dollar and the Australian dollar. Our accommodations segment has derived a majority of its revenues and operating income in Canada denominated in Canadian dollars. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. For the first nine months of 2011, the Canadian dollar was valued at an average exchange rate of U.S. $1.02 compared to U.S. $0.97 for the first nine months of 2010, an increase of 5%. This strengthening of the Canadian dollar had a positive impact on the translation of earnings generated from our Canadian subsidiaries and, therefore, the financial results of our accommodations segment. For the first nine months of 2011, the Australian dollar was valued at an average exchange rate of U.S. $1.04 compared to U.S. $0.90 for the first nine months of 2010, an increase of 16%.

Our offshore products segment is also influenced significantly by our customers’ longer-term outlook for energy prices and provides highly engineered products for offshore oil and natural gas drilling and production systems and facilities. Sales of our offshore products and services depend primarily upon development of infrastructure for offshore production systems and subsea pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels. In this segment, we are particularly influenced by global deepwater drilling and production spending, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices.

New order activity in our offshore products segment was limited beginning in the fourth quarter of 2008 and continued to decline throughout 2009 due to project postponements, cancellations and deferrals by customers as a result of the global economic recession and reduced oil prices. This reduction in order activity led to declines in our offshore products backlog and decreased revenues and profits in the first nine months of 2010. With the improvement in oil prices over the last two years along with the improved outlook for long-term oil demand, we began experiencing increased bidding and quoting activity for our offshore products in the second half of 2010 that continued throughout the first nine months of 2011. As a result of this increased activity, our backlog in offshore products has increased from $264.4 million as of September 30, 2010 to $513.9 million as of September 30, 2011. We anticipate global deepwater spending to continue with particular opportunities coming from Brazil, West Africa, South East Asia and Australia over the next twelve months.

Our well site services and tubular services segments are significantly influenced by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada. Until recently, this activity has been primarily driven by spending for natural gas exploration and production, particularly in the shale play regions of the U.S. using horizontal drilling and completion techniques. However, with the rise in oil prices, the lower natural gas prices and the advancement of horizontal drilling and completion techniques, activity in North America is beginning to shift to a greater proportion of oil and liquids-rich gas drilling. The oil rig count in the U.S. now totals approximately 1,100 rigs, the highest count in over 20 years, comprising approximately 54% of total U.S. drilling activity.

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

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

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


	Average Drilling Rig Count for
	Three Months Ended				Nine Months Ended
	September 30,		September 30,		September 30,		September 30,
	2011		2010		2011		2010
U.S. Land		1,911		1,604		1,800		1,458
U.S. Offshore		34		18		30		34

Total U.S.		1,945		1,622		1,830		1,492
Canada		443		361		406		332

Total North America		2,388		1,983		2,236		1,824

The average North American rig count for the three months ended September 30, 2011 increased by 405 rigs, or 20%, compared to the three months ended September 30, 2010 largely due to growth in the U.S. land rig count.

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

During 2010, U.S. mills began increasing production and imports of steel have increased in the first part of 2011, particularly goods imported from Canada and Korea followed by India, Mexico and Japan. We believe this increase in supply has been in response to the approximately 20% year-over-year increase in the drilling rig count in the U.S.

Other Factors that Influence our Business

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

Drilling activity in the U.S. Gulf of Mexico remains well below historical levels as a result of unprecedented events in the U.S. Gulf of Mexico following the Macondo well incident and resultant oil spill. A rescission of a moratorium on offshore drilling activity was effective in late 2010; however, increases in activity have been delayed by adjustments in operating procedures, compliance certifications, and lead times for permits and inspections, as a result of changes in the regulatory environment. In

addition, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production. Uncertainties and delays caused by the new regulatory environment have had and are expected to continue to have an overall negative effect on Gulf of Mexico drilling activity.

We continue to monitor the global economy, the demand for crude oil, coal and natural gas prices and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. We currently expect that our 2011 capital expenditures will total approximately $635 million compared to 2010 capital expenditures of $182 million. A portion of this $635 million in spending may carry over into early 2012 depending upon delivery schedules and other factors. Our 2011 capital expenditures include funding to expand several of our Canadian and Australian accommodations facilities, to add incremental equipment in our rental tools business, to increase our fleet of modular, mobile camp assets in Canada and the U.S. and to complete projects in progress at December 31, 2010, including (i) the construction of the Henday Lodge accommodations facility in the Canadian oil sands, (ii) continued expansion of our Wapasu Creek, Beaver River and Athabasca Lodge accommodations facilities in the Canadian oil sands and (iii) ongoing maintenance capital requirements. Approximately 75% of our total expected 2011 capital expenditures will be spent in the accommodations segment. In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on a careful evaluation of both the market outlook and industry fundamentals. In our tubular services segment, we remain focused on industry inventory levels, future drilling and completion activity and OCTG prices.

Consolidated Results of Operations (in millions)


	THREE MONTHS ENDED											NINE MONTHS ENDED
	SEPTEMBER 30,											SEPTEMBER 30,
							Variance											Variance
							2011 vs. 2010											2011 vs. 2010
	2011			2010			$		%			2011			2010			$		%
Revenues
Well site services -
Rental tools	$	127.2		$	91.8		$	35.4		39	%	$	347.4		$	238.5		$	108.9		46	%
Drilling services		45.6			33.9			11.7		35	%		119.7			98.4			21.3		22	%

Total well site services		172.8			125.7			47.1		37	%		467.1			336.9			130.2		39	%
Accommodations		227.8			127.7			100.1		78	%		627.8			395.2			232.6		59	%
Offshore products		139.5			102.4			37.1		36	%		399.7			311.4			88.3		28	%
Tubular services		362.5			232.5			130.0		56	%		988.8			671.7			317.1		47	%

Total	$	902.6		$	588.3		$	314.3		53	%	$	2,483.4		$	1,715.2		$	768.2		45	%

Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Rental tools	$	77.2		$	58.7		$	18.5		32	%	$	214.9		$	154.0		$	60.9		40	%
Drilling services		31.8			26.7			5.1		19	%		86.1			80.1			6.0		7	%

Total well site services		109.0			85.4			23.6		28	%		301.0			234.1			66.9		29	%
Accommodations		117.0			72.4			44.6		62	%		333.8			227.5			106.3		47	%
Offshore products		100.1			74.3			25.8		35	%		294.9			230.2			64.7		28	%
Tubular services		339.8			216.5			123.3		57	%		927.3			632.8			294.5		47	%

Total	$	665.9		$	448.6		$	217.3		48	%	$	1,857.0		$	1,324.6		$	532.4		40	%

Gross margin
Well site services -
Rental tools	$	50.0		$	33.1		$	16.9		51	%	$	132.5		$	84.5		$	48.0		57	%
Drilling services		13.8			7.2			6.6		92	%		33.6			18.3			15.3		84	%

Total well site services		63.8			40.3			23.5		58	%		166.1			102.8			63.3		62	%
Accommodations		110.8			55.3			55.5		100	%		294.0			167.7			126.3		75	%
Offshore products		39.4			28.1			11.3		40	%		104.8			81.2			23.6		29	%
Tubular services		22.7			16.0			6.7		42	%		61.5			38.9			22.6		58	%

Total	$	236.7		$	139.7		$	97.0		69	%	$	626.4		$	390.6		$	235.8		60	%

Gross margin as a percentage of revenues
Well site services -
Rental tools		39	%		36	%							38	%		35	%
Drilling services		30	%		21	%							28	%		19	%
Total well site services		37	%		32	%							36	%		31	%
Accommodations		49	%		43	%							47	%		42	%
Offshore products		28	%		27	%							26	%		26	%
Tubular services		6	%		7	%							6	%		6	%
Total		26	%		24	%							25	%		23	%

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

We reported net income attributable to the Company for the quarter ended September 30, 2011 of $91.9 million, or $1.67 per diluted share. These results compare to net income attributable to the Company of $46.3 million, or $0.88 per diluted share, reported for the quarter ended September 30, 2010.

Revenues. Consolidated revenues increased $314.3 million, or 53%, in the third quarter of 2011 compared to the third quarter of 2010.

Our well site services segment revenues increased $47.1 million, or 37%, in the third quarter of 2011 compared to the third quarter of 2010. This increase was primarily due to increased rental tools revenues. Our rental tools revenues increased $35.4 million, or 39%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value rentals, increased rental tools utilization, additional capital investment in rental tools and better pricing. Our drilling services revenues increased $11.7 million, or 35%, in the third quarter of 2011 compared to the third quarter of 2010 primarily as a result of increases in pricing, with average day rates rising to $16.5 thousand per day in the third quarter of 2011 from $14.0 thousand per day in the third quarter of 2010, and increased utilization of our rigs. Utilization of our drilling rigs increased from an average of 73% for the third quarter of 2010 to an average of 88% for the third quarter of 2011.

Our accommodations segment reported revenues in the third quarter of 2011 that were $100.1 million, or 78%, above the third quarter of 2010. The increase in accommodations revenue resulted from the full quarter contribution from the recent acquisitions of The MAC and Mountain West and increased oil sands lodge revenues generated from increased room capacity. Revenues and average available rooms for our oil sands lodges increased 43% and 32%, respectively, in the third quarter of 2011 compared to the third quarter of 2010.

Our offshore products segment revenues increased $37.1 million, or 36%, in the third quarter of 2011 compared to the third quarter of 2010. This increase was primarily the result of higher revenues from production orders and connector products coupled with the contribution from the Acute acquisition.

Tubular services segment revenues increased $130.0 million, or 56%, in the third quarter of 2011 compared to the third quarter of 2010. This increase was the result of an increase in tons shipped from 118,500 in 2010 to 182,300 in 2011, an increase of 63,800 tons, or 54%, driven by increased drilling and completion activity.

Cost of Sales and Service. Our consolidated cost of sales increased $217.3 million, or 48%, in the third quarter of 2011 compared to the third quarter of 2010 as a result of increased cost of sales at our tubular services segment of $123.3 million, or 57%, an increase at our accommodations segment of $44.6 million, or 62%, an increase at our offshore products segment of $25.8 million, or 35%, and an increase at our well site services segment of $23.6 million, or 28%. These cost of sales increases were directly related to the increases in segment revenues. Our consolidated gross margin as a percentage of revenues increased from 24% in the third quarter of 2010 to 26% in the third quarter of 2011 primarily due to the increased proportion of relatively higher margin accommodations segment revenues in 2011 compared to 2010.

Our well site services segment cost of sales increased $23.6 million, or 28%, in the third quarter of 2011 compared to the third quarter of 2010 as a result of a $18.5 million, or 32%, increase in rental tools services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 32% in the third quarter of 2010 to 37% in the third quarter of 2011. Our rental tool gross margin as a percentage of revenues increased from 36% in the third quarter of 2010 to 39% in the third quarter of 2011 primarily due to a more favorable mix of higher value rentals and improved pricing along with higher fixed cost absorption as a result of increased rental tools utilization. Our drilling services cost of sales increased $5.1 million, or 19%, in the third quarter of 2011 compared to the third quarter of 2010. Our drilling services gross margin as a percentage of revenues increased from 21% in the third quarter of 2010 to 30% in the third quarter of 2011 primarily due to the increase in day rates.

Our accommodations segment cost of sales increased $44.6 million, or 62%, in the third quarter of 2011 compared to the third quarter of 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $12.9 million, or 19%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues and the strengthening of the Canadian dollar. Our

accommodations segment gross margin as a percentage of revenues increased from 43% in the third quarter of 2010 to 49% in the third quarter of 2011 primarily as a result of higher margins realized in our lodges and villages.

Our offshore products segment cost of sales increased $25.8 million, or 35%, in the third quarter of 2011 compared to the third quarter of 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues increased from 27% in the third quarter of 2010 to 28% in the third quarter of 2011 primarily due to product mix.

Our tubular services segment cost of sales increased $123.3 million, or 57%, in the third quarter of 2011 compared to the third quarter of 2010 primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues decreased from 7% in the third quarter of 2010 to 6% in the third quarter of 2011 primarily due to product mix.

Selling, General and Administrative Expenses. Selling, general and administrative expense (SG&A) increased $8.3 million, or 22%, in the third quarter of 2011 compared to the third quarter of 2010 due primarily to SG&A expense associated with the inclusion of The MAC, which added $3.1 million in SG&A expense in the third quarter of 2011, an increased accrual for incentive bonuses, an increase in stock-based compensation expense, an increase in advertising and trade show expenses and higher SG&A costs in our Canadian accommodations business due to the strengthening of the Canadian dollar. SG&A was 5.0% of revenues in the third quarter of 2011 compared to 6.3% of revenues in the third quarter of 2010.

Depreciation and Amortization. Depreciation and amortization expense increased $16.5 million, or 54%, in the third quarter of 2011 compared to the same period in 2010 due primarily to $12.7 million in depreciation and amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made during the previous twelve months largely related to investments made in our Canadian accommodations business.

Operating Income. Consolidated operating income increased $74.1 million, or 105%, in the third quarter of 2011 compared to the third quarter of 2010 primarily as a result of an increase in operating income from our well site services segment of $26.0 million, or 174%, largely due to the more favorable mix of higher value rentals, improved pricing and increased rental tools utilization. Operating income in our accommodations segment also increased due to the addition of operating income from The MAC and an increase in operating income from our oil sands lodges due to increased room capacity. Operating income from our offshore products segment increased $10.3 million, or 71%.

Interest Expense and Interest Income. Net interest expense increased by $13.2 million, or 388%, in the third quarter of 2011 compared to the third quarter of 2010 due to increased debt levels, including interest expense on the 6 1/2% Notes, and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our revolving credit and term loan facilities. The weighted average interest rate on borrowings outstanding under the Company’s revolving credit and term loan facilities was 3.1% in the third quarter of 2011 compared to 3.3% in the third quarter of 2010. The increase in the weighted average interest rate on the Company’s revolving credit facilities in 2011 compared to 2010 is primarily due to outstanding amounts borrowed under our Australian facility, which has a higher interest rate than the U.S. or Canadian facilities.

Income Tax Expense. Our income tax provision for the three months ended September 30, 2011 totaled $36.5 million, or 28.4% of pretax income, compared to income tax expense of $20.6 million, or 30.7% of pretax income, for the three months ended September 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

NINE MONTHS ENDED SEPTEMBER 30, 2011 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2010

We reported net income attributable to the Company for the nine months ended September 30, 2011 of $228.2 million, or $4.15 per diluted share. These results compare to net income attributable to the Company of $124.1 million, or $2.37 per diluted share, reported for the nine months ended September 30, 2010.

Revenues. Consolidated revenues increased $768.2 million, or 45%, in the first nine months of 2011 compared to the first nine months of 2010.

Our well site services segment revenues increased $130.2 million, or 39%, in the first nine months of 2011 compared to the first nine months of 2010. This increase was primarily due to significantly increased rental tools revenues. Our rental tools revenues increased $108.9 million, or 46%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value rentals, increased rental tools utilization, additional capital investment in rental tools and better pricing. Our drilling services revenues increased $21.3 million, or 22%, in the first nine months of 2011 compared to the first nine months of 2010 primarily as a result of increases in pricing, with average day rates rising to $16.1 thousand per day in the first nine months of 2011 from $14.0 thousand per day in the first nine months of 2010, and increased utilization of our rigs. Utilization of our drilling rigs increased from an average of 72% for the first nine months of 2010 to an average of 80% for the first nine months of 2011.

Our accommodations segment reported revenues in the first nine months of 2011 that were $232.6 million, or 59%, above the first nine months of 2010. The increase in accommodations revenue resulted from the contribution from the recent acquisitions of The MAC and Mountain West and increased oil sands lodge revenues generated from increased room capacity. Revenues and average available rooms for our oil sands lodges increased 41% and 29%, respectively, in the first nine months of 2011 compared to the first nine months of 2010.

Our offshore products segment revenues increased $88.3 million, or 28%, in the first nine months of 2011 compared to the first nine months of 2010. This increase was primarily the result of higher demand for production orders and elastomer products and contributions from the acquisition of Acute.

Tubular services segment revenues increased $317.1 million, or 47%, in the first nine months of 2011 compared to the first nine months of 2010. This increase was a result of an increase in tons shipped from 354,600 in 2010 to 510,000 in 2011, an increase of 155,400 tons, or 44%, driven by increased drilling and completion activity.

Cost of Sales and Service. Our consolidated cost of sales increased $532.4 million, or 40%, in the first nine months of 2011 compared to the first nine months of 2010 as a result of increased cost of sales at our tubular services segment of $294.5 million, or 47%, an increase at our accommodations segment of $106.3 million, or 47%, an increase at our well site services segment of $66.9 million, or 29%, and an increase at our offshore products segment of $64.7 million, or 28%. 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 23% in the first nine months of 2010 to 25% in the first nine months of 2011 primarily due to the increased proportion of relatively higher margin accommodations and well site services segment revenues in 2011 compared to 2010 and higher margins realized in our accommodations and well site services segments, partially offset by an increased proportion of relatively lower margin tubular services segment revenues in 2011 compared to 2010.

Our well site services segment cost of sales increased $66.9 million, or 29%, in the first nine months of 2011 compared to the first nine months of 2010 as a result of a $60.9 million, or 40%, increase in rental tools services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 31% in the first nine months of 2010 to 36% in the first nine months of 2011. Our rental tools gross margin as a percentage of revenues increased from 35% in the first nine months of 2010 to 38% in the first nine months of 2011 primarily due to a more favorable mix of higher value rentals and improved pricing along with higher fixed cost absorption as a result of increased rental tools utilization. Our drilling services cost of sales increased $6.0 million, or 7%, in the first nine months of 2011 compared to the first nine months of 2010. Our drilling services gross margin as a percentage of revenues increased from 19% in the first nine months of 2010 to 28% in the first nine months of 2011 primarily due to an increase in day rates and improved cost absorption.

Our accommodations segment cost of sales increased $106.3 million, or 47%, in the first nine months of 2011 compared to the first nine months of 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $29.7 million, or 14%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues. Our accommodations segment gross margin as a percentage of revenues increased from 42% in the first nine months of 2010 to 47% in the first nine months of 2011 primarily due to higher margins realized in our lodges and villages.

Our offshore products segment cost of sales increased $64.7 million, or 28%, in the first nine months of 2011 compared to the first nine months of 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues was 26% in the first nine months of 2010 and 2011.

Tubular services segment cost of sales increased by $294.5 million, or 47%, primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues was 6% in the first nine months of 2010 and 2011.

Selling, General and Administrative Expenses. SG&A increased $22.4 million, or 20%, in the first nine months of 2011 compared to the first nine months of 2010 due primarily to SG&A expense associated with the inclusion of The MAC, which added $9.1 million in SG&A expense in the first nine months of 2011, increased accrual for incentive bonuses, increased employee-related costs, higher SG&A costs in our Canadian accommodations business due to the strengthening of the Canadian dollar, an increase in stock-based compensation expense and increased ad valorem taxes. SG&A was 5.3% of revenues in the first nine months of 2011 compared to 6.4% of revenues in the first nine months of 2010.

Depreciation and Amortization. Depreciation and amortization expense increased $45.2 million, or 49%, in the first nine months of 2011 compared to the same period in 2010 due primarily to $35.8 million in depreciation and amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made during the previous twelve months largely related to investments made in our Canadian accommodations business.

Operating Income. Consolidated operating income increased $166.5 million, or 89%, in the first nine months of 2011 compared to the first nine months of 2010 primarily as a result of an increase in operating income from our well site services segment of $72.4 million, or 271%, largely due to the more favorable mix of higher value rentals, improved pricing and increased rental tools utilization, and the addition of operating income from The MAC. In addition, operating income from our tubular services segment increased $20.4 million, or 74%, in the first nine months of 2011 compared to the first nine months of 2010 primarily as a result of the increase in tons shipped and operating income from our offshore products segment increased $17.1 million, or 40%. Operating income in the first nine months of 2011 included $1.6 million in acquisition related expenses for transactions closed in the fourth quarter of 2010.

Interest Expense and Interest Income. Net interest expense increased by $27.9 million, or 274%, in the first nine months of 2011 compared to the first nine months of 2010 due to increased debt levels, including interest expense on the 6 1/2% Notes, and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our revolving credit and term loan facilities. The weighted average interest rate on borrowings outstanding under the Company’s revolving credit and term loan facilities was 3.0% in the first nine months of 2011 compared to 2.5% in the first nine months of 2010. Interest income increased as a result of increased cash balances in interest bearing accounts.

Income Tax Expense. Our income tax provision for the nine months ended September 30, 2011 totaled $88.8 million, or 27.9% of pretax income, compared to income tax expense of $54.0 million, or 30.2% of pretax income, for the nine months ended September 30, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures, which, in the past, have included expanding our accommodations facilities, expanding and upgrading our offshore products manufacturing facilities and equipment, increasing and replacing rental tools assets, adding drilling rigs, funding new product development and general working capital needs. In addition, capital has been used to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations and proceeds from borrowings.

Cash totaling $223.1 million was provided by operations during the first nine months of 2011 compared to cash totaling $153.4 million provided by operations during the first nine months of 2010. During the first nine months of 2011, $171.0 million was used to fund working capital, primarily due to increased raw materials inventory and

receivables in our offshore products segment due to increased activity levels coupled with increased investments in working capital for our tubular services segment. During the first nine months of 2010, $76.2 million was used to fund working capital, primarily due to increased OCTG inventory levels in our tubular services segment to meet increasing demand.

Cash was used in investing activities during the nine months ended September 30, 2011 and 2010 in the amount of $372.2 million and $119.0 million, respectively. Capital expenditures totaled $371.2 million and $121.0 million during the nine months ended September 30, 2011 and 2010, respectively. Capital expenditures in both years consisted principally of purchases of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments and, in 2011, Australian mining related accommodations facilities.

We currently expect to spend a total of approximately $635 million for capital expenditures during 2011 to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. A portion of this $635 million in spending may carry over into early 2012 depending upon delivery schedules and other factors. Approximately 75% of our total expected 2011 capital expenditures will be spent in the accommodations segment. We expect to fund these capital expenditures with cash available, internally generated funds and borrowings under our revolving credit facilities or other corporate borrowings. The foregoing capital expenditure budget does not include any funds for opportunistic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed attractive to the Company.

Net cash of $183.1 million was provided by financing activities during the nine months ended September 30, 2011, primarily as a result of proceeds from the issuance in the second quarter of 2011 of $600 million aggregate principal amount of 6 1/2% senior unsecured notes due in 2019, offset by net repayments of outstanding amounts under our revolving credit facilities. We spent $13.2 million in financings costs in the first nine months of 2011. A total of $14.5 million was provided by financing activities during the nine months ended September 30, 2010, primarily as a result of the issuance of common stock as a result of stock option exercises.

We believe that cash on hand, cash flow from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the economy, the financial markets and other factors, many of which are beyond our control. In addition, such additional debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to stockholders.

Stock Repurchase Program. On August 27, 2010, the Company announced that its Board of Directors authorized $100 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which expired on December 31, 2009. The Company presently has approximately 51.2 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 September 30, 2011, a total of $12.6 million of our stock (209,300 shares) had been repurchased under this program, all of which were purchased in the third quarter of 2011, leaving a total authorization of up to approximately $87.4 million remaining available under the program.

Credit Facilities. On December 10, 2010, we replaced our existing $500 million bank credit facility with $1.05 billion in senior credit facilities governed by the Amended and Restated Credit Agreement (Credit Agreement). The Credit Agreement consists of a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan. The new facilities increased the total commitments available from $500 million under the previous facilities to $1.05 billion. In connection with the execution of the Credit Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $325 million to U.S. $700 million

(including $200 million in term loans), and the total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $175 million to U.S. $350 million (including $100 million in term loans). The maturity date of the Credit Agreement is December 10, 2015. The aggregate principal of the term loans is repayable at a rate of 1.25% per quarter in 2011 and 2.5% per quarter thereafter 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 $26.6 million to $150 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, the lack of or delay in funding by a significant member of our banking group could negatively affect our liquidity position.

As of September 30, 2011, we had $285.5 million outstanding under the Credit Agreement and an additional $23.7 million of outstanding letters of credit, leaving $729.6 million available to be drawn under the facilities.

On July 13, 2011, The MAC entered into a A$150 million Facility Agreement with National Australia Bank Limited. The Facility Agreement 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 September 30, 2011, we had A$31 million outstanding under the Australian facility and an additional A$2.3 million of outstanding letters of credit, leaving A$116.7 million available to be drawn under this facility.

Our total debt represented 37.7% of our combined total debt and shareholders’ equity at September 30, 2011 compared to 35.9% at December 31, 2010 and 9.9% at September 30, 2010. As of September 30, 2011, 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 (6 1/2% Notes) due 2019 through a private placement to qualified institutional buyers.


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 senior secured 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), among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee. The Indenture restricts the Company’s ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on,

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

2 3/8% Notes. As of September 30, 2011, we had classified the $175.0 million principal amount of our 2 3/8% Notes, net of unamortized discount, as a current liability based on the first put/call date of July 6, 2012. If certain contingent conversion thresholds based on the Company’s stock price are met and a 2 3/8% Note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they will receive cash up to $1,000 for each 2 3/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% Notes of 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. As of September 30, 2011, 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 September 30, 2011 measurement date. As of September 30, 2011, the recent trading prices of the 2 3/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. Based on recent trading patterns of the 2 3/8% Notes, we do not currently expect any significant amount of the 2 3/8% Notes to convert before the first put/call date of July 6, 2012. Should a holder convert their 2 3/8% Notes, we would utilize our existing credit facilities to fund the cash portion of the conversion value.

Critical Accounting Policies

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


ITEM 3. *Quantitative and Qualitative Disclosures about Market Risk*

Interest Rate Risk

We have credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of September 30, 2011, we had floating-rate obligations totaling approximately $315.7 million drawn under our credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rates increased by 1% from September 30, 2011 levels, our consolidated interest expense would increase by a total of approximately $3.2 million annually.

Foreign Currency Exchange Rate Risk

Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks in areas outside the U.S. (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 nine months of 2011, our realized foreign exchange losses were $1.4 million and are included in other operating (income) expense in the condensed consolidated statements of income.

Some of our foreign operations are conducted through wholly-owned foreign subsidiaries that have functional currencies other than the U.S. dollar. We currently have subsidiaries whose functional currencies are the Canadian

dollar and Australian dollar. Assets and liabilities from these subsidiaries are translated into U.S. dollars at the exchange rate in effect at each balance sheet date. The resulting translation gains or losses are reflected as accumulated other comprehensive income (loss) in the shareholders’ equity section of our consolidated balance sheets.


ITEM 4. *Controls and Procedures*

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2011 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

In August 2011, we completed the implementation of a new financial and inventory accounting system in our tubular services segment. We believe the new software will enhance our internal controls over financial reporting, and we believe that we have taken the necessary steps to maintain appropriate internal control over financial reporting during this period of system change. We will continuously monitor controls through and around the system to provide reasonable assurance that controls are effective.

During the three months ended September 30, 2011, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act), other than described above, that have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION


ITEM 1. *Legal Proceedings*

We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses, and in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.


ITEM 1A. *Risk Factors*

Item 1A. “Risk Factors” of our 2010 Form 10-K includes a detailed discussion of our risk factors. There have been no significant changes to our risk factors as set forth in our 2010 Form 10-K. The risks described in this Quarterly Report on Form 10-Q and our 2010 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.


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

Purchases of Equity Securities


							Total Number of			Approximate
							Shares Purchased			Dollar Value of Shares
							as Part of			That May Yet Be
	Total Number of			Average Price Paid			Publicly Announced			Purchased Under the
Period	Shares Purchased			per Share			Program			Program⁽¹⁾
July 1, 2011 —		891	⁽²⁾		$ 83.67	⁽³⁾		—		$	100,000,000
July 31, 2011
August 1, 2011 —		191,538	⁽⁴⁾		$ 61.20	⁽⁵⁾		191,400	⁽⁶⁾	$	88,286,379
August 31, 2011
September 1, 2011 -		17,900			$ 51.32	⁽⁷⁾		17,900	⁽⁶⁾	$	87,367,801
September 30, 2011
Total		210,329			$ 60.46			209,300		$	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 July 7, 2011, July 9, 2011 and July 11, 2011, which represent the dates the restrictions lapsed on such shares.

⁽⁴⁾		Included in these shares are 138 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.

⁽⁵⁾		The price paid per share was based on the weighted average closing price of our Company’s common stock on August 13, 2011, which represents the date the restrictions lapsed on such shares, and on the dates in which we repurchased shares under our common stock repurchase program.

⁽⁶⁾		Represents shares of common stock repurchased by us pursuant to our publicly announced common stock repurchase program.

⁽⁷⁾		The price paid per share was based on the weighted average closing price of our Company’s common stock on the date in which we repurchased shares under our common stock repurchase program.

Sales of Unregistered Securities

As of September 30, 2011, certain contingent conversion thresholds for our 2 3/8% Notes were met based on the Company’s stock price and, as a result, the 2 3/8 % Note holders could present their notes for conversion during the quarter following the September 30, 2011 measurement date. If a 2 3/8% Note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they will receive cash up to $1,000 for each 2 3/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% Notes of 31.496 multiplied by the Company average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. During the quarter ended September 30, 2011, a holder converted 10 of our 2 3/8% Notes (principal amount of $10,000) for cash of $10,000 plus 189 shares of our common stock.


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)).

10.3	—	Facility Agreement dated July 13, 2011, between The MAC Services Group Pty Limited and National Australia Bank Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on July 15, 2011 (File No. 001-16337)).


Exhibit No.		Description
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.

**		Furnished herewith.

SIGNATURES

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

OIL STATES INTERNATIONAL, INC.


Date:	November 4, 2011	By	/s/ BRADLEY J. DODSON

			Bradley J. Dodson Senior Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)

Date:	November 4, 2011	By	/s/ ROBERT W. HAMPTON

			Robert W. Hampton Senior Vice President — Accounting and Secretary (Duly Authorized Officer and Chief Accounting Officer)

Exhibit Index


Exhibit No.		Description
3.1	—	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

3.2	—	Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on March 13, 2009 (File No. 001-16337)).

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

10.3	—	Facility Agreement dated July 13, 2011, between The MAC Services Group Pty Limited and National Australia Bank Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on July 15, 2011 (File No. 001-16337)).

31.1*	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.

31.2*	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.

32.1**	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.

32.2**	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.

101.INS**	—	XBRL Instance Document.

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

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

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


Exhibit No.		Description
101.LAB**	—	XBRL Taxonomy Extension Label Linkbase Document.

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


*		Filed herewith.

**		Furnished herewith.

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