OIS 10-Q Quarterly Report Sept. 30, 2012

OIL STATES INTERNATIONAL, INC

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10-Q 1 oilstates_10q-093012.htm FORM 10-Q oilstates_10q-093012.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]

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

For the quarterly period ended September 30, 2012

[ ]

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 [ X ] NO [ ]

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

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

(Check one):

Large Accelerated Filer [X]		Accelerated Filer [ ]

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

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

The Registrant had 54,895,462 shares of common stock, par value $0.01, outstanding and 3,566,932 shares of treasury stock as of October 31, 2012.

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, 2012 and 2011	3
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Month Periods Ended September 30, 2012 and 2011	4
	Consolidated Balance Sheets – September 30, 2012 (unaudited) and December 31, 2011	5
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7 – 26

Cautionary Statement Regarding Forward-Looking Statements		27

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27 – 39

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39 – 40

Item 4.	Controls and Procedures	40

	Part II -- OTHER INFORMATION

Item 1.	Legal Proceedings	40 – 41

Item 1A.	Risk Factors	41

Item 2 .	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	42

Item 6.	Exhibits	42

	(a) Index of Exhibits	42 – 43

Signature Page		44

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 SEPTEMBER 30,						NINE MONTHS ENDED SEPTEMBER 30,
	2012			2011			2012			2011

Revenues	$	1,080,673		$	902,621		$	3,270,752		$	2,483,379

Costs and expenses:
Cost of sales and services		814,034			665,855			2,428,994			1,857,031
Selling, general and administrative expenses		51,308			45,430			147,901			131,902
Depreciation and amortization expense		59,440			46,929			164,323			137,318
Other operating (income) expense		1,566			(57	)		1,703			2,724
		926,348			758,157			2,742,921			2,128,975
Operating income		154,325			144,464			527,831			354,404

Interest expense, net of capitalized interest		(15,736	)		(16,760	)		(51,617	)		(39,541	)
Interest income		440			174			979			1,422
Equity in earnings of unconsolidated affiliates		30			(204	)		671			(151	)
Other income		2,486			885			8,530			1,515
Income before income taxes		141,545			128,559			486,394			317,649
Income tax expense		(37,436	)		(36,487	)		(135,337	)		(88,757	)
Net income		104,109			92,072			351,057			228,892
Less: Net income attributable to noncontrolling interest		317			221			967			721
Net income attributable to Oil States International, Inc.	$	103,792		$	91,851		$	350,090		$	228,171

Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	1.92		$	1.79		$	6.69		$	4.46
Diluted	$	1.87		$	1.67		$	6.32		$	4.15

Weighted average number of common shares outstanding:
Basic		53,975			51,264			52,347			51,144
Diluted		55,365			54,960			55,391			55,028

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

	THREE MONTHS ENDED SEPTEMBER 30,						NINE MONTHS ENDED SEPTEMBER 30,
	2012			2011			2012			2011

Net income	$	104,109		$	92,072		$	351,057		$	228,892

Other comprehensive income (loss):
Foreign currency translation adjustment		43,564			(127,085	)		40,527			(61,370	)
Unrealized loss on forward contracts, net of tax		(434	)		--			(434	)		--
Total other comprehensive income (loss)		43,130			(127,085	)		40,093			(61,370	)

Comprehensive income (loss)		147,239			(35,013	)		391,150			167,522
Comprehensive income attributable to noncontrolling interest		(357	)		(148	)		(996	)		(685	)
Comprehensive income (loss) attributable to Oil States International, Inc.	$	146,882		$	(35,161	)	$	390,154		$	166,837

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands)

	SEPTEMBER 30, 2012			DECEMBER 31, 2011
	(UNAUDITED)
ASSETS

Current assets:
Cash and cash equivalents	$	163,551		$	71,721
Accounts receivable, net		811,270			732,240
Inventories, net		807,317			653,698
Prepaid expenses and other current assets		18,853			32,000
Total current assets		1,800,991			1,489,659

Property, plant, and equipment, net		1,760,309			1,557,088
Goodwill, net		489,405			467,450
Other intangible assets, net		134,395			127,602
Other noncurrent assets		66,439			61,842
Total assets	$	4,251,539		$	3,703,641

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	328,029		$	252,209
Accrued liabilities		113,291			96,748
Income taxes		31,688			10,395
Current portion of long-term debt and capitalized leases		32,605			34,435
Deferred revenue		65,158			75,497
Other current liabilities		1,761			5,665
Total current liabilities		572,532			474,949

Long-term debt and capitalized leases		1,154,167			1,142,505
Deferred income taxes		112,905			97,377
Other noncurrent liabilities		27,761			25,538
Total liabilities		1,867,365			1,740,369

Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 58,458,892 shares and 54,803,539 shares issued, respectively, and 54,893,645 shares and 51,288,750 shares outstanding, respectively		585			548
Additional paid-in capital		580,479			545,730
Retained earnings		1,800,676			1,450,586
Accumulated other comprehensive income		114,464			74,371
Treasury stock, at cost, 3,565,247 and 3,514,789 shares, respectively		(113,246	)		(109,079	)
Total Oil States International, Inc. stockholders’ equity		2,382,958			1,962,156
Noncontrolling interest		1,216			1,116
Total stockholders’ equity		2,384,174			1,963,272
Total liabilities and stockholders’ equity	$	4,251,539		$	3,703,641

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,
	2012			2011

Cash flows from operating activities:
Net income	$	351,057		$	228,892
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		164,323			137,318
Deferred income tax provision		5,122			16,281
Excess tax benefits from share-based payment arrangements		(7,739	)		(7,966	)
Gains on disposals of assets		(7,131	)		(1,650	)
Non-cash compensation charge		13,934			10,829
Accretion of debt discount		4,106			5,787
Amortization of deferred financing costs		5,249			4,699
Other, net		(9	)		(16	)
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		(62,688	)		(109,415	)
Inventories		(140,408	)		(104,421	)
Accounts payable and accrued liabilities		84,449			28,137
Taxes payable		38,035			11,343
Other current assets and liabilities, net		(2,337	)		3,256
Net cash flows provided by operating activities		445,963			223,074

Cash flows from investing activities:
Capital expenditures, including capitalized interest		(331,750	)		(371,165	)
Acquisitions of businesses, net of cash acquired		(48,000	)		(212	)
Proceeds from disposition of property, plant and equipment		9,609			2,778
Other, net		(1,668	)		(3,601	)
Net cash flows used in investing activities		(371,809	)		(372,200	)

Cash flows from financing activities:
Revolving credit borrowings and (repayments), net		201,837			(395,908	)
6 1/2% senior notes issued		--			600,000
Payment of principal on 2 3/8% Notes conversion		(174,990	)		--
Term loan repayments		(22,510	)		(11,246	)
Debt and capital lease repayments		(2,453	)		(966	)
Issuance of common stock from share-based payment arrangements		13,108			11,559
Purchase of treasury stock		--			(12,632	)
Excess tax benefits from share-based payment arrangements		7,739			7,966
Payment of financing costs		(3,264	)		(13,152	)
Tax withholdings related to net share settlements of restricted stock		(4,167	)		(2,540	)
Other, net		3			(11	)
Net cash flows provided by (used in) financing activities		15,303			183,070

Effect of exchange rate changes on cash		2,802			(11,325	)
Net increase in cash and cash equivalents from continuing operations		92,259			22,619
Net cash used in discontinued operations – operating activities		(429	)		(118	)
Cash and cash equivalents, beginning of period		71,721			96,350
Cash and cash equivalents, end of period	$	163,551		$	118,851

Non-cash financing activities:
Value of common stock issued in payment of 2 3/8% Notes conversion	$	220,597		$	--

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, except for the out-of-period adjustments recorded in the third quarter of 2012 discussed below, 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.

In the third quarter of 2012, we recorded out-of-period adjustments, which decreased revenues by $3.1 million and increased cost of sales by $4.4 million (including a $0.7 million decrease in cost of sales which related to 2011). The total adjustment of $7.5 million, or $0.10 per diluted share after tax, related to corrections of accruals for customer credits and related returned inventory due to accounting and reporting system design and implementation issues, along with other adjustments of cost accruals in our tubular services segment. After evaluating the quantitative and qualitative aspects of these corrections, management has determined that our previously issued quarterly and annual consolidated financial statements were not materially misstated and that the out-of-period adjustments are immaterial to our estimated full year 2012 results and to our earnings’ trends.

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

The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2011 (the 2011 Form 10-K).

2. RECENT ACCOUNTING PRONOUNCEMENTS

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

In June 2011, the FASB issued amendments to disclosure requirements for the presentation of comprehensive income. This guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments require that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. The amendments were applied retrospectively. For public entities, the amendments were effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The amendments do not require any transition disclosures. In December 2011, the FASB issued an amendment deferring the effective date of the requirement to present reclassification adjustments out of accumulated other comprehensive income on the face of the consolidated statement of income. The Company adopted this standard in the Quarterly Report on Form 10-Q for the three month period ended March 31, 2012.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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

	SEPTEMBER 30, 2012			DECEMBER 31, 2011
Accounts receivable, net:
Trade	$	585,579		$	553,481
Unbilled revenue		229,113			180,273
Other		1,460			2,449
Total accounts receivable		816,152			736,203
Allowance for doubtful accounts		(4,882	)		(3,963	)
	$	811,270		$	732,240

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

	SEPTEMBER 30, 2012			DECEMBER 31, 2011
Inventories, net:
Tubular goods	$	523,718		$	420,519
Other finished goods and purchased products		93,015			80,184
Work in process		84,807			76,353
Raw materials		118,511			86,672
Total inventories		820,051			663,728
Allowance for obsolescence		(12,734	)		(10,030	)
	$	807,317		$	653,698

	ESTIMATED USEFUL LIFE				SEPTEMBER 30, 2012			DECEMBER 31, 2011
Property, plant and equipment, net:
Land					$	54,725		$	48,989
Accommodations assets (1)	2	-	15	years		1,378,366			1,160,661
Buildings and leasehold improvements (1)	1	-	40	years		174,606			154,233
Machinery and equipment	1	-	29	years		386,891			355,798
Rental tools	4	-	10	years		243,082			199,084
Office furniture and equipment	1	-	10	years		54,999			48,081
Vehicles	2	-	10	years		117,648			100,554
Construction in progress						179,076			166,371
Total property, plant and equipment						2,589,393			2,233,771
Accumulated depreciation						(829,084	)		(676,683	)
					$	1,760,309		$	1,557,088

	SEPTEMBER 30, 2012		DECEMBER 31, 2011
Accrued liabilities:
Accrued compensation	$	57,899	$	61,394
Accrued interest		13,474		6,035
Insurance liabilities		13,078		12,396
Accrued taxes, other than income taxes		14,738		5,889
Liabilities related to discontinued operations		1,696		2,125
Other		12,406		8,909
	$	113,291	$	96,748

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

4. EARNINGS PER SHARE

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

	THREE MONTHS ENDED SEPTEMBER 30,				NINE MONTHS ENDED SEPTEMBER 30,
	2012		2011		2012		2011
Basic earnings per share:
Net income attributable to Oil States International, Inc.	$	103,792	$	91,851	$	350,090	$	228,171

Weighted average number of shares outstanding		53,975		51,264		52,347		51,144

Basic earnings per share	$	1.92	$	1.79	$	6.69	$	4.46

Diluted earnings per share:
Net income attributable to Oil States International, Inc.	$	103,792	$	91,851	$	350,090	$	228,171

Weighted average number of shares outstanding		53,975		51,264		52,347		51,144
Effect of dilutive securities:
Options on common stock		477		592		513		666
2 3/8% Contingent Convertible Senior Subordinated Notes		782		2,944		2,391		3,044
Restricted stock awards and other		131		160		140		174

Total shares and dilutive securities		55,365		54,960		55,391		55,028

Diluted earnings per share	$	1.87	$	1.67	$	6.32	$	4.15

Our calculation of diluted earnings per share for the three and nine months ended September 30, 2012 excludes 303,833 shares and 424,299 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, 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.

See Note 6 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for a discussion of the conversion of out 2 3/8% Contigent Convertible Senior Subordinated Notes (2 3/8% Notes).

5. BUSINESS ACQUISITIONS AND GOODWILL

On July 2, 2012, we acquired Piper Valve Systems, Ltd (Piper). Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects offshore (surface and subsea) and onshore. Piper's valve technology complements our offshore products segment, allowing us to integrate their valve products and services into our existing subsea products such as pipeline end manifolds and terminals, increasing our suite of global deepwater product and service offerings. Subject to customary post-closing adjustments, total transaction consideration was $48.0 million, funded from amounts available under the Company’s U.S. revolving credit facility. The operations of Piper have been included in our offshore products segment since its date of acquisition.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Changes in the carrying amount of goodwill for the nine month period ended September 30, 2012 and the twelve month period ended December 31, 2011 are as follows (in thousands):

	Well Site Services
	Rental Tools and Services			Drilling Services			Subtotal			Accommodations			Offshore Products			Tubular Services			Total
Balance as of December 31, 2010
Goodwill	$	170,034		$	22,767		$	192,801		$	299,062		$	100,654		$	62,863		$	655,380
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		--			--			(62,863	)		(180,158	)
		75,506			--			75,506			299,062			100,654			--			475,222
Goodwill acquired and purchase price adjustments		--			--			--			(9,826	)		315			--			(9,511	)
Foreign currency translation and other changes		(323	)		--			(323	)		2,087			(25	)		--			1,739
		75,183			--			75,183			291,323			100,944			--			467,450

Balance as of December 31, 2011
Goodwill		169,711			22,767			192,478			291,323			100,944			62,863			647,608
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		--			--			(62,863	)		(180,158	)
		75,183			--			75,183			291,323			100,944			--			467,450
Goodwill acquired		--			--			--			--			17,175			--			17,175
Foreign currency translation and other changes		482			--			482			4,094			204			--			4,780
		75,665			--			75,665			295,417			118,323			--			489,405
Balance as of September 30, 2012
Goodwill		170,193			22,767			192,960			295,417			118,323			62,863			669,563
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		--			--			(62,863	)		(180,158	)
	$	75,665		$	--		$	75,665		$	295,417		$	118,323		$	--		$	489,405

6. DEBT

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

	September 30, 2012		December 31, 2011
	(Unaudited)

U.S. revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million and with a weighted average interest rate of 2.7% for the nine month period ended September 30, 2012	$	276,320	$	68,065
U.S. term loan, which matures December 10, 2015, of $200 million; 2.5% of aggregate principal repayable per quarter; weighted average interest rate of 2.4% for the nine month period ended September 30, 2012		175,000		190,000
Canadian revolving credit facility, which matures on December 10, 2015, with available commitments up to $250 million and with a weighted average interest rate of 4.3% for the nine month period ended September 30, 2012		--		--
Canadian term loan, which matures December 10, 2015, of $100 million; 2.5% of aggregate principal repayable per quarter; weighted average interest rate of 3.4% for the nine month period ended September 30, 2012		89,315		93,795
Australian revolving credit facility, which was replaced September 18, 2012, with available commitments up to AUD$150 million and with a weighted average interest rate of 6.2% for the nine month period ended September 30, 2012		--		43,050
Australian revolving credit facility, which matures December 10, 2015, with available commitments up to AUD$300 million and with a weighted average interest rate of 5.6% for the nine month period ended September 30, 2012		37,397		--
6 1/2% senior unsecured notes - due June 2019		600,000		600,000
2 3/8% contingent convertible senior subordinated notes, net		--		170,884
Subordinated unsecured notes payable to sellers of businesses, fixed interest rate of 6%, which mature in December 2012		2,000		4,000
Capital lease obligations and other debt		6,740		7,146
Total debt		1,186,772		1,176,940
Less: Current portion		32,605		34,435
Total long-term debt and capitalized leases	$	1,154,167	$	1,142,505

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

On September 18, 2012, the Company’s Australian accommodations subsidiary, The MAC Services Group Pty Limited (The MAC), entered into a AUD$300 million revolving loan facility governed by a Syndicated Facility Agreement (The MAC Group Facility Agreement), between The MAC, J.P. Morgan Australia Limited, as Australian agent and security trustee, JPMorgan Chase Bank, N.A., as U.S. agent, and the lenders party thereto, which is guaranteed by the Company and The MAC’s subsidiaries. The maturity date of The MAC Group Facility Agreement is December 10, 2015. Under the terms of the MAC Group Facility Agreement, loans bear interest for a particular interest period at a rate per annum equal to the sum of the average interest rate paid by banks for loans of the equivalent period and an applicable percentage ranging from 2.00% to 3.00% based upon the Australian Borrower’s leverage ratio. The MAC Group Facility Agreement contains representations, warranties and covenants that are customary for similar credit arrangements, including, among other things, covenants relating to financial reporting and notification, payment of obligations, and notification of certain events. Financial covenants in the MAC Group Facility Agreement also require The MAC not to permit: (i) the interest coverage ratio (the ratio of consolidated EBITDA to consolidated interest expense) to be less than 4.0 to 1.0 for any period of four consecutive fiscal quarters of The MAC; and (ii) the leverage ratio (the ratio of total debt to consolidated EBITDA) to be greater than 3.0 to 1.0 for any period of four consecutive fiscal quarters of The MAC. Each of the factors considered in the calculations of ratios are defined in The MAC Group Facility Agreement. The MAC Group Facility Agreement contains various customary restrictive covenants, subject to certain exceptions, that limit The MAC and its subsidiaries from, among other things, incurring additional indebtedness or guarantees, creating liens or other encumbrances on property, entering into a merger or similar transaction, selling or transferring certain property, making certain restricted payments and entering into transactions with affiliates. The MAC Group Facility Agreement replaced The MAC’s previous AUD$150 million revolving loan facility. As of September 30, 2012, we had AUD$36 million outstanding under the Australian credit facility leaving AUD$264 million available to be drawn under this facility.

On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% senior unsecured notes (6 1/2% Notes) due 2019 through a private placement to qualified institutional buyers. The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.5% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:

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

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

On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $174,990,000 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. In July 2012, rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $174,990,000 aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and 3,012,380 shares of the Company’s common stock valued at $220.6 million.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

The carrying amount of our 2 3/8% Notes as of December 31, 2011 in our condensed consolidated balance sheets was (in thousands):

	December 31, 2011

Carrying amount of the equity component in additional paid-in capital	$	28,434

Principal amount of the liability component	$	174,990
Less: Unamortized discount		4,106
Net carrying amount of the liability component	$	170,884

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

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Interest expense	$	--	$	3,003	$	6,185	$	8,904

As of September 30, 2012, the Company had approximately $163.6 million of cash and cash equivalents and $437.7 million of the Company’s U.S. and Canadian credit facilities available for future financing needs. The Company also had availability totaling AUD$264 million under its Australian credit facility. As of September 30, 2012, we had $40.0 million of outstanding letters of credit which reduced amounts available under our credit facilities.

Interest expense on the condensed consolidated statements of income is net of capitalized interest of $0.7 million and $3.2 million, respectively, for the three and nine months ended September 30, 2012 and $1.6 million and $4.0 million, respectively, for the same periods in 2011.

7. FAIR VALUE MEASUREMENTS

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

The fair values of our 2 3/8% and 6 1/2 % Notes are estimated based on quoted prices and analysis of similar instruments (Level 2 fair value measurements). The Company changed from a Level 1 fair value measurement standard to a Level 2 fair value measurement standard in the second quarter of 2012 in consideration of the relatively low daily trading volume of our debt instruments. The carrying values and fair values of these notes are as follows (in thousands):

	September 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
2 3/8% Notes
Principal amount	$	-	$	-	$	174,990	$	411,396
Less: unamortized discount		-		-		4,106		-
Net value	$	-	$	-	$	170,884	$	411,396

6 1/2% Notes
Principal amount due 2019	$	600,000	$	639,000	$	600,000	$	625,128

See Note 8 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for a discussion of the fair values of the Company’s foreign currency forward contracts.

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company conducts business in various foreign countries and, therefore, settles transactions in foreign currencies. The Company, from time to time, will utilize foreign currency forward contracts to offset the risk associated with the effects of certain foreign currency exposure. These derivative contracts are consistent with the Company’s strategy for managing financial risks. In July 2012, the Company entered into foreign currency forward contracts, which have been designated and qualify as cash flow hedges, to reduce the Company’s exposure to foreign currency fluctuations on a revenue contract denominated in a foreign currency. The Company initially reports any gain or loss on the effective portion of a cash flow hedge as a component of other comprehensive income and subsequently reclassifies any gain or loss to net sales when the hedged revenues are recorded. The portion of these instruments that do not qualify for cash flow hedge treatment are re-measured at fair value on each balance sheet date and resulting gains or losses are recognized in net income. As of September 30, 2012, the total notional amount of the derivative contracts was $12.4 million (€10.0 million). As of September 30, 2012, all of the Company’s derivative contracts were designated as hedges. The Company had no derivative contracts outstanding as of December 31, 2011.

For each derivative contract entered into in which the Company seeks to obtain cash flow hedge accounting treatment, the Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge transaction, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method of measuring ineffectiveness. This process includes linking all derivatives to specific firm commitments or forecasted transactions and designating the derivatives as cash flow hedges. The Company also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivative contracts that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The effective portion of these hedged items is reflected in other comprehensive income. If it is determined that a derivative contract is not highly effective, or that it has ceased to be a highly effective hedge, the Company will be required to discontinue hedge accounting with respect to that derivative contract prospectively.

At September 30, 2012, the Company’s foreign currency forward contracts had remaining maturities ranging from 4 to 25 months.

The balance sheet location and the fair values of derivative instruments are (in thousands):

Foreign Currency Forward Contracts	September 30, 2012
Assets
Derivatives designated as hedging instruments
Other current assets	$	-
Derivatives not designated as hedging instruments
Other current assets		-
Total assets	$	-
Liabilities
Derivatives designated as hedging instruments
Other current liabilities	$	612
Derivatives not designated as hedging instruments
Other current liabilities		-
Total liabilities	$	612

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

The amounts of the gains and losses related to the Company’s derivative contracts designated as hedging instruments for the three and nine months ended September 30, 2012 and September 30, 2011 are (in thousands):

	Pretax Gain (Loss) Recognized in Other Comprehensive Income on Effective Portion of Derivative
	Three months ended September 30,					Nine months ended September 30,
	2012			2011		2012			2011
Derivatives in Cash Flow Hedging Relationships:
Foreign currency forward contracts	$	(696	)	$	-	$	(696	)	$	-

		Pretax Gain (Loss) Recognized in Income on Effective Portion of Derivative as a Result of Reclassification from Accumulated Other Comprehensive Income
		Three months ended September 30,					Nine months ended September 30,
	Location	2012			2011		2012			2011
Derivatives in Cash Flow Hedging Relationships:
Foreign currency forward contracts	Net sales	$	(4	)	$	-	$	(4	)	$	-

		Gain (Loss) on Ineffective Portion of Derivative Recognized in Income
		Three months ended September 30,					Nine months ended September 30,
	Location	2012			2011		2012			2011
Derivatives in Cash Flow Hedging Relationships:
Foreign currency forward contracts	Net sales	$	(22	)	$	-	$	(22	)	$	-

At September 30, 2012, there is $0.7 million of unrealized pretax loss on outstanding derivatives accumulated in other comprehensive loss, a majority of which is expected to be reclassified to net sales within the next 24 months as a result of underlying hedged transactions also being recorded in net sales.

For the three and nine months ended September 30, 2012 and September 30, 2011, the gains and losses from our derivative contracts not designated as hedging instruments recognized in net sales were zero.

9. CHANGES IN COMMON STOCK OUTSTANDING

Shares of common stock outstanding – January 1, 2012	51,288,750
Shares issued upon conversion of 2 3/8% Notes	3,012,380
Shares issued upon exercise of stock options and vesting of restricted stock awards	644,075
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury	(51,560	)
Shares of common stock outstanding – September 30, 2012	54,893,645

10. STOCK BASED COMPENSATION

During the first nine months of 2012, we granted restricted stock awards totaling 301 ,119 shares valued at a total of $25.0 million. Of the restricted stock awards granted in the first nine months of 2012, a total of 217,000 awards vest in four equal annual installments beginning in February 2013, 47,625 awards are performance based awards that may vest in February 2015 in an amount that will depend on the Company’s achievement of specified performance objectives, 23,625 awards vest 100% in February 2016 and 12,464 awards vest 100% in May 2013. The performance based awards have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital for the three year period commencing January 1, 2012 and ending December 31, 2014. During the nine months ended September 30, 2012, the Company also granted 54,950 units of phantom shares under the newly created Canadian Long-Term Incentive Plan, which provides for the granting of units of phantom shares to key Canadian employees. These awards vest in three equal annual installments beginning in February 2013 and are accounted for as a liability. Participants granted units of phantom shares are entitled to a lump sum cash payment equal to the fair market value of a share of the Company’s common stock on the vesting date. A total of 155,250 stock options with a ten-year term were awarded in the nine months ended September 30, 2012 with an average exercise price of $84.52 that will vest in four equal annual installments starting in February 2013.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Stock based compensation pre-tax expense recognized in the nine month periods ended September 30, 2012 and 2011 totaled $13.9 million and $10.8 million, or $0.19 and $0.15 per diluted share after tax, respectively. Stock based compensation pre-tax expense recognized in the three month periods ended September 30, 2012 and 2011 totaled $4.7 million and $3.6 million, or $0.06 and $0.05 per diluted share after tax, respectively. The total fair value of restricted stock awards that vested during the nine months ended September 30, 2012 and 2011 was $15.9 million and $12.9 million, respectively. At September 30, 2012, $40.8 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.

11. 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, 2012 totaled $37.4 million, or 26.4% of pretax income, and $135.3 million, or 27.8% of pretax income, respectively, compared to $36.5 million, or 28.4% of pretax income, and $88.8 million, or 27.9% of pretax income, respectively, for the three and nine months ended September 30, 2011. The decrease in the effective tax rate from the prior year was largely the result of higher foreign earnings as a percentage of total earnings. Our foreign earnings are taxed at a lower rate than our domestic earnings.

12. SEGMENT AND RELATED INFORMATION

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

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

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings (loss) of unconsolidated affiliates			Capital expenditures		Total assets
Three months ended September 30, 2012
Well site services –
Rental tools and services	$	130,752	$	12,746	$	32,218		$	--		$	27,251	$	521,756
Drilling services		50,995		5,793		9,943			--			10,102		136,278
Total well site services		181,747		18,539		42,161			--			37,353		658,034
Accommodations		273,315		36,246		85,132			--			82,046		2,055,964
Offshore products		189,450		3,807		28,026			(103	)		9,846		781,483
Tubular services		436,161		569		10,515			133			2,423		718,350
Corporate and eliminations		--		279		(11,509	)		--			98		37,708
Total	$	1,080,673	$	59,440	$	154,325		$	30		$	131,766	$	4,251,539

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

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings (loss) of unconsolidated affiliates		Capital expenditures		Total assets
Nine months ended September 30, 2012
Well site services –
Rental tools and services	$	391,385	$	36,619	$	94,986		$	--	$	65,125	$	521,756
Drilling services		149,857		16,814		25,760			--		23,626		136,278
Total well site services		541,242		53,433		120,746			--		88,751		658,034
Accommodations		836,101		97,805		287,364			--		208,171		2,055,964
Offshore products		566,808		10,659		97,116			150		30,809		781,483
Tubular services		1,326,601		1,713		56,990			521		2,720		718,350
Corporate and eliminations		--		713		(34,385	)		--		1,299		37,708
Total	$	3,270,752	$	164,323	$	527,831		$	671	$	331,750	$	4,251,539

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

The operating income of our tubular services segment for the three and nine months ended September 30, 2012 includes $7.5 million, or $0.10 per diluted share after tax, and $0.7 million, or $0.01 per diluted share after tax, respectively, of unfavorable out-of-period adjustments related to corrections of accruals for customer credits and related returned inventory due to accounting and reporting system design and implementation issues, along with other adjustments of cost accruals. After evaluating the quantitative and qualitative aspects of these corrections, management has determined that our previously issued quarterly and annual consolidated financial statements were not materially misstated and that the out-of-period adjustments are immaterial to our estimated full year 2012 results and to our earnings’ trends.

13. 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.

14. CONDENSED CONSOLIDATED FINANCIAL INFORMATION

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

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

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

We have corrected the presentation of our condensed consolidating statements of income for the three and nine month periods ended September 30, 2011, our condensed consolidating balance sheet as of December 31, 2011 and our statement of cash flows for the nine month period ended September 30, 2011 to properly reflect the investment in and equity earnings of certain non-guarantor subsidiaries by certain guarantor subsidiaries in accordance with SEC Regulation S-X, which were previously only presented in the Parent/Guarantor column. We have also corrected other immaterial amounts previously disclosed to properly present (i) the activity and balances of a certain guarantor subsidiary in the Guarantor Subsidiaries column which was previously presented in the Parent/Guarantor column and (ii) the activity and balances of a certain non-guarantor subsidiary in the Non-Guarantors column which was previously presented in the Guarantor Subsidiaries column. The effect of these corrections increased net income for the Guarantor Subsidiaries by $35.2 million and decreased the net income for the Non-Guarantor Subsidiaries by less than $0.1 million, respectively, for three month periods ended September 30, 2011 and increased the net income for the Guarantor Subsidiaries and Non-Guarantor Subsidiaries by $81.8 million and $4.9 million, respectively, for the nine month periods ended September 30, 2011. The effect of the correction to the Guarantor Subsidiaries’ investments in unconsolidated affiliates balance at December 31, 2011 was an increase of $1,034 million. These changes had no impact on consolidated results as previously reported.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Three Months Ended September 30, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)

REVENUES
Operating revenues	$	—	$	730,981	$	349,692	$	—	$	1,080,673
Intercompany revenues		—		6,849		5,799		(12,648)		—
Total revenues		—		737,830		355,491		(12,648)		1,080,673

OPERATING EXPENSES
Cost of sales and services		—		621,732		194,234		(1,932)		814,034
Intercompany cost of sales and services		—		4,864		5,515		(10,379)		—
Selling, general and administrative expenses		461		33,017		17,830		—		51,308
Depreciation and amortization expense		279		23,678		35,488		(5)		59,440
Other operating (income) expense		(478)		828		1,216		—		1,566
Operating income (loss)		(262)		53,711		101,208		(332)		154,325

Interest expense, net of capitalized interest		(14,143)		(210)		(18,375)		16,992		(15,736)
Interest income		5,166		22		12,244		(16,992)		440
Equity in earnings (loss) of unconsolidated affiliates		113,030		73,548		(103)		(186,445)		30
Other income		—		576		1,910		—		2,486
Income before income taxes		103,791		127,647		96,884		(186,777)		141,545
Income tax provision		—		(14,509)		(22,927)		—		(37,436)
Net income		103,791		113,138		73,957		(186,777)		104,109

Other comprehensive income:
Foreign currency translation adjustment		43,564		30,976		30,976		(61,952)		43,564
Unrealized loss on forward contracts		—		(434)		—		—		(434)
Total other comprehensive income		43,564		30,542		30,976		(61,952)		43,130

Comprehensive income		147,355		143,680		104,933		(248,729)		147,239
Comprehensive income attributable to noncontrolling interest		—		—		(353)		(4)		(357)
Comprehensive income attributable to Oil States International, Inc.	$	147,355	$	143,680	$	104,580	$	(248,733)	$	146,882

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Three Months Ended September 30, 2011
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)

REVENUES
Operating revenues	$	—	$	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		366		30,809		14,255		—		45,430
Depreciation and amortization expense		200		19,846		26,888		(5)		46,929
Other operating (income)expense		—		648		(705)		—		(57)
Operating income (loss)		(566)		66,042		79,120		(132)		144,464

Interest expense		(16,337)		(286)		(18,087)		17,950		(16,760)
Interest income		5,071		7		13,047		(17,951)		174
Equity in earnings of unconsolidated affiliates		103,017		56,066		(487)		(158,800)		(204)
Other income (expense)		—		245		640		—		885
Income before income taxes		91,185		122,074		74,233		(158,933)		128,559
Income tax provision		667		(18,941)		(18,213)		—		(36,487)
Net income		91,852		103,133		56,020		(158,933)		92,072

Other comprehensive income:
Foreign currency translation adjustment		(127,085)		(99,873)		(99,922)		199,795		(127,085)
Total other comprehensive income		(127,085)		(99,873)		(99,922)		199,795		(127,085)

Comprehensive income		(35,233)		3,260		(43,902)		40,862		(35,013)
Comprehensive income attributable to noncontrolling interest		—		—		(142)		(6)		(148)
Comprehensive income attributable to Oil States International, Inc.	$	(35,233)	$	3,260	$	(44,044)	$	40,856	$	(35,161)

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Nine Months Ended September 30, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)

REVENUES
Operating revenues	$	—	$	2,258,519	$	1,012,233	$	—	$	3,270,752
Intercompany revenues		—		19,403		9,242		(28,645)		—
Total revenues		—		2,277,922		1,021,475		(28,645)		3,270,752

OPERATING EXPENSES
Cost of sales and services		—		1,878,276		556,602		(5,884)		2,428,994
Intercompany cost of sales and services		—		13,393		8,644		(22,037)		—
Selling, general and administrative expenses		1,287		95,432		51,182		—		147,901
Depreciation and amortization expense		713		67,845		95,779		(14)		164,323
Other operating (income) expense		(503)		182		2,024		—		1,703
Operating income (loss)		(1,497)		222,794		307,244		(710)		527,831

Interest expense, net of capitalized interest		(47,782)		(645)		(54,489)		51,299		(51,617)
Interest income		15,271		100		36,907		(51,299)		979
Equity in earnings (loss) of unconsolidated affiliates		382,702		222,508		149		(604,688)		671
Other income		—		6,175		2,355		—		8,530
Income before income taxes		348,694		450,932		292,166		(605,398)		486,394
Income tax provision		1,396		(67,703)		(69,030)		—		(135,337)
Net income		350,090		383,229		223,136		(605,398)		351,057

Other comprehensive income:
Foreign currency translation adjustment		40,527		28,282		28,293		(56,575)		40,527
Unrealized loss on forward contracts		—		(434)		—		—		(434)
Total other comprehensive income		40,527		27,848		28,293		(56,575)		40,093

Comprehensive income		390,617		411,077		251,429		(661,973)		391,150
Comprehensive income attributable to noncontrolling interest		—		—		(988)		(8)		(996)
Comprehensive income attributable to Oil States International, Inc.	$	390,617	$	411,077	$	250,441	$	(661,981)	$	390,154

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Nine Months Ended September 30, 2011
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)

REVENUES
Operating revenues	$	—	$	1,736,401	$	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		—		1,427,703		432,534		(3,206)		1,857,031
Intercompany cost of sales and services		—		9,693		440		(10,133)		—
Selling, general and administrative expenses		1,121		88,337		42,444		—		131,902
Depreciation and amortization expense		588		60,652		76,086		(8)		137,318
Other operating (income)expense		742		830		1,150		2		2,724
Operating income (loss)		(2,451)		161,885		195,100		(130)		354,404

Interest expense		(35,809)		(974)		(58,523)		55,765		(39,541)
Interest income		10,288		32		46,866		(55,764)		1,422
Equity in earnings of unconsolidated affiliates		254,181		139,019		(713)		(392,638)		(151)
Other income (expense)		—		669		846		—		1,515
Income before income taxes		226,209		300,631		183,576		(392,767)		317,649
Income tax provision		1,963		(46,275)		(44,445)		—		(88,757)
Net income		228,172		254,356		139,131		(392,767)		228,892

Other comprehensive income:
Foreign currency translation adjustment		(61,370)		(12,057)		(55,852)		67,909		(61,370)
Total other comprehensive income		(61,370)		(12,057)		(55,852)		67,909		(61,370)

Comprehensive income		166,802		242,299		83,279		(324,858)		167,522
Comprehensive income attributable to noncontrolling interest		—		—		(657)		(28)		(685)
Comprehensive income attributable to Oil States International, Inc.	$	166,802	$	242,299	$	82,622	$	(324,886)	$	166,837

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Balance Sheets

	September 30, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	205	$	1,821	$	161,525	$	—	$	163,551
Accounts receivable, net		—		483,214		328,056		—		811,270
Inventories, net		—		661,478		146,755		(916)		807,317
Prepaid expenses and other current assets		1,349		5,753		11,751		—		18,853
Total current assets		1,554		1,152,266		648,087		(916)		1,800,991

Property, plant and equipment, net		2,116		534,914		1,223,432		(153)		1,760,309
Goodwill, net		—		189,773		299,632		—		489,405
Other intangible assets, net		—		44,164		90,231		—		134,395
Investments in unconsolidated affiliates		2,512,635		1,548,748		3,570		(4,054,810)		10,143
Long-term intercompany receivables (payables)		808,304		(422,244)		(386,063)		3		—
Other noncurrent assets		37,758		508		18,030		—		56,296
Total assets	$	3,362,367	$	3,048,129	$	1,896,919	$	(4,055,876)	$	4,251,539

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	17,153	$	223,800	$	87,076	$	—	$	328,029
Accrued liabilities		25,257		52,736		35,295		3		113,291
Income taxes		(128,727)		130,162		30,253		—		31,688
Current portion of long-term debt and capitalized leases		20,018		2,318		10,269		—		32,605
Deferred revenue		—		50,496		14,662		—		65,158
Other current liabilities		—		1,474		287		—		1,761
Total current liabilities		(66,299)		460,986		177,842		3		572,532

Long-term debt and capitalized leases		1,031,326		6,248		116,593		—		1,154,167
Deferred income taxes		1,981		58,378		52,546		—		112,905
Other noncurrent liabilities		12,401		8,813		6,996		(449)		27,761
Total liabilities		979,409		534,425		353,977		(446)		1,867,365

Stockholders’ equity		2,382,958		2,513,704		1,541,943		(4,055,647)		2,382,958
Non-controlling interest		—		—		999		217		1,216
Total stockholders’ equity		2,382,958		2,513,704		1,542,942		(4,055,430)		2,384,174
Total liabilities and stockholders’ equity	$	3,362,367	$	3,048,129	$	1,896,919	$	(4,055,876)	$	4,251,539

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Balance Sheets

	December 31, 2011
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	(295)	$	1,736	$	70,280	$	—	$	71,721
Accounts receivable, net		974		461,097		270,170		(1)		732,240
Inventories, net		—		539,067		114,823		(192)		653,698
Prepaid expenses and other current assets		10,143		8,538		13,319		—		32,000
Total current assets		10,822		1,010,438		468,592		(193)		1,489,659

Property, plant and equipment, net		1,530		459,414		1,096,310		(166)		1,557,088
Goodwill, net		—		172,598		294,852		—		467,450
Other intangible assets, net		—		31,372		96,230		—		127,602
Investments in unconsolidated affiliates		2,088,062		1,269,457		1,710		(3,351,468)		7,761
Long-term intercompany receivables (payables)		836,853		(453,156)		(383,697)		—		—
Other noncurrent assets		41,235		457		12,389		—		54,081
Total assets	$	2,978,502	$	2,490,580	$	1,586,386	$	(3,351,827)	$	3,703,641

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	19,418	$	162,762	$	70,029	$	—	$	252,209
Accrued liabilities		17,804		48,819		30,125		—		96,748
Income taxes		(59,396)		61,060		8,731		—		10,395
Current portion of long-term debt and capitalized leases		20,018		4,404		10,013		—		34,435
Deferred revenue		—		47,227		28,270		—		75,497
Other current liabilities		—		5,382		283		—		5,665
Total current liabilities		(2,156)		329,654		147,451		—		474,949

Long-term debt and capitalized leases		1,008,969		6,437		127,099		—		1,142,505
Deferred income taxes		(1,072)		57,677		40,772		—		97,377
Other noncurrent liabilities		10,605		8,635		6,747		(449)		25,538
Total liabilities		1,016,346		402,403		322,069		(449)		1,740,369

Stockholders’ equity		1,962,156		2,088,177		1,263,410		(3,351,587)		1,962,156
Non-controlling interest		—		—		907		209		1,116
Total stockholders’ equity		1,962,156		2,088,177		1,264,317		(3,351,378)		1,963,272
Total liabilities and stockholders’ equity	$	2,978,502	$	2,490,580	$	1,586,386	$	(3,351,827)	$	3,703,641

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, 2012
	Oil States International, Inc. (Parent/ Guarantor)		Guarantor Subsidiaries		Other Subsidiaries (Non- Guarantors)		Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(108,585)	$	259,004	$	295,544	$	—	$	445,963

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(1,299)		(137,792)		(192,659)		—		(331,750)
Acquisitions of businesses, net of cash acquired		—		(48,000)		—		—		(48,000)
Proceeds from disposition of property, plant and equipment		—		5,944		3,665		—		9,609
Other, net		—		(9,957)		8,289		—		(1,668)
Net cash provided by (used in) investing activities		(1,299)		(189,805)		(180,705)		—		(371,809)

CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		208,254		—		(6,417)		—		201,837
Payment of principal on 2 3/8% Notes conversion		(174,990)		—		—		—		(174,990)
Term loan repayments		(15,000)		—		(7,510)		—		(22,510)
Debt and capital lease payments		(15)		(2,314)		(124)		—		(2,453)
Issuance of common stock from share-based payment arrangements		13,108		—		—		—		13,108
Excess tax benefits from share-based payment arrangements		7,739		—		—		—		7,739
Payment of financing costs		(23)		—		(3,241)		—		(3,264)
Proceeds from (funding of) accounts and notes with affiliates, net		75,478		(66,372)		(9,106)		—		—
Tax withholdings related to net share settlements of restricted stock		(4,167)		—		—		—		(4,167)
Other, net		—		1		2		—		3
Net cash provided by (used in) financing activities		110,384		(68,685)		(26,396)		—		15,303

Effect of exchange rate changes on cash		—		—		2,802		—		2,802
Net change in cash and cash equivalents from continuing operations		500		514		91,245		—		92,259
Net cash used in discontinued operations operating activities		—		(429)		—		—		(429)
Cash and cash equivalents, beginning of period		(295)		1,736		70,280		—		71,721

Cash and cash equivalents, end of period	$	205	$	1,821	$	161,525	$	—	$	163,551

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

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(46,432)	$	133,885	$	135,731	$	(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)
Proceeds from disposition of property, plant and equipment		—		1,840		938		—		2,778
Other, net		2		(182)		(3,421)		—		(3,601)
Net cash used in investing activities		(332)		(97,251)		(274,727)		110		(372,200)

CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings and (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		(159,673)		(26,625)		186,298		—		—
Tax withholdings related to net share settlements of restricted stock		(2,540)		—		—		—		(2,540)
Other, net		(11)		1		(1)		—		(11)
Net cash provided by financing activities		77,284		(26,968)		132,754		—		183,070

Effect of exchange rate changes on cash		—		—		(11,325)		—		(11,325)
Net change in cash and cash equivalents from continuing operations		30,520		9,666		(17,567)		—		22,619
Net cash used in discontinued operations operating activities		—		(118)		—		—		(118)
Cash and cash equivalents, beginning of period		(227)		1,216		95,361		—		96,350

Cash and cash equivalents, end of period	$	30,293	$	10,764	$	77,794	$	—	$	118,851

Cautionary Statement Regarding Forward-Looking Statements

This quarterly report on Form 10-Q contains "certain forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Some of the information in the quarterly report may contain "forward-looking statements." The "forward-looking statements" can be identified by the use of forward-looking terminology including "may," "expect," "anticipate," "estimate," "continue," "believe," or other similar words. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of known material factors that could affect our results, please refer to “Part II, Item 1A. Risk Factors” in this report and "Part I, Item 1A. Risk Factors" and the financial statement line item discussions set forth in "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in our 2011 Form 10-K filed with the Commission on February 17, 2012. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations and are not guarantees of future performance. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.

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

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

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

Macroeconomic Environment and Outlook

We provide a broad range of products and services to the oil and gas industry through our accommodations, offshore products, well site services and tubular services business segments. In our accommodations segment, we support both the oil and gas and mining industries. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers’ willingness to spend capital on the exploration for and development of oil, natural gas, metallurgical (met) coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices, economic growth, commodity demand and estimates of resource production. As a result, demand for our products and services is highly sensitive to current and expected commodity prices, principally that of crude oil, met coal and, to a lesser extent, natural gas.

In the first quarter of 2012, the price of West Texas Intermediates (WTI) crude oil increased to over $100 per barrel as positive economic news related to growth rates projected in China and other emerging markets, consumer spending and U.S. consumer confidence indicated that an economic recovery was underway. However, the spot price of crude oil has decreased since the first quarter of 2012 and is currently trading at approximately $86 per barrel for WTI crude and around $109 per barrel for Intercontinental Exchange (ICE) Brent crude. If U.S. oil production continues to increase and exceeds pipeline transportation capacity, we could see continued and/or additional downward pressure on WTI oil prices negatively affecting future U.S. drilling activity. Despite some signs of an improving economy in the United States, the world’s largest consumer of crude oil, significant global economic risks remain due to slowing growth rates in China, fiscal and financial uncertainty in various European countries, a prolonged level of relatively high unemployment in the U.S. and other advanced economies and inflation risks in certain emerging markets. Recent WTI and Brent crude pricing trends are as follows:

	Average Price (per bbl)
	WTI		Brent Crude
Quarter ended
9/30/2012	$	92.17	$	109.63
6/30/2012		93.38		108.90
3/31/2012		102.85		118.54
12/31/2011		94.03		109.31
9/30/2011		89.71		112.47
6/30/2011		102.51		117.12
3/31/2011		93.93		104.90
12/31/2010		85.10		86.80
9/30/2010		76.01		76.41

Prices for natural gas in the United States improved during the third quarter of 2012, largely due to increased demand for natural gas as a result of the industrial sector switching from coal to gas, but continue to be weak due to the rise in production from unconventional natural gas resources in North America, specifically onshore shale production, resulting from the broad application of horizontal drilling and hydraulic fracturing. Natural gas prices are currently trading at or below $3.50 per Mcf. In addition, a considerable amount of natural gas is being derived as a by-product of drilling crude oil and natural gas liquids-oriented wells in liquids rich onshore basins. As a result, the U.S. gas-related working rig count has declined from more than 800 rigs at the beginning of 2012 to less than 430 rigs currently. Although still overstocked, natural gas inventories in the U.S. have declined from 60% above the 5-year average as of the end of the first quarter of 2012 to only 8% above the 5-year average as of the end of the third quarter of 2012. Any increases in the supply of natural gas, whether the supply comes from conventional or unconventional production or associated gas production from oil wells, could constrain prices for natural gas for an extended period and result in fewer rigs drilling for gas in the near-term. Recent natural gas pricing trends are as follows:

	Natural Gas Average Price (per mcf)
Quarter ended
9/30/2012	$	2.88
6/30/2012		2.29
3/31/2012		2.44
12/31/2011		3.32
9/30/2011		4.12
6/30/2011		4.37
3/31/2011		4.18
12/31/2010		3.81
9/30/2010		4.28

Chinese steel production growth has fallen this year as European economies have contracted and U.S. economic growth is anemic, lowering demand for steel and steel inputs such as met coal and iron ore. As a result, prices for met coal and iron ore have fallen throughout 2012, but appear to have stabilized at current levels. Met coal prices have decreased from approximately $325/metric ton at the beginning of the third quarter of 2011 to $200/metric ton at the end of the third quarter of 2012.

Various oil and gas industry analysts have projected increased 2012 global exploration and production expenditures compared to calendar year 2011 levels. North American capital spending plans are likely to be lower year-over-year going forward and are expected to be focused in oil-related shale areas while international exploration and production budgets are expected to primarily be spent offshore.

Overview

Demand for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices. In contrast, demand for our well site services and tubular services segments responds to shorter-term movements in oil and natural gas prices and, specifically, changes in North American drilling and completion activity. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the U. S. and internationally.

Our accommodations business is predominantly located in northern Alberta, Canada and Queensland, Australia and derives most of its business from resource companies who are developing and producing oil sands and coal resources and, to a lesser extent, other mineral resources. More than two-thirds of our accommodations revenue is generated by our large-scale lodge and village facilities. Where traditional accommodations and infrastructure are not accessible or cost effective, our semi-permanent lodge and village facilities provide comprehensive accommodations services similar to those found in an urban hotel. We typically contract our facilities to our customers on a fee per day basis covering lodging and meals that is based on the duration of their needs which can range from several months to several years. For example, in the third quarter of 2012, we were awarded a ten-year contract in support of future operations personnel working on the Kearl Project, potentially one of the Canadian oil sands largest open-pit mining operations jointly owned between Imperial Oil and ExxonMobil Canada.

Generally, our oil sands and mining accommodations’ customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of 10 years to in excess of 30 years and, consequently, these investments are dependent on those customers' longer-term view of commodity demand and prices. Oil sands development activity has increased in the past year and has had a positive impact on our accommodations segment. Recent announcements of new and expanded oil sands projects will create the opportunity for extensions of existing accommodations contracts and incremental accommodations contracts for us in Canada. In addition, several major oil companies and national oil companies have announced joint ventures to develop oil sands leases or other acquisitions of oil sands exposure 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 met coal demand, especially from China, Japan and India. Despite met coal prices weakening recently, our contracted work insulates us somewhat from short-term swings in met coal prices and we expect Chinese met coal demand to continue to increase in 2012 compared to 2011 as the country continues to industrialize. We are expanding our Australian accommodations capacity to meet this increasing demand. In addition, primarily in Canada and the U.S., we provide shorter-term remote site accommodations in smaller configurations utilizing our modular, mobile camp assets, and deploy these assets to support onshore North American drilling and completion activity in several of the active shale play regions.

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

The improvement in oil prices over the last two years, along with the outlook for long-term oil demand, resulted in increased bidding and quoting activity for our offshore products in the latter part of 2010 that continued throughout 2011 and the first nine months of 2012. As a result of this increased activity, backlog in our offshore products segment increased from $514 million as of September 30, 2011 to a record $597 million as of September 30, 2012, inclusive of $17 million in backlog from the Piper Valve Systems acquisition completed in July 2012. Offshore products’ backlog totaled $535 million as of December 31, 2011. We anticipate global deepwater spending to continue to include new award opportunities coming from Brazil, West Africa, the U.S. Gulf of Mexico, South East Asia and Australia over the next twelve months.

Our well site services businesses are affected by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada and the rest of the world. Until recently, overall industry activity has been primarily driven by spending for natural gas exploration and production, particularly in the shale play regions of the U.S. using horizontal drilling and completion techniques. However, considering current oil prices, lower natural gas prices and the advancement of horizontal drilling and completion techniques, activity in North America has shifted to a greater proportion of oil and liquids-rich drilling. According to rig count data published by Baker Hughes Incorporated, the oil rig count in the U.S. now totals approximately 1,400 rigs, the highest oil-related rig count in over 20 years, comprising approximately 77% of total U.S. drilling activity.

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

Through our tubular services segment, we distribute a broad range of casing and tubing used in the drilling and completion of oil and natural gas wells primarily in North America. Accordingly, sales and gross margins in our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled, movements in global steel input prices and the overall industry level of OCTG inventory and pricing. Historically, tubular services’ gross margin generally expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. Our tubular services business has historically been our most cyclical business segment. The strong U.S. land drilling activity in 2011 and in the first nine months of 2012, along with the return of drilling in the U.S. Gulf of Mexico, has led to increased tubular services volumes and revenues.

We have a diversified product and service offering, which has led to exposure to activities conducted throughout the oil and gas cycle. Demand for our tubular services, land drilling and rental tools and services businesses is highly correlated to changes in the drilling rig count in the United States and, to a much lesser extent, Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.

	Average Drilling Rig Count for
	Three Months Ended				Nine Months Ended
	September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
U.S. Land – Oil		1,391		1,024		1,329		923
U.S. Land – Natural gas and other		464		887		579		877
U.S. Offshore		51		34		47		30
Total U.S.		1,906		1,945		1,955		1,830
Canada		325		443		362		406
Total North America		2,231		2,388		2,317		2,236

The average North American rig count for the nine months ended September 30, 2012 increased by 81 rigs, or 3.6%, compared to the nine months ended September 30, 2011 largely due to growth in the U.S. land oil rig count partially offset by a decline in natural gas drilling. However, overall U.S. drilling activity has fallen over the past three months as lower commodity prices have negatively impacted customer cash flows and spending plans.

A factor that influences the financial results for our accommodations segment is the exchange rate between the U.S. dollar and the Canadian dollar and, to a lesser extent, the exchange rate between the U.S. dollar and the Australian dollar. Our accommodations segment has derived a majority of its revenues and operating income in Canada and, since 2011, Australia. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. Although U.S. dollar and Australian dollar exchange rates were comparable in the first nine months of 2012 and 2011, the Canadian dollar was valued at an average exchange rate of U.S. $1.00 in the first nine months of 2012 compared to U.S. $1.02 for the first nine months of 2011, a decrease of 2%. This weakening of the Canadian dollar had a proportionately negative impact on the translation of earnings generated from our Canadian subsidiary and, therefore, the financial results of our accommodations segment.

Steel and steel input prices influence the pricing decisions of our OCTG suppliers, thereby impacting the pricing and margins of our tubular services segment. During 2011 and 2012, OCTG marketplace supply and demand became more balanced compared to the previous two years. Increased supplies of OCTG have met the increased demand created by expanded drilling activity. Throughout 2011 and into the first nine months of 2012, imports of OCTG have increased, particularly goods imported from Canada and Korea followed by India, Mexico and Japan. Additionally, domestic OCTG mill capacity increased in 2012. These increases in supply have been in response to the 7% year-over-year increase in the drilling rig count in the U.S. The OCTG Situation Report suggests that industry OCTG inventory levels peaked in the first quarter of 2009 at approximately twenty months’ supply on the ground and have trended down to approximately five months' supply currently, which is considered closer to a normalized level when measured against historical levels. Ample industry inventory on the ground and increasing imports and domestic production coupled with modestly declining drilling activity have put downward pressure on OCTG prices throughout 2012. We remain focused on working capital management and returns on invested capital in our tubular services segment and will continue to monitor industry inventory levels, forecasted drilling and completion activity and OCTG prices.

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

Although higher than 2011, the drilling rig count in the U.S. Gulf of Mexico remains below historical levels following the April 2010 Macondo well incident and resultant oil spill in the U.S. Gulf of Mexico. Beginning in the third quarter of 2011, however, U.S. Gulf of Mexico drilling activity has shown signs of a slow, but steady, recovery as permitting levels have been steadily improving. New well permitting has increased from 75 permits issued in the first nine months of 2011 to 132 permits issued in the first nine months of 2012.

We continue to monitor the global economy, the demand for crude oil, met coal and natural gas and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. We currently expect that our 2012 capital expenditures will total approximately $500 million to $550 million compared to 2011 capital expenditures of $487 million. The 2012 capital expenditures estimate is lower than previously estimated due to the carryover of some expenditures to the first half of 2013. Our 2012 capital expenditures include funding to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and for upgrade of our equipment and facilities. Approximately two-thirds of our total expected 2012 capital expenditures will be spent in our accommodations segment. In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on an evaluation of both the market outlook and industry fundamentals.

Consolidated Results of Operations (in millions)

	THREE MONTHS ENDED SEPTEMBER 30,											NINE MONTHS ENDED SEPTEMBER 30,
							Variance 2012 vs. 2011											Variance 2012 vs. 2011
	2012			2011			$			%		2012			2011			$		%

Revenues
Well site services -
Rental tools and services	$	130.7		$	127.2		$	3.5		3	%	$	391.4		$	347.4		$	44.0		13	%
Drilling services		51.0			45.6			5.4		12	%		149.9			119.7			30.2		25	%
Total well site services		181.7			172.8			8.9		5	%		541.3			467.1			74.2		16	%
Accommodations		273.3			227.8			45.5		20	%		836.1			627.8			208.3		33	%
Offshore products		189.5			139.5			50.0		36	%		566.8			399.7			167.1		42	%
Tubular services		436.2			362.5			73.7		20	%		1,326.6			988.8			337.8		34	%
Total	$	1,080.7		$	902.6		$	178.1		20	%	$	3,270.8		$	2,483.4		$	787.4		32	%
Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Rental tools and services	$	80.5		$	77.2		$	3.3		4	%	$	243.4		$	214.9		$	28.5		13	%
Drilling services		34.4			31.8			2.6		8	%		104.9			86.1			18.8		22	%
Total well site services		114.9			109.0			5.9		5	%		348.3			301.0			47.3		16	%
Accommodations		136.5			117.0			19.5		17	%		408.7			333.8			74.9		22	%
Offshore products		142.2			100.1			42.1		42	%		417.2			294.9			122.3		41	%
Tubular services		420.4			339.8			80.6		24	%		1,254.8			927.3			327.5		35	%
Total	$	814.0		$	665.9		$	148.1		22	%	$	2,429.0		$	1,857.0		$	572.0		31	%
Gross margin
Well site services -
Rental tools and services	$	50.2		$	50.0		$	0.2		0	%	$	148.0		$	132.5		$	15.5		12	%
Drilling services		16.6			13.8			2.8		20	%		45.0			33.6			11.4		34	%
Total well site services		66.8			63.8			3.0		5	%		193.0			166.1			26.9		16	%
Accommodations		136.8			110.8			26.0		23	%		427.4			294.0			133.4		45	%
Offshore products		47.3			39.4			7.9		20	%		149.6			104.8			44.8		43	%
Tubular services		15.8			22.7			(6.9	)	(30	%)		71.8			61.5			10.3		17	%
Total	$	266.7		$	236.7		$	30.0		13	%	$	841.8		$	626.4		$	215.4		34	%
Gross margin as a percentage of revenues
Well site services -
Rental tools and services		38	%		39	%							38	%		38	%
Drilling services		33	%		30	%							30	%		28	%
Total well site services		37	%		37	%							36	%		36	%
Accommodations		50	%		49	%							51	%		47	%
Offshore products		25	%		28	%							26	%		26	%
Tubular services		4	%		6	%							5	%		6	%
Total		25	%		26	%							26	%		25	%

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

We reported net income attributable to the Company for the quarter ended September 30, 2012 of $103.8 million, or $1.87 per diluted share. These results compare to net income attributable to the Company of $91.9 million, or $1.67 per diluted share, reported for the quarter ended September 30, 2011. Third quarter 2012 results included $7.5 million pre-tax, or $0.10 per diluted share after tax, in unfavorable out-of-period adjustments related to corrections of accruals for customer credits and related returned inventory due to accounting and reporting system design and implementation issues, along with other adjustments of cost accruals in our tubular services segment.

Revenues. Consolidated revenues increased $178.1 million, or 20%, in the third quarter of 2012 compared to the third quarter of 2011.

Our well site services segment revenues increased $8.9 million, or 5%, in the third quarter of 2012 compared to the third quarter of 2011 primarily due to increases in both rental tools and services revenues and drilling services revenues. Our rental tools and services revenues increased $3.5 million, or 3%, in the third quarter of 2012 compared to the third quarter of 2011 as a favorable mix of demand for the Company’s proprietary tools, particularly in the Bakken and Eagle Ford regions, coupled with improved activity levels in the Gulf of Mexico, Canada and Mexico led to a 4% increase in revenue per ticket. The number of service tickets issued in the third quarter of 2012 decreased 1% compared to the third quarter of 2011 due to reduced activity particularly in the Haynesville, Barnett and Marcellus regions, resulting from reduced customer spending in dry gas markets. Our drilling services revenues increased $5.4 million, or 12%, in the third quarter of 2012 compared to the third quarter of 2011 primarily as a result of increases in pricing, with average day rates rising to $18,300 per day for the third quarter of 2012 up from $16,500 per day for the third quarter of 2011, and increased utilization of our rigs from an average of approximately 88% for the third quarter of 2011 to an average of approximately 92% for the third quarter of 2012.

Our accommodations segment reported revenues in the third quarter of 2012 that were $45.5 million, or 20%, higher than the third quarter of 2011. Higher accommodations revenues were generated primarily from expanded room capacity in Canada and Australia. Revenues, average available rooms and revenue per available room (RevPar) for lodges and villages increased 34%, 17%, and 14%, respectively, in the third quarter of 2012 compared to the third quarter of 2011. The increase in the RevPar in 2012 compared to 2011 was primarily due to increased occupancy levels.

Our offshore products segment revenues increased $50.0 million, or 36%, in the third quarter of 2012 compared to the third quarter of 2011. This increase was primarily the result of an improved revenue mix favoring our production equipment and connector products along with contributions from the Piper Valve business which was acquired in July 2012. Backlog reached an all-time record level, totaling $597 million at September 30, 2012 compared to $514 million reported at September 30, 2011, inclusive of $17 million in backlog obtained from the Piper Valve Systems acquisition.

Our tubular services segment revenues increased $73.7 million, or 20%, in the third quarter of 2012 compared to the third quarter of 2011. This increase was primarily due to an increase in tons shipped from 182,300 in 2011 to 213,500 in 2012, an increase of 31,200 tons, or 17%. Higher volumes resulted from increased activity in the Gulf of Mexico coupled with modest onshore market share gains. We also reported a 3% increase in realized revenues per ton shipped in the third quarter of 2012 compared to the third quarter of 2011. In the third quarter of 2012, we recorded unfavorable out-of-period adjustments related to corrections of accruals for customer credits and returned inventory, which decreased revenues by $3.1 million.

Cost of Sales and Service. Our consolidated cost of sales increased $148.1 million, or 22%, in the third quarter of 2012 compared to the third quarter of 2011 as a result of increased cost of sales at our tubular services segment of $80.6 million, or 24%, an increase at our offshore products segment of $42.1 million, or 42%, an increase at our accommodations segment of $19.5 million, or 17%, and an increase at our well site services segment of $5.9 million, or 5%. These cost of sales increases were directly related to the increases in segmental revenues. Cost of sales at our tubular services segment includes $4.4 million in additional cost of sales due to unfavorable out-of-period adjustments related to corrections of accruals for returned inventory coupled with other cost accrual adjustments. Our consolidated gross margin as a percentage of revenues decreased from 26% in the third quarter of 2011 to 25% in the third quarter of 2012 primarily due to an increased proportion of relatively lower margin tubular services segment revenues in the third quarter of 2012 compared to the third quarter of 2011.

Our well site services segment cost of sales increased $5.9 million, or 5%, in the third quarter of 2012 compared to the third quarter of 2011 as a result of a $3.3 million, or 4%, increase in rental tools and services cost of sales and a $2.6 million, or 8%, increase in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues was 37% in both the third quarter of 2012 and 2011. Our rental tools and services gross margin as a percentage of revenues was consistent at 38% in the third quarter of 2012 compared to 39% in the third quarter of 2011. Our drilling services gross margin as a percentage of revenues increased from 30% in the third quarter of 2011 to 33% in the third quarter of 2012 primarily due to increased pricing, rig utilization and cost absorption, partially offset by increased trucking, repairs and maintenance, and other costs.

Our accommodations segment cost of sales increased $19.5 million, or 17%, in the third quarter of 2012 compared to the third quarter of 2011 primarily due to increased revenues and room capacity in both Canada and Australia. Our accommodations segment gross margin as a percentage of revenues increased from 49% in the third quarter of 2011 to 50% in the third quarter of 2012 primarily due to the 14% increase in RevPar for lodges and villages in the third quarter of 2012 compared to the third quarter of 2011 which was predominantly driven by higher utilization.

Our offshore products segment cost of sales increased $42.1 million, or 42%, in the third quarter of 2012 compared to the third quarter of 2011 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues decreased from 28% in the third quarter of 2011 to 25% in the third quarter of 2012 primarily due to a $2.9 million margin adjustment on a subsea pipeline project in Brazil, which was performed in 2010 and 2011 but is still in the process of being collected, and declines in the gross margins of our elastomers business. Excluding this charge, gross margin as a percentage of revenues for the third quarter of 2012 would have been 26%.

Our tubular services segment cost of sales increased by $80.6 million, or 24%, in the third quarter of 2012 compared to the third quarter of 2011 primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues decreased from 6% in the third quarter of 2011 to 4% in the third quarter of 2012 primarily due to $7.5 million in non-cash unfavorable out-of-period adjustments related to corrections of accruals for customer credits and related returned inventory and other cost accrual adjustments. Excluding these adjustments, gross margin as a percentage of revenues for the third quarter of 2012 would have been 5%. The decrease in gross margin as a percentage of revenues, excluding the out-of-period adjustments, was due to an increase in the proportion of sales in relatively lower-margin markets such as the Permian Basin.

Selling, General and Administrative Expenses. Selling, general and administrative expense increased $5.9 million, or 13%, in the third quarter of 2012 compared to the third quarter of 2011 primarily due to increased employee-related costs, commissions, bad debt expense and professional fees, along with SG&A expense associated with the inclusion of the Piper Valve business which was acquired in July 2012.

Depreciation and Amortization. Depreciation and amortization expense increased $12.5 million, or 27%, in the third quarter of 2012 compared to the third quarter of 2011 primarily due to capital expenditures made during the previous twelve months largely related to investments in our Canadian and Australian accommodations and rental tools and services businesses.

Operating Income. Consolidated operating income increased $9.9 million, or 7%, in the third quarter of 2012 compared to the third quarter of 2011 primarily as a result of an increase in operating income from our accommodations segment of $13.4 million, or 19%, primarily as a result of expanded room capacity in Canada and Australia, and an increase in operating income from our offshore products segment of $3.2 million, or 13%, partially offset by a $7.4 million decrease in operating income from our tubular services segment. The decrease in operating income from our tubular services segment was primarily due to $7.5 million in non-cash unfavorable out-of-period adjustments to correct accruals of customer credits and related returned inventory and other cost accrual adjustments. In addition, operating income from our well site services segment increased $1.2 million, or 3%, largely due to increased dayrates and rig utilization in our drilling services business.

Interest Expense and Interest Income. Net interest expense decreased by $1.3 million, or 8%, in the third quarter of 2012 compared to the third quarter of 2011 primarily due to the conversion of the 2 3/8% Notes in July 2012, partially offset by increased interest expense on our revolving credit facility due to higher debt levels outstanding under the credit facilities. The weighted average interest rate on borrowings outstanding under the Company’s credit facilities was 2.8% in the third quarter of 2012 compared to 3.1% in the third quarter of 2011. Interest income increased as a result of increased cash balances in interest bearing accounts.

Income Tax Expense. Our income tax provision for the three months ended September 30, 2012 totaled $37.4 million, or 26.4% of pretax income, compared to income tax expense of $36.5 million, or 28.4% of pretax income, for the three months ended September 30, 2011. The decrease in the effective tax rate from the prior year was largely the result of lower domestic earnings as a percentage of total earnings. Our domestic earnings are taxed at a higher rate than our foreign earnings.

NINE MONTHS ENDED SEPTEMBER 30, 2012 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2010

We reported net income attributable to the Company for the nine months ended September 30, 2012 of $350.1 million, or $6.32 per diluted share, including a gain of $17.9 million, or $0.23 per diluted share after-tax, from a favorable contract settlement reported in our U.S. accommodations business and a pre-tax gain of $2.5 million, or $0.03 per diluted share after-tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012. The third quarter adjustment taken in the tubular services segment did not have a material impact on the results for the nine months ended September 30, 2012. These results compare to net income attributable to the Company of $228.2 million, or $4.15 per diluted share, reported for the nine months ended September 30, 2011.

Revenues. Consolidated revenues increased $787.4 million, or 32%, in the first nine months of 2012 compared to the first nine months of 2011.

Our well site services segment revenues increased $74.2 million, or 16%, in the first nine months of 2012 compared to the first nine months of 2011 primarily due to increases in both rental tools and services revenues and drilling services revenues. Our rental tools and services revenues increased $44.0 million, or 13%, in the first nine months of 2012 compared to the first nine months of 2011 primarily due to increased demand for completion services supporting the 7% increase in the U.S. rig count, a more favorable mix of higher value rentals and services, increased equipment utilization, additional capital investment in rental equipment and greater service intensity. Our drilling services revenues increased $30.2 million, or 25%, in the first nine months of 2012 compared to the first nine months of 2011 primarily as a result of increased utilization of our rigs from an average of approximately 80% during the first nine months of 2011 to an average of approximately 91% during the first nine months of 2012, and increases in pricing, with average day rates rising to $18,200 per day for the first nine months of 2012 up from $16,100 per day for the first nine months of 2011.

Our accommodations segment reported revenues in the first nine months of 2012 that were $208.3 million, or 33%, above the first nine months of 2011. The increase in accommodations revenue primarily resulted from increased revenues from expanded room capacity in Canada and Australia along with $18.3 million in revenue from a favorable contract settlement reported in our U.S. accommodations business during the first quarter of 2012. Revenues, average available rooms and RevPar for our lodges and villages increased 40%, 27% and 11%, respectively, in the first nine months of 2012 compared to the first nine months of 2011.

Our offshore products segment revenues increased $167.1 million, or 42%, in the first nine months of 2012 compared to the first nine months of 2011. This increase was primarily the result of higher levels of manufacturing and service activity, along with an improved revenue mix favoring our production equipment and connector products.

Our tubular services segment revenues increased $337.8 million, or 34%, in the first nine months of 2012 compared to the first nine months of 2011. This increase was primarily a result of an increase in tons shipped from 510,000 in 2011 to 648,900 in 2012, an increase of 138,900 tons, or 27%. Higher volume resulted from the 7% increase in U.S. drilling and completion activity, market share gains in the U.S. and incremental customer programs in the U.S. Gulf of Mexico and certain U.S. shale basins. We also reported a 5% increase in realized revenues per ton shipped in the first nine months of 2012 compared to the first nine months of 2011.

Cost of Sales and Service. Our consolidated cost of sales increased $572.0 million, or 31%, in the first nine months of 2012 compared to the first nine months of 2011 as a result of increased cost of sales at our tubular services segment of $327.5 million, or 35%, an increase at our offshore products segment of $122.3 million, or 41%, an increase at our accommodations segment of $74.9 million, or 22%, and an increase at our well site services segment of $47.3 million, or 16%. These cost of sales increases were directly related to the increases in segmental revenues. Our consolidated gross margin as a percentage of revenues increased from 25% in the first nine months of 2011 to 26% in the first nine months of 2012 primarily due to the increased proportion of relatively higher margin accommodations revenues and higher margins realized in our accommodations segment, partially offset by an increased proportion of relatively lower margin tubular services segment revenues in the first nine months of 2012 compared to the first nine months of 2011.

Our well site services segment cost of sales increased $47.3 million, or 16%, in the first nine months of 2012 compared to the first nine months of 2011 as a result of a $28.5 million, or 13%, increase in rental tools and services cost of sales and an $18.8 million, or 22%, increase in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues remained constant at 36% in the first nine months of 2012 and 2011. Our rental tools and services gross margin as a percentage of revenues was 38% in the first nine months of 2012 and 2011. Our drilling services gross margin as a percentage of revenues increased from 28% in the first nine months of 2011 to 30% in the first nine months of 2012 primarily due to increased day rates, rig utilization and cost absorption.

Our accommodations segment cost of sales increased $74.9 million, or 22%, in the first nine months of 2012 compared to the first nine months of 2011 primarily due to increased revenues and room capacity in both Canada and Australia. Our accommodations segment gross margin as a percentage of revenues increased from 47% in the first nine months of 2011 to 51% in the first nine months of 2012 primarily due to a 11% increase in RevPar for lodges and villages in the first nine months of 2012 compared to the first nine months of 2011 and, to a lesser extent, the favorable contract settlement reported in our U.S. accommodations business during the first quarter of 2012. The increase in the RevPar in 2012 compared to 2011 was primarily due to increased occupancy levels. Excluding the favorable contract settlement, our accommodations segment gross margin as a percentage of revenues would have been 50% in the first nine months of 2012.

Our offshore products segment cost of sales increased $122.3 million, or 41%, in the first nine months of 2012 compared to the first nine months of 2011 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues remained constant at 26% in the first nine months of 2012 and 2011. Excluding the $2.9 million negative margin adjustment in the third quarter booked on a subsea pipeline project in Brazil which was performed in 2010 and 2011 but is still in the process of being collected, gross margin as a percentage of revenues for the first nine months of 2012 would have been 27%.

Our tubular services segment cost of sales increased by $327.5 million, or 35%, in the first nine months of 2012 compared to the first nine months of 2011 primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues decreased from 6.3% in the first nine months of 2011 to 5.4% in the first nine months of 2012 primarily due to an increase in the proportion of sales in relatively lower-margin markets such as the Permian Basin.

Selling, General and Administrative Expenses. Selling, general and administrative expense increased $16.0 million, or 12%, in the first nine months of 2012 compared to the first nine months of 2011 primarily due to increased employee-related costs, commissions and office expenses along with SG&A expense associated with the inclusion of the Piper Valve business which was acquired in July 2012.

Depreciation and Amortization. Depreciation and amortization expense increased $27.0 million, or 20%, in the first nine months of 2012 compared to the first nine months of 2011 primarily due to capital expenditures made during the previous twelve months largely related to investments in our Canadian and Australian accommodations and rental tools and services businesses.

Operating Income. Consolidated operating income increased $173.4 million, or 49%, in the first nine months of 2012 compared to the first nine months of 2011 primarily as a result of an increase in operating income from our accommodations segment of $108.9 million, or 61%, due to expanded room capacity in Canada and Australia, along with the favorable contract settlement reported in our U.S. accommodations business, and an increase in operating income from our offshore products segment of $36.7 million, or 61%. In addition, operating income from our well site services segment increased $21.7 million, or 22%, largely due to a more favorable mix of services and increased activity in our rental tools and services business and increased rig utilization and dayrates in our drilling services business. Operating income from our tubular services segment increased $9.1 million, or 19%, primarily as a result of the increase in tons shipped.

Interest Expense and Interest Income. Net interest expense increased by $12.5 million, or 33%, in the first nine months of 2012 compared to the first nine months of 2011 primarily due to interest expense on the 6 1/2% Notes due in 2019 which were issued on June 1, 2011, partially offset by decreased interest expense on our revolving credit facility due to lower amounts outstanding under the facilities and decreased interest expense on our 2 3/8% Notes due to their conversion in July 2012. The weighted average interest rate on borrowings outstanding under the Company’s credit facilities was 3.1% in the first nine months of 2012 and 2011. Interest income decreased as a result of decreased cash balances in interest bearing accounts.

Income Tax Expense. Our income tax provision for the nine months ended September 30, 2012 totaled $135.3 million, or 27.8% of pretax income, compared to income tax expense of $88.8 million, or 27.9% of pretax income, for the nine months ended September 30, 2011. The modest decrease in the effective tax rate from the prior year was largely the result of higher foreign earnings as a percentage of total earnings. Our foreign earnings are taxed at a lower rate than our domestic earnings.

Liquidity and Capital Resources

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

Cash totaling $446.0 million was provided by operations during the first nine months of 2012 compared to cash totaling $223.1 million provided by operations during the first nine months of 2011. During the first nine months of 2012, $82.9 million was used to fund working capital, primarily due to increased investments in working capital for our tubular services business and increases in receivables in our offshore products business. 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.

Cash was used in investing activities during the nine months ended September 30, 2012 and 2011 in the amounts of $371.8 million and $372.2 million, respectively. Capital expenditures totaled $331.8 million and $371.2 million during the nine months ended September 30, 2012 and 2011, respectively. Capital expenditures in both years consisted principally of purchases and installation of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments and Australian mining developments.

We currently expect to spend a total of approximately $500 million to $550 million for capital expenditures during 2012 to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and for upgrade of our equipment and facilities. Approximately two-thirds of our total estimated 2012 capital expenditures are expected to be spent in our accommodations segment. We expect to fund these capital expenditures with cash available, internally generated funds and borrowings under our U.S., Canadian and Australian credit facilities. The foregoing capital expenditure forecast does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company. At September 30, 2012, we had cash totaling $160.3 million held by foreign subsidiaries, primarily in Canada and the United Kingdom, where we have assumed permanent reinvestment of earnings and where we have not recorded a U.S. tax liability upon the assumed repatriation of foreign earnings. We believe these cash balances will be utilized for future investment outside the United States.

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

Net cash of $15.3 million was provided by financing activities during the nine months ended September 30, 2012, primarily as a result of borrowings under our U.S. revolving credit facility, partially offset by payments of principal amounts on the conversion of our 2 3/8% Notes and repayments on our U.S. and Canadian term loans. 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.

On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $174,990,000 in aggregate principal amount, on July 6, 2012 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. The 2 3/8% Notes were convertible by the holders thereof into shares of the Company’s common stock at the conversion rate of 31.496 shares of common stock for each $1,000 principal amount of 2 3/8% Notes converted. Rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $174,990,000 aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash equal to the principal amount and 3,012,380 shares of the Company’s common stock. See Note 6 to the Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.

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

Stock Repurchase Program. On August 23, 2012, the Company announced that its Board of Directors authorized $200 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which was set to expire on September 1, 2012. As of September 30, 2012, the Company had approximately 54.9 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2014. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. As of September 30, 2012, we had not repurchased any shares pursuant to this authorization.

Credit Facilities. Our current bank credit facilities include a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan. The U.S. and Canadian credit facilities contain total commitments available of $1.05 billion, including Total U.S. Commitments (as defined in the Credit Agreement) of U.S. $700 million (including $200 million in U.S. term loans), and Total Canadian Commitments (as defined in the Credit Agreement) of U.S. $350 million (including $100 million in Canadian term loans). The maturity date of the Credit Agreement is December 10, 2015. The current principal balance of the term loans is repayable at a rate of 2.5% per quarter of the aggregate principal amount until maturity on December 10, 2015 when the remaining principal is due. We currently have 19 lenders in our Credit Agreement with commitments ranging from $25.3 million to $150 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, the lack of or delay in funding by a significant member of our banking group could negatively affect our liquidity position. As of September 30, 2012, we had $540.6 million outstanding under the Credit Agreement and an additional $36.0 million of outstanding letters of credit, leaving $437.7 million available to be drawn under the U.S. and Canadian facilities.

Our total debt represented 33.2% of our combined total debt and stockholders’ equity at September 30, 2012 compared to 37.5% at December 31, 2011 and 37.7% at September 30, 2011. As of September 30, 2012, the Company was in compliance with all of its debt covenants.

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

The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.5% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:

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

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

On June 1, 2011, in connection with the issuance of the 6 1/2% Notes, the Company entered into an Indenture (the Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The Indenture restricts the Company's ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 6 1/2% Notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The Indenture contains customary events of default. As of September 30, 2012, the Company was in compliance with all covenants of the 6 1/2% Notes.

Critical Accounting Policies

For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2011 Form 10-K. These estimates require significant judgments, assumptions and estimates. We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. There have been no material changes to the judgments, assumptions and estimates, upon which our critical accounting estimates are based.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

We have credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of September 30, 2012, we had floating-rate obligations totaling approximately $578.0 million drawn under our credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If floating interest rates increased by 1%, our consolidated interest expense would increase by a total of approximately $5.8 million annually based on our floating debt obligations as of September 30, 2012.

Foreign Currency Exchange Rate Risk

Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks in areas outside the U.S. (primarily in our offshore products segment), we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the first nine months of 2012, our reported foreign exchange losses were $1.7 million and are included in “Other operating expense” in the consolidated statements of income. In order to reduce our exposure to fluctuations in currency exchange rates, we may enter into foreign exchange agreements with financial institutions. As of September 30, 2012, we had outstanding foreign currency forward purchase contracts totaling $12.4 million, hedging expected cash flows denominated in Euros. We have recorded other comprehensive loss of $0.7 million in the nine months ended September 30, 2012 as a result of this contract. As of December 31, 2011, we had no active hedge contracts outstanding.

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, 2012 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

During the three months ended September 30, 2012, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) or in other factors, which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

Item 1A. “Risk Factors” of our 2011 Form 10-K includes a detailed discussion of our risk factors. The risks described in this Quarterly Report on Form 10-Q and our 2011 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no significant changes to our risk factors as set forth in our 2011 Form 10-K except for the additional risk factors below:

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

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

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

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

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

Purchases of Equity Securities

Period			Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Program	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Program (1)
July 1, 2012	–	July 31, 2012	243 (2)	$68.12 (3)	--	$ 87,367,801
August 1, 2012	–	August 31, 2012	132 (2)	$78.78 (4)	--	$ 200,000,000
September 1, 2012	–	September 30, 2012	--	--	--	$ 200,000,000
Total			375	$71.87	--	$ 200,000,000

(1)

On August 27, 2010, we announced a share repurchase program of up to $100,000,000, expiring on September 1, 2012. On August 23, 2012, we announced a share repurchase program of up to $200,000,000 to replace the prior share repurchase authorization, which was set to expire on September 1, 2012. The current share repurchase program expires on September 1, 2014.

(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, 2012 and July 11, 2012, which represent the dates the restrictions lapsed on such shares.

(4)

The price paid per share was based on the weighted average closing price of our Company’s common stock on August 13, 2012, which represents the date the restrictions lapsed on such shares.

ITEM 6. Exhibits

(a)	INDEX OF EXHIBITS

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

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

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

4.1	—	First Supplemental Indenture, dated as of September 10, 2012, among Oil States Energy Services, L.L.C., Oil States International, Inc. (together with its successors and assigns), each other then-existing Guarantor under the Indenture, and Wells Fargo Bank, N.A., as Trustee, paying agent and registrar under such Indenture (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).

10.1	—	Syndicated Facility Agreement, dated as of September 18, 2012, among The MAC Services Group Pty Limited, as Borrower, the Lenders named therein, J.P. Morgan Australia Limited, as Australian Agent and Security Trustee, JPMorgan Chase Bank, N.A., as U.S. Agent, JPMorgan Chase Bank, N.A., as Issuing Bank and JPMorgan Chase Bank, N.A., as Swing Line Lender (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).

10.2	—	Amendment No. 1, dated as of September 18, 2012, to the Credit Agreement among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., each of the Guarantors, the Lenders party hereto and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).

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

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

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

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

101.INS*	—	XBRL Instance Document

101.SCH*	—	XBRL Taxonomy Extension Schema Document

101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.

**	Management contracts or compensatory plans or arrangements.

***	Furnished herewith.

SIGNATURES

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

OIL STATES INTERNATIONAL, INC.

Date: November 2, 2012	By	/s/ BRADLEY J. DODSON
		Bradley J. Dodson
		Senior Vice President, Chief Financial Officer and
		Treasurer (Duly Authorized Officer and Principal Financial Officer)



Date: November 2, 2012	By	/s/ ROBERT W. HAMPTON
		Robert W. Hampton
		Senior Vice President -- Accounting and
		Secretary (Duly Authorized Officer and Chief Accounting Officer)

Exhibit Index

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


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



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

4.1	—	First Supplemental Indenture, dated as of September 10, 2012, among Oil States Energy Services, L.L.C., Oil States International, Inc. (together with its successors and assigns), each other then-existing Guarantor under the Indenture, and Wells Fargo Bank, N.A., as Trustee, paying agent and registrar under such Indenture (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).

10.1	—	Syndicated Facility Agreement, dated as of September 18, 2012, among The MAC Services Group Pty Limited, as Borrower, the Lenders named therein, J.P. Morgan Australia Limited, as Australian Agent and Security Trustee, JPMorgan Chase Bank, N.A., as U.S. Agent, JPMorgan Chase Bank, N.A., as Issuing Bank and JPMorgan Chase Bank, N.A., as Swing Line Lender (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).

10.2	—	Amendment No. 1, dated as of September 18, 2012, to the Credit Agreement among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., each of the Guarantors, the Lenders party hereto and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).

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

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

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

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

101.INS*	—	XBRL Instance Document

101.SCH*	—	XBRL Taxonomy Extension Schema Document

101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document

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

101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.

**	Management contracts or compensatory plans or arrangements.

***	Furnished herewith.

TABLE OF CONTENTS

Part I -- Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II -- Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Purchases Of Equity Securities By The Issuer and Affiliated Purchasers Item 6. Exhibits

OIS 10-Q Quarter ended Sept. 30, 2012