osii_10k-123112.htm

PERFORMANCE GRAPH

The following performance graph and chart compare the cumulative total stockholder return on the Company's common stock to the cumulative total return on the Standard & Poor's 500 Stock Index and Philadelphia OSX Index, an index of oil and gas related companies that represent an industry composite of the Company's peer group, for the period from December 31, 2007 to December 31, 2012. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2007 and assume the reinvestment of all dividends.

Oil States International – NYSE

	Cumulative Total Return
		12/07		12/08		12/09		12/10		12/11		12/12
OIL STATES INTERNATIONAL, INC.	$	100.00	$	54.78	$	115.15	$	187.84	$	223.83	$	209.67
S & P 500		100.00		63.00		79.67		91.67		93.61		108.59
PHLX OIL SERVICE SECTOR (OSX)		100.00		40.95		67.83		82.91		70.00		71.39

*$100 invested on December 31, 2007 in stock or index-including reinvestment of dividends. Fiscal year ending December 31st.

(1)

This graph is not "soliciting material," is not deemed filed with the Commission and is not to be incorporated by reference in any filing by us under the Securities Act, or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.

(2)	The stock price performance shown on the graph is not necessarily indicative of future price performance. Information used in the graph was obtained from Research Data Group, Inc., a source believed to be reliable, but we are not responsible for any errors or omissions in such information.

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Unregistered Sales of Equity Securities and Use of Proceeds

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchases

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)
October 1, 2012 – October 31, 2012		583	(2)	$	76.52	(3)		--	$	200,000,000
November 1, 2012 – November 30, 2012		146,494	(4)	$	66.53	(5)		146,396	$	190,260,656
December 1, 2012 - December 31, 2012		79,400		$	69.34	(6)		79,400	$	184,754,796
Total		226,477		$	67.54			225,796	$	184,754,796

(1)

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 October 4, 2012 and October 5, 2012, which represent the dates the restrictions lapsed on such shares.

(4)

Included in these shares are 98 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.

(5)

The price paid per share was based (a) on the dates in which we repurchased shares under our common stock repurchase program, and (b) on the weighted average closing price of our Company’s common stock on November 3, 2012, which represents the date the restrictions lapsed on such shares.

(6)

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

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Item 6. Selected Financial Data

The selected financial data on the following pages include selected historical financial information of our company as of and for each of the five years ended December 31, 2012. The following data should be read in conjunction with “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and the Company's Consolidated Financial Statements and related notes included in “Part II, Item 8. Financial Statements” of this Annual Report on Form 10-K.

Selected Financial Data

(In thousands, except per share amounts)

	Year Ended December 31,
	2012			2011			2010			2009			2008
Statement of Income Data:
Revenues	$	4,413,088		$	3,479,180		$	2,411,984		$	2,108,250		$	2,948,457
Costs and Expenses:
Product costs, service and other costs		3,292,969			2,599,267			1,874,294			1,640,198			2,234,974
Selling, general and administrative expenses		203,651			182,434			150,865			139,293			143,080
Depreciation and amortization expense		230,098			188,147			124,202			118,108			102,604
Impairment of goodwill		--			--			--			94,528			85,630
Other operating (income) expense		2,590			1,809			7,041			(2,606	)		(1,586	)
Operating income		683,780			507,523			255,582			118,729			383,755
Interest expense, net of capitalized interest		(68,922	)		(57,506	)		(16,274	)		(15,266	)		(23,585	)
Interest income		1,583			1,700			751			380			3,561
Equity in earnings (loss) of unconsolidated affiliates		243			(163	)		239			1,452			4,035
Other income		10,211			3,515			330			414			5,684
Income before income taxes		626,895			455,069			240,628			105,709			373,450
Income tax provision(1)		(177,047	)		(131,647	)		(72,023	)		(46,097	)		(154,151	)
Net income	$	449,848		$	323,422		$	168,605		$	59,612		$	219,299
Less: Net income attributable to noncontrolling interest		1,239			969			587			498			446

Net income attributable to Oil States International, Inc.	$	448,609		$	322,453		$	168,018		$	59,114		$	218,853

Net income per share attributable to Oil States International, Inc:
Basic	$	8.47		$	6.30		$	3.34		$	1.19		$	4.41
Diluted	$	8.10		$	5.86		$	3.19		$	1.18		$	4.26
Average common shares outstanding
Basic		52,959			51,163			50,238			49,625			49,622
Diluted		55,384			55,007			52,700			50,219			51,414

	Year Ended December 31,
	2012			2011			2010			2009			2008

Other Data:
EBITDA, as defined(2)	$	923,093		$	698,053		$	379,766		$	238,205		$	495,632
Capital expenditures, including capitalized interest		487,937			487,482			182,207			124,488			247,384
Acquisitions of businesses, net of cash acquired(3)		80,449			2,412			709,575			(18	)		29,835
Net cash provided by operating activities		637,483			215,913			230,922			453,362			257,464
Net cash used in investing activities, including capital expenditures(3)		(576,977	)		(488,955	)		(889,680	)		(102,608	)		(246,094	)
Net cash provided by (used in) financing activities		120,558			257,888			649,032			(296,773	)		(1,666	)

	At December 31,
	2012		2011		2010		2009		2008
Balance Sheet Data:
Cash and cash equivalents	$	253,172	$	71,721	$	96,350	$	89,742	$	30,199
Total current assets		1,826,092		1,489,659		1,100,004		925,568		1,237,484
Property, plant and equipment, net		1,852,126		1,557,088		1,252,657		749,601		695,338
Total assets		4,439,962		3,703,641		3,015,999		1,932,386		2,298,518
Long-term debt and capital leases, excluding current portion and 2 3/8% Notes		1,279,805		971,621		731,732		8,215		299,948
2 3/8% contingent convertible senior subordinated notes		--		170,884		163,108		155,859		149,110
Total stockholders' equity		2,465,800		1,963,272		1,628,933		1,382,066		1,235,541

(1)	Our effective tax rate increased in 2008 and 2009 due to the impairment of non-deductible goodwill.

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(2)

The term EBITDA as defined consists of net income plus interest expense, net, income taxes, depreciation and amortization. EBITDA as defined is not a measure of financial performance under generally accepted accounting principles. You should not consider it in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of profitability or liquidity. Additionally, EBITDA as defined may not be comparable to other similarly titled measures of other companies. The Company has included EBITDA as defined as a supplemental disclosure because its management believes that EBITDA as defined provides useful information regarding its ability to service debt and to fund capital expenditures and provides investors a helpful measure for comparing its operating performance with the performance of other companies that have different financing and capital structures or tax rates. The Company uses EBITDA as defined to compare and to monitor the performance of its business segments to other comparable public companies and as one of the primary measures to benchmark for the award of incentive compensation under its annual incentive compensation plan.

(3)	On December 30, 2010, we acquired all of the ordinary shares of The MAC for a total purchase price of $638.0 million, net of cash acquired.

We believe that net income is the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA as defined. The following table reconciles EBITDA as defined with our net income, as derived from our financial information (in thousands):

	Year Ended December 31,
	2012		2011		2010		2009		2008
Net income attributable to Oil States International, Inc.	$	448,609	$	322,453	$	168,018	$	59,114	$	218,853
Depreciation and amortization expense		230,098		188,147		124,202		118,108		102,604
Interest expense, net		67,339		55,806		15,523		14,886		20,024
Income tax provision		177,047		131,647		72,023		46,097		154,151
EBITDA, as defined	$	923,093	$	698,053	$	379,766	$	238,205	$	495,632

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 7 contains “forward-looking statements” - within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act that are based on management’s current expectations, estimates and projections about our business operations. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of numerous factors, including the known material factors set forth in “Part I, Item 1A. Risk Factors.” You should read the following discussion and analysis together with our Consolidated Financial Statements and the notes to those statements included elsewhere in this Annual Report on Form 10-K.

Macroeconomic Environment

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, met coal and other 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.

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In the past few years, crude oil prices have been volatile due to global economic movements and uncertainties including regional take-away capacity. In the first quarter of 2012, the price of West Texas Intermediates (WTI) crude oil increased from a monthly average price of $100 per barrel in January to $106 per barrel in March as positive economic news related to growth rates projected in China and other emerging markets, consumer spending and U.S. consumer confidence indicating that an economic recovery was underway. In addition, prices increased in response to tensions in the Middle East region which caused fears of supply disruption. However, crude oil prices came under pressure during the second quarter of 2012 due to increased crude oil inventories, insufficient take-away capacity in Cushing, Oklahoma, higher output expectations amid new technology and lower economic growth forecasts. In addition, certain regional markets such as the Bakken, Permian Basin and Eagle Ford were negatively impacted by significant discounts to WTI due to insufficient pipeline and rail take-away capacity. The spot price of WTI crude oil decreased to as low as $78 per barrel in the second quarter of 2012. Since the end of the second quarter of 2012, the spot price of crude oil has substantially recovered and, as of February 19, 2013, is trading at approximately $97 per barrel for WTI crude and approximately $118 per barrel for Intercontinental Exchange (ICE) Brent crude. If the global supply of oil and global inventory levels continue to decrease due to government instability in many oil-producing nations and energy demand continues to increase in countries such as China, India and the U.S., we could see continued and/or additional increases in WTI oil prices which could positively affect future U.S. drilling activity. In Canada, Western Canadian Select (WCS), which is the crude price that many of our oil sands accommodations customers receive, traded at a discount to WTI that ranged from $7.25 to $42.50 per barrel during 2012. The WCS discount was primarily due to increasing crude production from the Canadian oil sands region coupled with limited pipeline and rail capacity to transport the oil sands crude to heavy oil refineries either in the U.S. or Canada. This WCS discount had and is likely to continue to have a negative impact on our oil sands customers’ desire to invest in increased oil sands production. As of February 19, 2013, WCS is trading at a discount to WTI of $25.00.

In spite of WTI’s recovery to over $90 per barrel late in 2012 and in the first quarter of 2013, there remains a risk that crude prices deteriorate going forward due to potentially 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)(1)
Quarter ended	WTI		Brent Crude		Western Canadian Select
12/31/2012	$	88.01	$	110.15	$	61.34
9/30/2012		92.17		109.63		76.75
6/30/2012		93.38		108.90		73.53
3/31/2012		102.85		118.54		75.82
12/31/2011		94.03		109.31		81.56
9/30/2011		89.71		112.47		75.05
6/30/2011		102.51		117.12		84.72
3/31/2011		93.93		104.90		72.43
12/31/2010		85.10		86.80		69.07
9/30/2010		76.01		76.41		57.08

(1) Source: WTI and Brent prices from U.S. Energy Information Administration (EIA) and WCS prices from Bloomberg.

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Due to significant over-supply of natural gas stemming from increased production from shale plays, natural gas prices fell precipitously in the fourth quarter of 2011 and the first half of 2012, reaching a low of $1.82 in April 2012. Since these lows, prices for natural gas in the United States improved subsequent to April 2012, largely due to increased demand for natural gas for electrical power generation and 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 techniques. Natural gas prices are trading at approximately $3.30 per Mcf as of February 19, 2013. 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 as of February 19, 2013. 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 12% above the 5-year average as of the end 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:

Quarter ended	Natural Gas Average Price(1) (per mcf)
12/31/2012	$	3.40
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

(1) Source: natural gas prices from EIA.

Chinese steel production growth has fallen this year as European economies have contracted and U.S. economic growth has been 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 fell throughout 2012, but appear to have stabilized at current levels. Met coal prices have decreased from over $200/metric ton at the beginning of 2012 to approximately $160/metric ton at the end of 2012. Depressed met coal prices have led to some coal mine closures as well as delays in the start-up of some coal mining projects in Australia.

Various oil and gas industry analysts have projected increased 2013 global exploration and production expenditures compared to 2012. North American capital spending plans are likely to be lower year-over-year and are expected to be focused in oil-related onshore shale areas while international exploration and production budgets are expected to increase and primarily be spent on offshore projects.

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.

Generally, our oil sands and mining accommodations’ customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of ten years to in excess of thirty years and, consequently, these investments are dependent on those customers' longer-term view of commodity demand and prices. Oil sands development activity has increased over the past several years 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. 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, one of the Canadian oil sands potentially largest mining operations. In addition, several major and national oil companies have announced acquisitions and 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. With the WCS discount to WTI, several oil sands customers have announced the deferral of new oil sands projects, which could negatively affect our ability to expand our oil sands room count or our occupancy levels.

We are expanding our Australian accommodations capacity to meet increasing demand, notably in the Bowen Basin in Queensland and in the Gunnedah and Hunter basins in New South Wales to support coal production, and in Western Australia to support LNG and other energy-related projects. Accommodations deployed to support onshore U.S. drilling activity in several of the active shale play regions have also favorably contributed to our results.

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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.

In our well site services business segment, we predominantly provide completion services and, to a lesser extent, land drilling services. Our completion services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the completion 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 Mountain 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 the United States. 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.

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 completion 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 Rig Count for Year Ended December 31,
	2012		2011		2010		2009		2008
U.S. Land – Oil		1,335		966		573		270		377
U.S. Land - Natural gas and other		537		877		937		772		1,436
U.S. Offshore		47		32		31		44		65
Total U.S.		1,919		1,875		1,541		1,086		1,878
Canada		365		423		351		221		379
Total North America		2,284		2,298		1,892		1,307		2,257

The rig count fell precipitously in the first half of 2009 in response to the impact of the global economic downturn which negatively impacted energy prices but has substantially recovered from its June 2009 low. The average North American rig count for the year ended December 31, 2012 decreased by fourteen rigs, or less than 1%, compared to the average for the year ended December 31, 2011 largely due to a decline in natural gas drilling partially offset by growth in the U.S. land oil rig count.

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. For the year ended December 31, 2012, average U.S. dollar and Canadian and Australian dollar exchange rates were comparable with a less than 1% change over average exchange rates in 2011.

Steel and steel input prices influence the pricing decisions of our OCTG suppliers, thereby impacting the pricing and margins of our tubular services segment. Steel prices on a global basis declined precipitously during the recession in 2009. Industry inventories increased materially as the rig count declined, and OCTG imports remained at high levels. These developments in the OCTG marketplace had a material detrimental impact on OCTG pricing and, accordingly, on our revenues and margins realized during the last half of 2009 in our tubular services segment. These negative trends moderated in 2010 because of a reduction in imports, largely due to the imposition of trade sanctions on Chinese OCTG imports, coupled with increases in the U.S. rig count.

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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 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 increased well complexity coupled with the 2% year-over-year increase in the drilling rig count in the U.S. The OCTG Situation Report suggests that industry OCTG inventory levels have increased throughout 2012 and currently stand at five to six months' supply. Ample industry inventory on the ground along with increasing imports and domestic production coupled with modestly declining drilling activity put downward pressure on OCTG prices throughout 2012. Average OCTG prices declined 9% during 2012.

We remain focused on working capital management and generating 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 2012 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 improved. New well permitting has increased from 109 permits issued in 2011 to 179 permits issued in 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. Our capital expenditures in 2012 totaled $488 million compared to 2011 capital expenditures of $487 million. Our 2012 capital expenditures included funding to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Approximately two-thirds of our total 2012 capital expenditures were 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. We currently expect to spend a total of approximately $600 million to $650 million for capital expenditures during 2013.

Recent Acquisitions

On December 14, 2012, we acquired all of the equity of Tempress for purchase price consideration of $48.3 million consisting of $32.5 million of cash and contingent consideration with a fair value of $15.8 million. The Company funded escrow accounts totaling $25.3 million related to the contingent consideration and seller transaction indemnities which are classified as “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for contingent consideration and escrowed amounts potentially due to the seller total $21.1 million at December 31, 2012 and are classified as “Other noncurrent liabilities” in our Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.

On July 2, 2012, we acquired all of the operating assets of Piper for total cash consideration of $48.0 million. Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects located offshore (both surface and subsea) and onshore. The operations of Piper have been included in our offshore products segment since the acquisition date.

On November 1, 2011, we purchased an open camp accommodations facility located in Carrizo Springs, Texas for total consideration of $2.2 million. This facility provides accommodations support to customers working in the Eagle Ford Shale basin. The operations of the Carrizo Springs facility have been included in our accommodations segment since the acquisition date.

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On December 30, 2010, we acquired all of the ordinary shares of The MAC, through a Scheme of Arrangement (the Scheme) under the Corporations Act of Australia. The MAC is headquartered in Sydney, Australia and supplies accommodations services to the Australian natural resources market. Under the terms of the Scheme, each shareholder of The MAC received $3.95 (A$3.90) per share in cash. The total purchase price was $638 million, net of cash acquired plus debt assumed of $87 million. The MAC’s operations have been included in our accommodations segment beginning in 2011.

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

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

The Company funded all of its acquisitions with cash on hand and/or amounts available under our senior secured credit facilities. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our senior secured bank facilities.

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Consolidated Results of Operations (in millions)

	YEARS ENDED December 31,
							Variance 2012 vs. 2011					Variance 2011 vs. 2010
	2012			2011			$		%			2010			$		%
Revenues
Well site services -
Completion services	$	522.6		$	488.0		$	34.6		7	%	$	343.0		$	145.0		42	%
Drilling services		191.0			165.9			25.1		15	%		133.2			32.7		25	%
Total well site services		713.6			653.9			59.7		9	%		476.2			177.7		37	%
Accommodations		1,113.5			864.7			248.8		29	%		537.7			327.0		61	%
Offshore products		804.1			585.8			218.3		37	%		428.9			156.9		37	%
Tubular services		1,781.9			1,374.8			407.1		30	%		969.2			405.6		42	%
Total	$	4,413.1		$	3,479.2		$	933.9		27	%	$	2,412.0		$	1,067.2		44	%
Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Completion services	$	324.6		$	298.4		$	26.2		9	%	$	220.1		$	78.3		36	%
Drilling services		133.2			122.7			10.5		9	%		105.5			17.2		16	%
Total well site services		457.8			421.1			36.7		9	%		325.6			95.5		29	%
Accommodations		552.3			456.4			95.9		21	%		314.4			142.0		45	%
Offshore products		595.9			430.0			165.9		39	%		316.5			113.5		36	%
Tubular services		1,687.0			1,291.8			395.2		31	%		917.8			374.0		41	%
Total	$	3,293.0		$	2,599.3		$	693.7		27	%	$	1,874.3		$	725.0		39	%
Gross margin
Well site services -
Completion services	$	198.0		$	189.6		$	8.4		4	%	$	122.9		$	66.7		54	%
Drilling services		57.8			43.2			14.6		34	%		27.7			15.5		56	%
Total well site services		255.8			232.8			23.0		10	%		150.6			82.2		55	%
Accommodations		561.2			408.3			152.9		37	%		223.3			185.0		83	%
Offshore products		208.2			155.8			52.4		34	%		112.4			43.4		39	%
Tubular services		94.9			83.0			11.9		14	%		51.4			31.6		61	%
Total	$	1,120.1		$	879.9		$	240.2		27	%	$	537.7		$	342.2		64	%
Gross margin as a percentage of revenues
Well site services -
Completion services		38	%		39	%							36	%
Drilling services		30	%		26	%							21	%
Total well site services		36	%		36	%							32	%
Accommodations		50	%		47	%							42	%
Offshore products		26	%		27	%							26	%
Tubular services		5	%		6	%							5	%
Total		25	%		25	%							22	%

YEAR ENDED DECEMBER 31, 2012 COMPARED TO YEAR ENDED DECEMBER 31, 2011

We reported net income attributable to the Company for the year ended December 31, 2012 of $448.6 million, or $8.10 per diluted share, including a gain of $17.9 million, or $0.23 per diluted share after-tax, from a favorable contract settlement reported in our U.S. accommodations business and a pre-tax gain of $2.5 million, or $0.03 per diluted share after-tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012. These results compare to net income attributable to the Company of $322.5 million, or $5.86 per diluted share, reported for the year ended December 31, 2011.

Revenues. Consolidated revenues increased $933.9 million, or 27%, in 2012 compared to 2011.

Our well site services segment revenues increased $59.7 million, or 9%, in 2012 compared to 2011 primarily due to increases in both completion services revenues and drilling services revenues. Our completion services revenues increased $34.6 million, or 7%, in 2012 compared to 2011 primarily due to increased demand for our completion services supporting the 2% increase in the U.S. rig count, a more favorable mix of higher value rentals and services and greater service intensity. Our drilling services revenues increased $25.1 million, or 15%, in 2012 compared to 2011 primarily as a result of increases in pricing, with average day rates rising to $18,000 per day in 2012, up from $16,400 per day in 2011, and increased utilization of our rigs from an average of approximately 82% in 2011 to an average of approximately 88% in 2012.

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Our accommodations segment reported revenues in 2012 that were $248.8 million, or 29%, above 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 revenue per available room (RevPAR) for our lodges and villages increased 36%, 23% and 11%, respectively, in 2012 compared to 2011.

Our offshore products segment revenues increased $218.3 million, or 37%, in 2012 compared to 2011. This increase was primarily the result of higher levels of manufacturing and service activity, an improved revenue mix favoring our production equipment and connector products along with contributions from the acquisition of Piper which closed in July 2012.

Our tubular services segment revenues increased $407.1 million, or 30%, in 2012 compared to 2011. This increase was primarily a result of an increase in tons shipped from 699,000 in 2011 to 862,700 in 2012, an increase of 163,700 tons, or 23%. Higher volume resulted from the 2% 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 2012 compared to 2011 due to a more favorable mix of OCTG grades sold.

Cost of Sales and Service. Our consolidated cost of sales increased $693.7 million, or 27%, in 2012 compared to 2011. This cost of sales increase was directly related to the increase in revenue. Our consolidated gross margin as a percentage of revenues remained constant at 25% in 2012 and 2011.

Our well site services segment cost of sales increased $36.7 million, or 9%, in 2012 compared to 2011 as a result of a $26.2 million, or 9%, increase in completion services cost of sales and a $10.5 million, or 9%, increase in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues remained constant at 36% in both 2012 and 2011. Our completion services gross margin as a percentage of revenues declined modestly to 38% in 2012 compared to 39% in 2011. Our drilling services gross margin as a percentage of revenues increased from 26% in 2011 to 30% in 2012 primarily due to increased day rates, rig utilization and cost absorption.

Our accommodations segment cost of sales increased $95.9 million, or 21%, in 2012 compared to 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 2011 to 50% in 2012 primarily due to an 11% increase in RevPAR for lodges and villages in 2012 compared to 2011. The increase in the RevPAR in 2012 compared to 2011 was primarily due to increased occupancy levels.

Our offshore products segment cost of sales increased $165.9 million, or 39%, in 2012 compared to 2011 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues decreased modestly to 26% in 2012 compared to 27% in 2011.

Our tubular services segment cost of sales increased by $395.2 million, or 31%, in 2012 compared to 2011 primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues decreased from 6.0% in 2011 to 5.3% in 2012 primarily due to lower margin sales into certain onshore markets as a result of declining OCTG prices throughout 2012.

Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) expense increased $21.2 million, or 12%, in 2012 compared to 2011 primarily due to increased employee-related costs related to an 8% increase in total headcount, commissions and office expenses along with SG&A expense associated with the inclusion of Piper, which was acquired in July 2012.

Depreciation and Amortization. Depreciation and amortization expense increased $42.0 million, or 22%, in 2012 compared to 2011 primarily due to capital expenditures made during 2011 and 2012 largely related to investments in our Canadian and Australian accommodations and completion services businesses.

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Operating Income. Consolidated operating income increased $176.3 million, or 35%, in 2012 compared to 2011 primarily as a result of an increase in operating income from our accommodations segment of $115.7 million, or 46%, 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 $39.4 million, or 42%. In addition, operating income from our well site services segment increased $15.5 million, or 11%, largely due to increased dayrates and rig utilization in our drilling services business and a more favorable mix of services and increased activity in our completion services business. Operating income from our tubular services segment increased $10.6 million, or 16%, in 2012 compared to 2011 primarily as a result of the increase in tons shipped.

Interest Expense and Interest Income. Net interest expense increased by $11.5 million, or 21%, in 2012 compared to 2011 primarily due to interest expense on the 6 1/2% Senior Notes due 2019 (6 1/2% Notes), issued on June 1, 2011, partially offset by decreased interest expense on our 2 3/8% Notes due 2025 (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 3.0% in 2012 compared to 3.1% in 2011. Interest income decreased as a result of decreased cash balances in interest bearing accounts.

Income Tax Expense. Our income tax provision for 2012 totaled $177.0 million, or 28.2% of pretax income, compared to income tax expense of $131.6 million, or 28.9% of pretax income, for 2011. The effective tax rates of 28.2% and 28.9% for the years ended December 31, 2012 and 2011, respectively, are comparable and are lower than U.S. statutory rates because of lower foreign tax rates.

YEAR ENDED DECEMBER 31, 2011 COMPARED TO YEAR ENDED DECEMBER 31, 2010

We reported net income attributable to the Company for the year ended December 31, 2011 of $322.5 million, or $5.86 per diluted share. These results compare to net income attributable to the Company of $168.0 million, or $3.19 per diluted share, reported for the year ended December 31, 2010.

Revenues. Consolidated revenues increased $1.1 billion, or 44%, in 2011 compared to 2010.

Our well site services segment revenues increased $177.7 million, or 37%, in 2011 compared to 2010. This increase was primarily due to significantly increased completion services revenues. Our completion services revenues increased $145.0 million, or 42%, primarily due to increased demand for completion services supporting the 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 better pricing. Our drilling services revenues increased $32.7 million, or 25%, in 2011 compared to 2010 primarily as a result of increases in pricing, with average day rates rising to $16.4 thousand per day in 2011 from $14.2 thousand per day in 2010, and increased utilization of our rigs from an average of approximately 72% in 2010 to an average of approximately 82% in 2011.

Our accommodations segment reported revenues in 2011 that were $327.0 million, or 61%, above 2010. The increase in accommodations revenue resulted from the contribution from the fourth quarter 2010 acquisitions of The MAC and Mountain West along with increased revenues generated from expanded room capacity in Canada and Australia. Revenues and average available rooms for our oil sands lodges increased 40% and 30%, respectively, in 2011 compared to 2010.

Our offshore products segment revenues increased $156.9 million, or 37%, in 2011 compared to 2010. This increase was primarily the result of higher demand for production equipment and elastomer products along with contributions from the acquisition of Acute.

Tubular services segment revenues increased $405.6 million, or 42%, in 2011 compared to 2010. This increase was a result of an increase in tons shipped from 502,800 tons in 2010 to 699,000 tons in 2011, an increase of 196,200 tons, or 39%, driven by increased U.S. drilling and completion activity.

Cost of Sales and Service. Our consolidated cost of sales increased $725.0 million, or 39%, in 2011 compared to 2010. This cost of sales increase was directly related to the increase in revenue. Our consolidated gross margin as a percentage of revenues increased from 22% in 2010 to 25% in 2011 primarily due to the increased proportion of relatively higher margin accommodations and well site services segment revenues in 2011 compared to 2010 and higher margins realized in our accommodations and well site services segments, partially offset by an increased proportion of relatively lower margin tubular services segment revenues in 2011 compared to 2010.

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Our well site services segment cost of sales increased $95.5 million, or 29%, in 2011 compared to 2010 primarily as a result of a $78.3 million, or 36%, increase in completion services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 32% in 2010 to 36% in 2011. Our completion services gross margin as a percentage of revenues increased from 36% in 2010 to 39% in 2011 primarily due to a more favorable mix of higher value rentals and services and improved pricing along with higher fixed cost absorption as a result of increased rental tool utilization. Our drilling services cost of sales increased $17.2 million, or 16%, in 2011 compared to 2010. Our drilling services gross margin as a percentage of revenues increased from 21% in 2010 to 26% in 2011 primarily due to an increase in day rates, rig utilization and improved cost absorption.

Our accommodations segment cost of sales increased $142.0 million, or 45%, in 2011 compared to 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $36.2 million, or 12%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues and room capacity. Our accommodations segment gross margin as a percentage of revenues increased from 42% in 2010 to 47% in 2011 primarily due to higher margins realized on our lodges and villages.

Our offshore products cost of sales increased $113.5 million, or 36%, in 2011 compared to 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues increased modestly, 26% in 2010 compared to 27% in 2011.

Tubular services segment cost of sales increased by $374.0 million, or 41%, in 2011 compared to 2010 primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues increased from 5% in 2010 to 6% in 2011 due primarily to a 2% increase in revenue per ton.

Selling, General and Administrative Expenses. SG&A expense increased $31.6 million, or 21%, in 2011 compared to 2010 due primarily to the acquisition of The MAC, increased employee-related costs, higher SG&A costs in our Canadian accommodations business due to the strengthening of the Canadian dollar, increased third-party professional fees and increased commissions expense. SG&A was 5.2% of revenues in 2011 compared to 6.3% of revenues in 2010.

Depreciation and Amortization. Depreciation and amortization expense increased $63.9 million, or 51%, in 2011 compared to 2010 due primarily to $50.6 million in depreciation and amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made in 2010 and 2011, largely related to investments made in our Canadian accommodations business.

Operating Income. Consolidated operating income doubled to $251.9 million in 2011 compared to 2010 primarily as a result of an increase in operating income from our well site services segment of $93.3 million, or 195%, largely due to a more favorable mix, improved pricing and increased activity in our completion services business coupled with an increase in operating income as a result of the addition of The MAC. In addition, operating income from our offshore products segment increased $34.0 million, or 56%, in 2011 compared to 2010 and operating income from our tubular services segment increased $28.5 million, or 79%, primarily as a result of the increase in tons shipped. Operating income in 2011 and 2010 included $2.2 million and $7.0 million, respectively, in acquisition related expenses.

Interest Expense and Interest Income. Net interest expense increased by $40.3 million, or 260%, in 2011 compared to 2010 due to increased debt levels, interest expense on the 6 1/2% Notes issued on June 1, 2011, and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our revolving credit, term loan facilities and the 6 1/2% Notes. The weighted average interest rate on borrowings outstanding under the Company's revolving credit and term loan facilities was 3.1% in 2011 compared to 3.6% in 2010. Interest income increased as a result of increased cash balances in interest bearing accounts.

Income Tax Expense. Our income tax provision for 2011 totaled $131.6 million, or 28.9% of pretax income, compared to $72.0 million, or 29.9% of pretax income, for 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010, partially offset by an increase in state taxes.

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Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures, which in the past have included expanding our accommodations facilities, expanding and upgrading our offshore products manufacturing facilities and equipment, replacing and increasing completion services assets, funding new product development and 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 under our credit facilities and capital market transactions. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

Cash totaling $637.5 million was provided by operations during the year ended December 31, 2012 compared to cash totaling $215.9 million provided by operations during the year ended December 31, 2011. During 2012, $74.9 million was used to fund working capital, primarily due to increased investments in receivables and inventory in our offshore products segment coupled with higher OCTG inventory at our tubular services segment due to increased order activity. During 2011, $340.3 million was used to fund working capital, primarily due to increased investments in receivables and inventory in our tubular services and offshore products segments due to higher activity levels.

Cash was used in investing activities during the years ended December 31, 2012 and 2011 in the amounts of $577.0 million and $489.0 million, respectively. Capital expenditures totaled $487.9 million and $487.5 million during the years ended December 31, 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.

During the year ended December 31, 2012, we spent cash of $80.4 million to acquire all of the operating assets of Piper and all of the equity of Tempress. In addition, the Company funded escrow accounts totaling $25.3 million related to contingent consideration and seller transaction indemnities for the Tempress acquisition. This compares to $2.2 million spent during the year ended December 31, 2011 to acquire an open camp accommodations facility in Carrizo Springs, Texas to provide accommodations support to customers working in the Eagle Ford shale basin. The Company funded the acquisitions of Piper and Tempress from amounts available under the Company’s U.S. revolving credit facility. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

We currently expect to spend a total of approximately $600 million to $650 million for capital expenditures during 2013 to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Approximately two-thirds of our total estimated 2013 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 December 31, 2012, we had cash totaling $191.7 million held by foreign subsidiaries, primarily in Canada and the United Kingdom, where, in the case of Canada, we have assumed indefinite 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.

Net cash of $120.6 million was provided by financing activities during the year ended December 31, 2012, primarily as a result of proceeds from the issuance in the fourth quarter of 2012 of $400 million aggregate principal amount of 5 1/8% Senior Notes due 2023 (5 1/8% Notes), offset by net repayments of outstanding amounts under our revolving credit facilities, payments of principal amounts on the conversion of our 2 3/8% Notes and repayments on our U.S. and Canadian term loans. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our credit facilities. Net cash of $257.9 million was provided by financing activities during the year ended December 31, 2011, primarily as a result of proceeds from the issuance in the second quarter of 2011 of $600 million aggregate principal amount of the 6 1/2% Notes due in 2019, offset by net repayments of outstanding amounts under our revolving credit facilities. We incurred $7.9 million of costs to secure financings in 2012 compared to $13.5 million in 2011. See Note 8 to the Consolidated Financial Statements included in this Annual Report for additional information on our debt offerings.

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On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $175 million 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. In July 2012, rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $175 million 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. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

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 December 31, 2012, the Company had approximately 54.7 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 December 31, 2012, a total of $15.2 million of our stock (225,796 shares) had been repurchased under this program, leaving a total authorization of up to approximately $184.8 million remaining available under the program.

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 credit facilities are governed by an Amended and Restated Credit Agreement dated of December 10, 2010 (Credit Agreement) by and among the Company, PTI Group Inc., PTI Premium Camp Services, Ltd., the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent and U.S. collateral agent and Royal Bank of Canada, as Canadian administrative agent and Canadian collateral agent. The U.S. and Canadian revolving 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.

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The Credit Agreement contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0 in 2012 and 3.0 to 1.0 thereafter. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest as defined, exclude goodwill impairments, debt discount amortization and other non-cash charges. As of December 31, 2012, we were in compliance with our debt covenants and expect to continue to be in compliance during 2013. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to either LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. During the year 2012, our applicable margin over LIBOR ranged from 2.00% to 2.25% and it was 2.00% as of December 31, 2012. Our weighted average interest rate paid under the Credit Agreement was 2.7% during the year ended December 31, 2012 and 3.0% for the year ended December 31, 2011.

As of December 31, 2012, we had $255.8 million outstanding under the Credit Agreement and an additional $41.1 million of outstanding letters of credit, leaving $708.9 million available to be drawn under the U.S. and Canadian facilities.

5 1/8% Notes. On December 21, 2012, the Company sold $400 million aggregate principal amount of 5 1/8% Notes through a private placement to qualified institutional buyers.

The 5 1/8% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 5 1/8% per annum and mature on January 1, 2023. At any time prior to January 15, 2016, the Company may redeem up to 35% of the 5 1/8% Notes at a redemption price of 105.125% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to January 15, 2018, the Company may redeem some or all of the 5 1/8% 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 January 15, 2018, the Company may redeem some or all of the 5 1/8% 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 January 15,	% of Principal Amount
2018	102.563	%
2019	101.708	%
2020	100.854	%
2021 and thereafter	100.000	%

The Company utilized approximately $334 million of the net proceeds of the 5 1/8% Notes to repay borrowings under its U.S. credit facility. The remaining net proceeds of approximately $61 million were utilized for general corporate purposes.

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On December 21, 2012, in connection with the issuance of the 5 1/8% Notes, the Company entered into an Indenture (the 5 1/8% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The 5 1/8% Notes 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 5 1/8% 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 5 1/8% Notes 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 5 1/8% Notes Indenture contains customary events of default. As of December 31, 2012, the Company was in compliance with all covenants of the 5 1/8% Notes Indenture.

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

The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our 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 and thereafter	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 6 1/2% Notes 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 6 1/2% Notes 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 6 1/2% Notes Indenture contains customary events of default. As of December 31, 2012, the Company was in compliance with all covenants of the 6 1/2% Notes Indenture.

Our total debt represented 34.7% of our combined total debt and shareholders’ equity at December 31, 2012 compared to 37.5% at December 31, 2011.

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Contractual Obligations. The following summarizes our contractual obligations at December 31, 2012, and the effect such obligations are expected to have on our liquidity and cash flow over the next five years (in thousands):

	Payments due by period
	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
Contractual obligations
Total debt, including capital leases(1)	$	1,765,475	$	89,980	$	393,193	$	119,612	$	1,162,690
Purchase obligations		451,848		416,254		35,594		-		-
Non-cancelable operating lease obligations(2)		77,363		15,069		23,531		14,671		24,092
Asset retirement obligations - expected cash payments		16,350		344		271		904		14,831
Other non-current liabilities		25,089		-		25,089		-		-
Total contractual cash obligations	$	2,336,125	$	521,647	$	477,678	$	135,187	$	1,201,613

(1)

Includes interest on fixed-rate debt. Excludes interest on variable-rate debt. We cannot predict with any certainty the amount of interest due on our revolving debt due to the expected variability of interest rates and principal amounts outstanding. If we assume interest payment amounts are calculated using the outstanding principal balances, interest rates and foreign currency exchange rates as of December 31, 2012 and include applicable commitment fees, estimated interest payments on our credit facilities would be $20.0 million “due in less than one year” and $36.9 million “due in one to three years.” In the case of our outstanding term loans, applicable principal pay down amounts have been reflected in the interest payment calculations. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional for additional information on our credit facilities.

(2)

See Note 13 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information.

Our debt obligations at December 31, 2012 are included in our consolidated balance sheet, which is a part of our Consolidated Financial Statements included in this Annual Report on Form 10-K. We have not entered into any material leases subsequent to December 31, 2012.

Due to the uncertainty with respect to the timing of future cash flows associated with our uncertain tax positions at December 31, 2012, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. Therefore, $1.0 million in uncertain tax positions, including interest and penalties, have been excluded from the contractual obligations table above.

Effects of Inflation

Our revenues and results of operations have not been materially impacted by inflation in the past three fiscal years.

Off-Balance Sheet Arrangements

As of December 31, 2012, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.

Tax Matters

Our primary deferred tax assets at December 31, 2012, are related to employee benefit costs for our Equity Participation Plan, deductible goodwill and other intangibles, inventory allowance for obsolescence, and foreign tax credit carryforwards. The foreign tax credits will expire in varying amounts after 2019.

Our income tax provision for the year ended December 31, 2012 totaled $177.0 million, or 28.2% of pretax income, compared to $131.6 million, or 28.9% of pretax income, for the year ended December 31, 2011. The effective tax rates of 28.2% and 28.9% for the years ended December 31, 2012 and 2011, respectively, are comparable and are lower than U.S. statutory rates because of lower foreign tax rates.

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There are a number of legislative proposals to change the United States tax laws related to multinational corporations. These proposals are in various stages of discussion. It is not possible at this time to predict how these proposals would impact our business or whether they could result in increased tax costs.

Critical Accounting Policies

Our Consolidated Financial Statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally accepted in the United States (GAAP), which require that management make numerous estimates and assumptions. Actual results could differ from those estimates and assumptions, thus impacting our reported results of operations and financial position. The critical accounting policies and estimates described in this section are those that are most important to the depiction of our financial condition and results of operations and the application of which requires management’s most subjective judgments in making estimates about the effect of matters that are inherently uncertain. We describe our significant accounting policies more fully in Note 2 to Consolidated Financial Statements included in this Annual Report on Form 10-K.

Accounting for Contingencies

We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on their fair value or our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include future consideration due sellers as a result of the terms of a business combination, litigation, taxes, interest, insurance claims, warranty claims, contract claims and obligations and discontinued operations.

Asset Retirement Obligations

We recognize initial estimated asset retirement obligations (ARO) related to properties as liabilities, with an associated increase in property and equipment for the asset’s estimated retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated ARO changes, an adjustment is recorded to both the ARO and the capitalized asset retirement cost. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling the ARO. The Company derecognizes ARO liabilities when the related obligations are settled. At December 31, 2012, $5.5 million of ARO was included in the Consolidated Balance Sheet in “Other noncurrent liabilities.” The ARO liability reflects the estimated present value of the amount of asset removal and site reclamation costs related to the retirement of assets in the Company’s accommodations business. Total accretion expense related to the ARO was $0.3 million in 2012. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties and a risk-adjusted discount rate in order to determine the current present value of the obligation.

Tangible and Intangible Assets, including Goodwill

Our goodwill totaled $520.8 million, or 11.7%, of our total assets, as of December 31, 2012. Our other intangible assets totaled $146.1 million, or 3.3%, of our total assets, as of December 31, 2012. The assessment of impairment on long-lived assets, including intangibles, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. Indicators of impairment might include persistent negative economic trends affecting the markets we serve, recurring losses or lowered expectations of future cash flows expected to be generated by our assets. The determination of the amount of impairment would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether a decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment losses.

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We review each reporting unit at least annually or on an interim basis if an indicator of impairment was determined to occur, as defined in current accounting standards regarding goodwill to assess goodwill for potential impairment. Our reporting units include completion services, drilling, accommodations, offshore products and tubular services. There is no remaining goodwill in our drilling or tubular services reporting units subsequent to the full impairment of goodwill at those reporting units as of December 31, 2008. As part of the goodwill impairment analysis, current accounting standards give us the option to first perform a qualitative assessment to determine whether it is more likely than not (that is, a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. Current accounting standards also give us the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. In 2012, the Company chose to bypass the qualitative assessment for all of its reporting units with goodwill remaining and perform the two-step impairment test. In performing the two-step impairment test, we estimate the implied fair value (IFV) of each reporting unit and compare the IFV to the carrying value of such unit (the Carrying Value). Because none of our reporting units has a publically quoted market price, we must determine the value that willing buyers and sellers would place on the reporting unit through a routine sale process (a Level 3 fair value measurement). In our analysis, we target an IFV that represents the value that would be placed on the reporting unit by market participants, and value the reporting unit based on historical and projected results throughout a cycle, not the value of the reporting unit based on trough or peak earnings. We utilize, depending on circumstances, trading multiples analyses, discounted projected cash flow calculations with estimated terminal values and acquisition comparables to estimate the IFV. The IFV of our reporting units is affected by future oil and natural gas prices, anticipated spending by our customers, and the cost of capital. As part of our process to assess goodwill for impairment, we also compare the total market capitalization of the Company to the sum of the IFV's of all of our reporting units to assess the reasonableness of the IFV's in the aggregate. If the carrying amount of a reporting unit exceeds its IFV, goodwill is considered to be potentially impaired and additional analysis in accordance with current accounting standards is conducted to determine the amount of impairment, if any. In 2012, our quantitative assessment of potential goodwill impairment based on an analysis and comparison of trading multiples indicated that it is more likely than not that the fair value of each of our reporting units is greater than its carrying amount. At the date of our goodwill impairment test in 2012, the IFV of our offshore products, accommodations and completion services reporting units exceeded their carrying values by 172%, 50% and 101%, respectively.

As part of our process to assess goodwill for impairment in 2012 we also compared the total market capitalization of the Company to the sum of the IFV’s of all of our reporting units to assess the reasonableness of the IFV’s in the aggregate.

Revenue and Cost Recognition

Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectability is probable and pricing is fixed and determinable. Our product sales terms do not include significant post-delivery obligations. For significant projects, revenues are recognized under the percentage-of-completion method, measured by the percentage of costs incurred to date compared to estimated total costs for each contract (cost-to-cost method). Billings on such contracts in excess of costs incurred and estimated profits are classified as deferred revenue. Costs incurred and estimated profits in excess of billings on percentage-of-completion contracts are recognized as unbilled receivables. Management believes this method is the most appropriate measure of progress on large contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Factors that may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents. These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future reported earnings. In our accommodations and well site services segments, revenues are recognized based on a periodic (usually daily), or room rate or when the services are rendered. Proceeds from customers for the cost of oilfield rental equipment that is damaged or lost downhole are reflected as gains or losses on the disposition of assets after considering the write-off of the remaining net book value of the equipment. For drilling services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.

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Cost of goods sold includes all direct material and labor costs and those costs related to contract performance, such as indirect labor, supplies, tools and repairs. Selling, general, and administrative costs are charged to expense as incurred.

Valuation Allowances

Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required. We have, in past years, recorded a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized.

Estimation of Useful Lives

The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Our judgment in this area is influenced by our historical experience in operating our assets, technological developments and expectations of future demand for the assets. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.

Stock Based Compensation

Since the adoption of the accounting standards regarding share-based payments, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An initial estimate of the fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes Merton “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward vesting terms, option prices and option lives. Utilizing the Black Scholes Merton model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change assumptions for future awards as we consider appropriate.

Income Taxes

The Company follows the liability method of accounting for income taxes in accordance with current accounting standards regarding the accounting for income taxes. Under this method, deferred income taxes are recorded based upon the differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws in effect at the time the underlying assets or liabilities are recovered or settled.

When the Company's earnings from foreign subsidiaries are considered to be indefinitely reinvested, no provision for U.S. income taxes is made for these earnings. If any of the subsidiaries have a distribution of earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the various foreign countries.

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In accordance with current accounting standards, the Company records a valuation allowance in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. Management will continue to evaluate the appropriateness of the valuation allowance in the future based upon the operating results of the Company.

In accounting for income taxes, we are required by the provisions of current accounting standards regarding the accounting for uncertainty in income taxes, to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.

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.

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

In July 2012, the FASB issued an accounting standards update which is intended to reduce the cost and complexity of performing an impairment test for indefinite-lived intangible assets by simplifying how an entity tests those assets for impairment. The update is also intended to improve the consistency in impairment testing guidance among long-lived asset categories. Previous guidance required an entity to test indefinite-lived intangible assets for impairment by comparing the fair value of the asset with its carrying amount at least on an annual basis. If the carrying amount exceeded its fair value, an entity needed to recognize an impairment loss in the amount of the excess. The amendment to this update allows an entity to first assess the qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. This assessment will determine whether it is necessary to perform quantitative impairment tests. This type of testing results in guidance that is similar to the September 2011 accounting standards update issued for goodwill impairment testing described above. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 with early adoption permitted. As permitted, we adopted these provisions in 2012. The adoption of this standard did not have a material effect on our consolidated financial statements.

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ITEM 7A. Quantitative And Qualitative Disclosures About Market Risk

Our principal market risks are our exposure to changes in interest rates and foreign currency exchange rates.

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 December 31, 2012, we had floating-rate obligations totaling approximately $303.6 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 increase by 1%, our consolidated interest expense would increase by a total of approximately $3.0 million annually based on our floating debt obligations as of December 31, 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 2012, our reported foreign exchange losses were $2.1 million and are included in “Other operating (income)/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 December 31, 2012, we had outstanding foreign currency forward purchase contracts with a notional amount of $12.4 million, hedging expected cash flows denominated in Euros. We have recorded other comprehensive loss of $1.0 million in 2012 as a result of this contract. As of December 31, 2011, we had no active hedge contracts outstanding.

Item 8. Financial Statements and Supplementary Data

Our Consolidated Financial Statements and supplementary data of the Company appear on pages 72 through 114 of this Annual Report on Form 10-K and are incorporated by reference into this Item 8. Selected quarterly financial data is set forth in Note 16 to our Consolidated Financial Statements, which is incorporated herein by reference.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

There were no changes in or disagreements on any matters of accounting principles or financial statement disclosure between us and our independent auditors during our two most recent fiscal years or any subsequent interim period.

Item 9A. Controls and Procedures

(i) Evaluation of Disclosure Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, 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 December 31, 2012 at the reasonable assurance level.

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Pursuant to section 906 of The Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Commission. These certifications accompanied this report when filed with the Commission, but are not set forth herein.

(ii) Internal Control Over Financial Reporting

(a) Management's annual report on internal control over financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012 was conducted. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control–Integrated Framework. Based on our assessment we believe that, as of December 31, 2012, the Company's internal control over financial reporting is effective based on those criteria.

In July and December 2012, the Company acquired all of the assets of Piper and all of the equity of Tempress, respectively. The Company will begin the process of evaluating Piper’s and Tempress' internal controls during 2013. As permitted by the related Securities and Exchange Commission (SEC) staff’s interpretative guidance for newly acquired businesses, the Company excluded Piper and Tempress from management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2012. In the aggregate, Piper and Tempress represented 2.6% of the total assets and less than 1% of total revenues of the Company as of and for the fiscal year ended December 31, 2012.

(b) Attestation report of the registered public accounting firm.

The attestation report of Ernst & Young LLP, the Company's independent registered public accounting firm, on the Company's internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 74 and is incorporated herein by reference.

During the Company's fourth fiscal quarter ended December 31, 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.

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Item 9B. Other Information

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2012 that was not reported on a Form 8-K during such time.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

(1)

Information concerning directors, including the Company's audit committee financial expert, appears in the Company's Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders, under "Election of Directors." This portion of the Definitive Proxy Statement is incorporated herein by reference.

(2)

Information with respect to executive officers appears in the Company's Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders, under "Executive Officers of the Registrant." This portion of the Definitive Proxy Statement is incorporated herein by reference.

(3)

Information concerning Section 16(a) beneficial ownership reporting compliance appears in the Company's Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders, under "Section 16(a) Beneficial Ownership Reporting Compliance." This portion of the Definitive Proxy Statement is incorporated herein by reference.

Item 11. Executive Compensation

The information required by Item 11 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by Item 12 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by Item 13 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

Item 14. Principal Accounting Fees and Services

Information concerning principal accounting fees and services and the audit committee's preapproval policies and procedures appear in the Company's Definitive Proxy Statement for the 2013 Annual Meeting of Stockholders under the heading "Fees Paid to Ernst & Young LLP" and is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) Index to Financial Statements, Financial Statement Schedules and Exhibits

(1) Financial Statements: Reference is made to the index set forth on page 72 of this Annual Report on Form 10-K.

(2) Financial Statement Schedules: No schedules have been included herein because the information required to be submitted has been included in the Consolidated Financial Statements or the Notes thereto, or the required information is inapplicable.

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(3) Index of Exhibits: See Index of Exhibits, below, for a list of those exhibits filed herewith, which index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Annual Report on Form 10-K by Item 601 of Regulation S-K.

(b)

Index of Exhibits

Exhibit Index

Exhibit No.		Description
2.1	—	Scheme Implementation Deed, dated October 15, 2010, by and between Oil States International, Inc. and The MAC Services Group Limited (incorporated by reference to Exhibit 2.1 to Oil States’ Current Report on Form 8-K, as filed with the Commission on October 15, 2010 (File No. 001-16337)).

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	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1, as filed with the Commission on November 7, 2000 (File No. 333-43400)).


4.2	—	Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).


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

4.4	—	Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Exhibit 4.4 to Oil States' Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).

4.5	—	Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Oil States' Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).

4.6	—	Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 to Oil States' Current Reports on Form 8-K as filed with the Commission on June 23, 2005 and July 13, 2005 (File No. 001-16337)).
4.7	—	Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

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

4.9	—	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)).

4.10	—	Indenture dated as of December 21, 2012 among Oil States International, Inc., the Guarantors named therein, and Wells Fargo Bank, N.A., as trustee, paying agent and registrar (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on December 21, 2012 (File No. 001-16337)).

4.11*	—	First Supplemental Indenture, dated as of February 15, 2013, among Tempress Technologies, Inc., 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.

4.12*	—	Second Supplemental Indenture, dated as of February 15, 2013, among Tempress Technologies, Inc., 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.

10.1	—	Combination Agreement dated as of July 31, 2000 by and among Oil States International, Inc., HWC Energy Services, Inc., Merger Sub-HWC, Inc., Sooner Inc., Merger Sub-Sooner, Inc. and PTI Group Inc. (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1, as filed with the Commission on August 10, 2000 (File No. 333-43400)).

10.2	—	Plan of Arrangement of PTI Group Inc. (incorporated by reference to Exhibit 10.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

10.3	—	Support Agreement between Oil States International, Inc. and PTI Holdco (incorporated by reference to Exhibit 10.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).



10.4	—	Voting and Exchange Trust Agreement by and among Oil States International, Inc., PTI Holdco and Montreal Trust Company of Canada (incorporated by reference to Exhibit 10.4 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).



10.5**	—	Second Amended and Restated 2001 Equity Participation Plan effective March 30, 2009 (incorporated by reference to Exhibit 10.5 to Oil States' Current Report on Form 8-K, as filed with the Commission on April 2, 2009 (File No. 001-16337)).


10.6**	—	Deferred Compensation Plan effective November 1, 2003 (incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31, 2003, as filed with the Commission on March 5, 2004 (File No. 001-16337)).

10.7**	—	Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).


10.8**	—	Executive Agreement between Oil States International, Inc. and Cindy B. Taylor (incorporated by Reference to Exhibit 10.9 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

10.9**	—	Form of Change of Control Severance Plan for Selected Members of Management (incorporated by reference to Exhibit 10.11 of the Company's Registration Statement on Form S-1, as filed with the Commission on December 12, 2000 (File No. 333-43400)).


10.10	—	Credit Agreement, dated as of October 30, 2003, among Oil States International, Inc., the Lenders named therein and Wells Fargo Bank Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12 to the Company's Quarterly Report on Form 10-Q for the three months ended September 30, 2003, as filed with the Commission on November 12, 2003 (File No. 001-16337)).

10.10A	—	Incremental Assumption Agreement, dated as of May 10, 2004, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12A to the Company's Quarterly Report on Form 10-Q for the three months ended June 30, 2004, as filed with the Commission on August 4, 2004 (File No. 001-16337)).

10.10B	—	Amendment No. 1, dated as of January 31, 2005, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12B to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

10.10C	—	Amendment No. 2, dated as of December 5, 2006, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12C to the Company's Current Report on Form 8-K, as filed with the Commission on December 8, 2006 (File No. 001-16337)).

10.10D	—	Incremental Assumption Agreement, dated as of December 13, 2007, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12D to the Company's Current Report on Form 8-K, as filed with the Commission on December 18, 2007 (File No. 001-16337)).

10.10E	—	Amendment No. 3, dated as of October 1, 2009, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.11E to the Company's Current Report on Form 8-K, as filed with the Commission on October 2, 2009 (File No. 001-16337)).

10.10F	—	Amended and Restated Credit Agreement, dated as of December 10, 2010, among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., as borrowers, the lenders named therein and Wells Fargo Bank, N.A., as Administrative Agent, U.S. Collateral Agent, the U.S. Swing Line Lender and an Issuing Bank; and Royal Bank of Canada, as Canadian Administrative Agent, Canadian Collateral Agent and the Canadian Swing Line Lender; JP Morgan Chase Bank, N.A., as Syndication Agent and Wells Fargo Securities, LLC, RBC Capital Markets and JP Morgan Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, as filed with the Commission on December 20, 2010 (File No. 001-16337)).

10.10G	—	Facility Agreement dated July 13, 2011, between The MAC Services Group Pty Limited and National Australia Bank Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on July 15, 2011 (File No. 001-16337)).


10.10H	—	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, Issuing Bank and 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)).

10.10I	—	Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of September 18, 2012, among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., each of the Guarantors named therein, the Lenders party thereto 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)).

10.11**	—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.14 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, as filed with the Commission on November 5, 2004 (File No. 001-16337)).

10.12**	—	Form of Director Stock Option Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

10.13**	—	Form of Employee Non Qualified Stock Option Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

10.14**	—	Form of Restricted Stock Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

10.15**	—	Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.21 to the Company's Report on Form 8-K as filed with the Commission on November 15, 2006 (File No. 001-16337)).

10.16**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Mr. Cragg) (incorporated by reference to Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, as filed with the Commission on April 29, 2005 (File No. 001-16337)).

10.17**	—	Form of Non-Employee Director Restricted Stock Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.22 to the Company's Report of Form 8-K, as filed with the Commission on May 24, 2005 (File No. 001-16337)).

10.18**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Bradley Dodson) effective October 10, 2006 (incorporated by reference to Exhibit 10.24 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, as filed with the Commission on November 3, 2006 (File No. 001-16337)).

10.19**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Ron R. Green) effective May 17, 2007 (incorporated by reference to Exhibit 10.25 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, as filed with the Commission on August 2, 2007 (File No. 001-16337)).

	10.20**	—	Amendment to the Executive Agreement of Cindy Taylor, effective January 1, 2009 (incorporated by reference to Exhibit 10.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

	10.21**	—	Amendment to the Executive Agreement of Bradley Dodson, effective January 1, 2009 (incorporated by reference to Exhibit 10.22 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

	10.22**	—	Amendment to the Executive Agreement of Christopher Cragg, effective January 1, 2009 (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

	10.23**	—	Amendment to the Executive Agreement of Ron Green, effective January 1, 2009 (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

	10.24**	—	Amendment to the Executive Agreement of Robert Hampton, effective January 1, 2009 (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

	10.25**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Charles Moses), effective March 4, 2010 (incorporated by reference to Exhibit 10.26 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, as filed with the Commission on April 30, 2010 (File No. 001-16337)).

	10.26**	—	Call Option Agreement, dated October 15, 2010, by and between Marley Holdings Pty Limited and PTI Holding Company 2 Pty Limited (incorporated by reference to Exhibit 10.1 to Oil States’ Current Report on Form 8-K, as filed with the Commission on October 5, 2010 (File No. 001-16337)).

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

	10.28**	—	Deferred Stock Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on February 23, 2012 (File No. 001-16337)).


	21.1*	—	List of subsidiaries of the Company.

	23.1*	—	Consent of Independent Registered Public Accounting Firm.

	24.1*	—	Powers of Attorney for Directors.

	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.

- 70 -

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 on February 20, 2013.

	OIL STATES INTERNATIONAL, INC.


	By	/s/ CINDY B. TAYLOR
		Cindy B. Taylor
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 20, 2013.

Signature		Title

/s/ STEPHEN A. WELLS*		Chairman of the Board
Stephen A. Wells

/s/ CINDY B. TAYLOR		Director, President & Chief Executive Officer
Cindy B. Taylor		(Principal Executive Officer)

/s/ BRADLEY J. DODSON		Senior Vice President, Chief Financial Officer
Bradley J. Dodson		and Treasurer
		(Principal Financial Officer)

/s/ ROBERT W. HAMPTON		Senior Vice President —Accounting and Corporate Secretary
Robert W. Hampton		(Principal Accounting Officer)

/s/ MARTIN A. LAMBERT*		Director
Martin A. Lambert

/s/ S. JAMES NELSON, JR.*		Director
S. James Nelson, Jr.

/s/ MARK G. PAPA*		Director
Mark G. Papa

/s/ GARY L. ROSENTHAL*		Director
Gary L. Rosenthal

/s/ CHRISTOPHER T. SEAVER*		Director
Christopher T. Seaver

/s/ DOUGLAS E. SWANSON*		Director
Douglas E. Swanson

/s/ WILLIAM T. VAN KLEEF*		Director
William T. Van Kleef


*By:	/s/ BRADLEY J. DODSON
	Bradley J. Dodson, pursuant to a power of
	attorney filed as Exhibit 24.1 to this
	Annual Report on Form 10-K

- 71 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

INDEX TO

CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	73
Report of Independent Registered Public Accounting Firm on the Company's Internal Control Over Financial Reporting	74
Consolidated Statements of Income for the Years Ended December 31, 2012, 2011, and 2010	75
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011, and 2010	76
Consolidated Balance Sheets at December 31, 2012 and 2011	77
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2012, 2011 and 2010	78
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011, and 2010	79
Notes to Consolidated Financial Statements	80 – 114

- 72 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Oil States International, Inc.:

We have audited the accompanying consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oil States International, Inc. and subsidiaries at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 20, 2013

- 73 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Oil States International, Inc.:

We have audited Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Oil States International, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s annual report on internal control over financial reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

As indicated in the accompanying Management's annual report on internal control over financial reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the business acquired from Piper Valve Systems, Ltd. and Tempress Technologies, Inc. which is included in the 2012 consolidated financial statements of Oil States International, Inc. and subsidiaries and constituted 2.6 percent of total assets as of December 31, 2012 and less than 1 percent of revenues for the year then ended. Our audit of internal control over financial reporting of Oil States International, Inc. and subsidiaries’ also did not include an evaluation of the internal control over financial reporting of the business acquired from Piper Valve Systems, Ltd. and Tempress Technologies, Inc.

In our opinion, Oil States International, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012 and our report dated February 20, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 20, 2013

- 74 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2012			2011			2010
Revenues:
Product	$	2,429,139		$	1,815,526		$	1,282,212
Service and other		1,983,949			1,663,654			1,129,772
		4,413,088			3,479,180			2,411,984
Costs and expenses:
Product costs		2,174,000			1,617,399			1,147,427
Service and other costs		1,118,969			981,868			726,867
Selling, general and administrative expenses		203,651			182,434			150,865
Depreciation and amortization expense		230,098			188,147			124,202
Other operating expense		2,590			1,809			7,041
		3,729,308			2,971,657			2,156,402
Operating income		683,780			507,523			255,582

Interest expense, net of capitalized interest		(68,922	)		(57,506	)		(16,274	)
Interest income		1,583			1,700			751
Equity in earnings (loss) of unconsolidated affiliates		243			(163	)		239
Other income		10,211			3,515			330
Income before income taxes		626,895			455,069			240,628
Income tax provision		(177,047	)		(131,647	)		(72,023	)
Net income	$	449,848		$	323,422		$	168,605
Less: Net income attributable to noncontrolling interests		1,239			969			587
Net income attributable to Oil States International, Inc.	$	448,609		$	322,453		$	168,018

Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	8.47		$	6.30		$	3.34
Diluted	$	8.10		$	5.86		$	3.19
Weighted average number of common shares outstanding (in thousands):
Basic		52,959			51,163			50,238
Diluted		55,384			55,007			52,700

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

- 75 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

	Year Ended December 31,
	2012			2011			2010

Net income	$	449,848		$	323,422		$	168,605

Other comprehensive income (loss):
Foreign currency translation adjustment		33,450			(10,079	)		40,274
Unrealized loss on forward contracts, net of tax		(724	)		--			--
Other		--			(99	)		160
Total other comprehensive income (loss)		32,726			(10,178	)		40,434

Comprehensive income		482,574			313,244			209,039
Comprehensive income attributable to noncontrolling interest		(1,256	)		(948	)		(612	)
Comprehensive income attributable to Oil States International, Inc.	$	481,318		$	312,296		$	208,427

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

- 76 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	253,172		$	71,721
Accounts receivable, net		832,785			732,240
Inventories, net		701,496			653,698
Prepaid expenses and other current assets		38,639			32,000
Total current assets		1,826,092			1,489,659

Property, plant and equipment, net		1,852,126			1,557,088
Goodwill, net		520,818			467,450
Other intangible assets, net		146,103			127,602
Other noncurrent assets		94,823			61,842
Total assets	$	4,439,962		$	3,703,641

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	279,933		$	252,209
Accrued liabilities		107,906			96,748
Income taxes		29,588			10,395
Current portion of long-term debt and capitalized leases		30,480			34,435
Deferred revenue		66,311			75,497
Other current liabilities		4,314			5,665
Total current liabilities		518,532			474,949

Long-term debt and capitalized leases		1,279,805			1,142,505
Deferred income taxes		129,235			97,377
Other noncurrent liabilities		46,590			25,538
Total liabilities		1,974,162			1,740,369

Stockholders' equity:
Oil States International, Inc. stockholders' equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 58,488,299 shares and 54,803,539 shares issued, respectively, and 54,695,473 shares and 51,288,750 shares outstanding, respectively		585			548
Additional paid-in capital		586,070			545,730
Retained earnings		1,899,195			1,450,586
Accumulated other comprehensive income		107,097			74,371
Common stock held in treasury at cost, 3,792,826 and 3,514,789 shares, respectively		(128,542	)		(109,079	)
Total Oil States International, Inc. stockholders' equity		2,464,405			1,962,156
Noncontrolling interest		1,395			1,116
Total stockholders' equity		2,465,800			1,963,272
Total liabilities and stockholders' equity	$	4,439,962		$	3,703,641

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

- 77 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands)

	Common Stock			Additional Paid-In Capital			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Noncontrolling Interest			Total Stockholders' Equity

Balance, December 31, 2009	$	531		$	468,428		$	960,115	$	44,115		$	(92,341	)	$	1,218		$	1,382,066
Net income								168,018								587			168,605
Currency translation adjustment										40,274						25			40,299
Other comprehensive loss										160									160
Dividends paid																(803	)		(803	)
Exercise of stock options, including tax benefit		9			27,380														27,389
Amortization of restricted stock compensation					6,592														6,592
Stock option expense					6,028														6,028
Surrender of stock to pay taxes on restricted stock awards		2			(2	)							(1,406	)					(1,406	)
Other		(1	)		3								1						3
Balance, December 31, 2010	$	541		$	508,429		$	1,128,133	$	84,549		$	(93,746	)	$	1,027		$	1,628,933
Net income								322,453								969			323,422
Currency translation adjustment										(10,079	)					(21	)		(10,100	)
Other comprehensive income										(99	)								(99	)
Dividends paid																(859	)		(859	)
Exercise of stock options, including tax benefit		5			22,732														22,737
Amortization of restricted stock compensation					8,412														8,412
Stock option expense					6,153														6,153
Surrender of stock to pay taxes on restricted stock awards		2			(2	)							(2,702	)					(2,702	)
Stock acquired for cash													(12,632	)					(12,632	)
Other					6								1						7
Balance, December 31, 2011	$	548		$	545,730		$	1,450,586	$	74,371		$	(109,079	)	$	1,116		$	1,963,272
Net income								448,609								1,239			449,848
Currency translation adjustment										33,450						17			33,467
Unrealized loss on forward contracts, net of tax										(724	)								(724	)
Dividends paid																(977	)		(977	)
Exercise of stock options, including tax benefit		5			21,465														21,470
Amortization of restricted stock compensation					13,390														13,390
Stock option expense					5,514														5,514
Surrender of stock to pay taxes on restricted stock awards		2			(2	)							(4,218	)					(4,218	)
Stock acquired for cash													(15,245	)					(15,245	)
Conversion of 2 3/8% Notes - reacquisition of equity component					(220,597	)													(220,597	)
Shares issued upon conversion of 2 3/8% Notes		30			220,566														220,596
Other					4														4
Balance, December 31, 2012	$	585		$	586,070		$	1,899,195	$	107,097		$	(128,542	)	$	1,395		$	2,465,800

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities:
Net income	$	449,848		$	323,422		$	168,605
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		230,098			188,147			124,202
Deferred income tax provision		17,370			27,075			20,590
Excess tax benefits from share-based payment arrangements		(8,164	)		(8,583	)		(4,029	)
Non-cash compensation charge		18,904			14,565			12,620
Losses (gains) on disposals of assets		(8,600	)		(3,614	)		211
Accretion of debt discount		4,106			7,786			7,249
Amortization of deferred financing costs		7,301			6,497			1,703
Other, net		1,535			960			(263	)
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		(83,379	)		(260,186	)		(61,835	)
Inventories		(34,182	)		(154,290	)		(75,416	)
Accounts payable and accrued liabilities		30,697			47,610			82,032
Taxes payable		17,960			24,789			(22,468	)
Other current assets and liabilities, net		(6,011	)		1,735			(22,279	)
Net cash flows provided by operating activities		637,483			215,913			230,922

Cash flows from investing activities:
Capital expenditures, including capitalized interest		(487,937	)		(487,482	)		(182,207	)
Acquisitions of businesses, net of cash acquired		(80,449	)		(2,412	)		(709,575	)
Proceeds from disposition of property, plant and equipment		14,653			5,949			2,734
Deposits held in escrow related to acquisitions of businesses		(20,000	)		--			--
Other, net		(3,244	)		(5,010	)		(632	)
Net cash flows used in investing activities		(576,977	)		(488,955	)		(889,680	)

Cash flows from financing activities:
Revolving credit borrowings and (repayments), net		(64,251	)		(316,736	)		347,129
6 1/2 % senior notes issued		--			600,000			--
Payment of principal on 2 3/8% Notes conversion		(174,990	)		(10	)		--
5 1/8 % senior notes issued		400,000			--			--
Term loan borrowings (repayments)		(30,047	)		(14,972	)		300,955
Debt and capital lease repayments		(4,569	)		(2,529	)		(487	)
Issuance of common stock from share based payment arrangements		13,628			14,154			23,361
Purchase of treasury stock		(15,245	)		(12,632	)		--
Excess tax benefits from share based payment arrangements		8,164			8,583			4,029
Payment of financing costs		(7,914	)		(13,464	)		(24,548	)
Tax withholdings related to net share settlements of restricted stock		(4,218	)		(2,702	)		(1,406	)
Other, net		--			(1,804	)		(1	)
Net cash flows provided by financing activities		120,558			257,888			649,032

Effect of exchange rate changes on cash		680			(9,332	)		16,477
Net increase (decrease) in cash and cash equivalents from continuing operationscontinuing operations		181,744			(24,486	)		6,751
Net cash used in discontinued operations – operating activities		(293	)		(143	)		(143	)
Cash and cash equivalents, beginning of year		71,721			96,350			89,742

Cash and cash equivalents, end of year	$	253,172		$	71,721		$	96,350

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

The Consolidated Financial Statements include the accounts of Oil States International, Inc. (Oil States or the Company) and its consolidated subsidiaries. Investments in unconsolidated affiliates, in which the Company is able to exercise significant influence, are accounted for using the equity method. All significant intercompany accounts and transactions between the Company and its consolidated subsidiaries have been eliminated in the accompanying Consolidated Financial Statements.

The Company, through its subsidiaries, is a leading provider of specialty products and services to natural resources companies throughout the world. We operate in a substantial number of the world's active oil, natural gas and coal producing regions, including Canada, onshore and offshore U.S., Australia, West Africa, the North Sea, South America and Southeast and Central Asia. The Company operates in four principal reportable business segments – accommodations, offshore products, well site services and tubular services.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Fair Value of Financial Instruments

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 6 1/2%, 5 1/8% and 2 3/8% Notes (before their redemption in July 2012), on the accompanying consolidated balance sheets approximate their fair values.

The fair values of our 6 1/2%, 5 1/8% and 2 3/8% Notes (before their redemption in July 2012) 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 for the periods indicated (in thousands):

			December 31, 2012				December 31, 2011
	Interest Rate		Carrying Value		Fair Value		Carrying Value		Fair Value
6 1/2% Notes
Principal amount due 2019	6 1/2	%	$	600,000	$	641,628	$	600,000	$	625,128

5 1/8% Notes
Principal amount due 2023	5 1/8	%	$	400,000	$	405,752	$	-	$	-

2 3/8% Notes
Principal amount	2 3/8	%	$	-	$	-	$	174,990	$	411,396
Less: unamortized discount				-		-		4,106		-
Net value			$	-	$	-	$	170,884	$	411,396

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

See Note 9 – “Derivative Instruments and Hedging Activities” for a discussion of the fair values of the Company’s foreign currency forward contracts.

As of December 31, 2012 and 2011, the carrying value of the Company's debt outstanding under its credit facilities was estimated to be at fair value.

Restricted Cash

At December 31, 2012, cash of $25.3 million held in escrow accounts and subject to terms of acquisition agreements providing for contingent consideration and seller representation and warranty provisions and are included in “Other noncurrent assets” in our Consolidated Balance Sheets.

Inventories

Inventories consist of tubular and other oilfield products, manufactured equipment, spare parts for manufactured equipment, work-in-process, raw materials and supplies and materials for the construction of remote accommodation facilities. Inventories include raw materials, labor, subcontractor charges and manufacturing overhead and are carried at the lower of cost or market. The cost of inventories is determined on an average cost or specific-identification method. A reserve for excess, damaged, remnants and/or obsolete inventory is maintained based on the age, turnover or condition of the inventory.

Property, Plant, and Equipment

Property, plant, and equipment are stated at cost or at estimated fair market value at acquisition date if acquired in a business combination, and depreciation is computed, for assets owned or recorded under capital lease, using the straight-line method, after allowing for salvage value where applicable, over the estimated useful lives of the assets. We use the component depreciation method for our drilling services and Australian accommodations assets. Leasehold improvements are capitalized and amortized over the lesser of the life of the lease or the estimated useful life of the asset.

Expenditures for repairs and maintenance are charged to expense when incurred. Expenditures for major renewals and betterments, which extend the useful lives of existing equipment, are capitalized and depreciated. Upon retirement or disposition of property and equipment, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized in the statements of income.

Asset Retirement Obligations

We recognize initial estimated asset retirement obligations (ARO) related to properties as liabilities, with an associated increase in property and equipment for the asset’s estimated retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated ARO changes, an adjustment is recorded to both the ARO and the capitalized asset retirement cost. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling the ARO. The Company relieves ARO liabilities when the related obligations are settled. At December 31, 2012, $5.5 million of ARO was included in the Consolidated Balance Sheet in “Other noncurrent liabilities.” The ARO liability reflects the estimated present value of the amount of asset removal and site reclamation costs related to the retirement of assets in the Company’s accommodations business. Total accretion expense related to the ARO was $0.3 million in 2012. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties and a risk-adjusted discount rate in order to determine the current present value of the obligation.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price paid for acquired businesses over the allocated fair value of the related net assets after impairments, if applicable. Goodwill is stated net of accumulated amortization of $11 million as of December 31, 2012 and 2011.

We evaluate goodwill for impairment annually and when an event occurs or circumstances change to suggest that the carrying amount may not be recoverable. Our reporting units with goodwill include accommodations, offshore products and completion services. In accordance with current accounting standards, we are given the option to test for impairment of our goodwill by first performing a qualitative assessment to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. Current accounting standards also give us the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. In 2012, the Company chose to bypass the qualitative assessment for all of its reporting units with goodwill remaining and perform the two-step impairment test. In performing the two-step impairment test, we compare the reporting unit's carrying amount, including goodwill, to the implied fair value (IFV) of the reporting unit. The IFV of the reporting units are estimated using an analysis of trading multiples of comparable companies to our reporting units. We also utilize discounted projected cash flows and acquisition multiples analyses in certain circumstances. We discount our projected cash flows using a long-term weighted average cost of capital for each reporting unit based on our estimate of investment returns that would be required by a market participant. If the carrying amount of the reporting unit exceeds its fair value, goodwill is considered impaired, and a second step is performed to determine the amount of impairment, if any. We conduct our annual impairment test in December of each year. In 2012, our quantitative assessment of potential goodwill impairment based on an analysis and comparison of trading multiples indicated that it is more likely than not that the fair value of each of our reporting units is greater than its carrying amount.

For intangible assets that we amortize, we review the useful life of the intangible asset and evaluate each reporting period whether events and circumstances warrant a revision to the remaining useful life. We evaluate the remaining useful life of an intangible asset that is not being amortized each reporting period to determine whether events and circumstances continue to support an indefinite useful life.

See Note 7 – Goodwill and Other Intangible Assets.

Impairment of Long-Lived Assets

In compliance with current accounting standards regarding the accounting for the impairment or disposal of long-lived assets at the asset group level, the recoverability of the carrying values of long-lived assets, including finite-lived intangible assets, is assessed at a minimum annually, or whenever, in management's judgment, events or changes in circumstances indicate that the carrying value of such asset groups may not be recoverable based on estimated future cash flows. If this assessment indicates that the carrying values will not be recoverable, as determined based on undiscounted cash flows over the remaining useful lives, an impairment loss is recognized. The impairment loss equals the excess of the carrying value over the fair value of the asset group. The fair value of the asset group is based on prices of similar assets, if available, or discounted cash flows. Based on the Company's review, the carrying values of its asset groups are recoverable, and no impairment losses have been recorded for the periods presented.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Foreign Currency and Other Comprehensive Income

Gains and losses resulting from balance sheet translation of foreign operations where a foreign currency is the functional currency are included as a separate component of accumulated other comprehensive income within stockholders' equity representing substantially all of the balances within accumulated other comprehensive income. Remeasurements of intercompany loans denominated in a different currency than the functional currency of the entity that are of a long-term investment nature are recognized as other comprehensive income within stockholders’ equity. Gains and losses resulting from balance sheet remeasurements of assets and liabilities denominated in a different currency than the functional currency, other than intercompany loans that are of a long-term investment nature, are included in the consolidated statements of income as incurred.

Foreign Exchange Risk

A portion of revenues, earnings and net investments in foreign affiliates are exposed to changes in foreign exchange rates. We seek to manage our foreign exchange risk in part through operational means, including managing expected local currency revenues in relation to local currency costs and local currency assets in relation to local currency liabilities. In order to reduce our exposure to fluctuations in currency exchange rates, we may also enter into foreign exchange agreements with financial institutions. As of December 31, 2012, we had outstanding foreign currency forward purchase contracts with a notional amount of $12.4 million, hedging expected cash flows denominated in Euros. We have recorded other comprehensive loss of $1.0 million in 2012 as a result of this contract. As of December 31, 2011, we had no active hedge contracts outstanding. Foreign exchange losses associated with our operations have totaled $2.1 million in 2012, $1.4 million in 2011 and $1.1 million in 2010 and were included in “Other operating expense.”

Interest Capitalization

Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets' estimated useful lives. For the years ended December 31, 2012, 2011, and 2010, $3.5 million, $5.3 million and $0.2 million were capitalized, respectively.

Revenue and Cost Recognition

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Income Taxes

The Company follows the liability method of accounting for income taxes in accordance with current accounting standards regarding the accounting for income taxes. Under this method, deferred income taxes are recorded based upon the differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets or liabilities are recovered or settled.

In accounting for income taxes, we are required by the provisions of current accounting standards regarding the accounting for uncertainty in income taxes to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.

Receivables and Concentration of Credit Risk, Concentration of Suppliers

Based on the nature of its customer base, the Company does not believe that it has any significant concentrations of credit risk other than its concentration in the worldwide oil and gas and Australian mining industries. The Company evaluates the credit-worthiness of its significant, new and existing customers' financial condition and, generally, the Company does not require significant collateral from its customers.

The Company purchased 81% of its oilfield tubular goods from three suppliers in 2012. The loss of any significant supplier in the tubular services segment could materially adversely affect it.

Allowances for Doubtful Accounts

The Company maintains allowances for doubtful accounts for estimated losses resulting from the inability of the Company's customers to make required payments. If a trade receivable is deemed to be uncollectible, such receivable is charged-off against the allowance for doubtful accounts. The Company considers the following factors when determining if collection of revenue is reasonably assured: customer credit-worthiness, past transaction history with the customer, current economic industry trends, customer solvency and changes in customer payment terms. If the Company has no previous experience with the customer, the Company typically obtains reports from various credit organizations to ensure that the customer has a history of paying its creditors. The Company may also request financial information, including financial statements or other documents to ensure that the customer has the means of making payment. If these factors do not indicate collection is reasonably assured, the Company would require a prepayment or other arrangement to support revenue recognition and recording of a trade receivable. If the financial condition of the Company's customers were to deteriorate, adversely affecting their ability to make payments, additional allowances would be required.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Earnings per Share

Diluted EPS amounts include the effect of the Company's outstanding stock options and restricted stock shares under the treasury stock method. In addition, before their conversion in July 2012, shares of our 2 3/8% Contingent Convertible Senior Subordinated Notes (2 3/8% Notes) assumed to be issued upon conversion were included in the calculation of fully diluted shares outstanding and fully diluted earnings per share. The weighted average number of these shares totaled 1,793,244, 3,023,420 and 1,647,321 during the years ended December 31, 2012, December 31, 2011 and December 31, 2010, respectively.

Stock-Based Compensation

Current accounting standards regarding share-based payments require companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. In addition to service based awards, in 2012 the Company also issued performance based awards which may vest in an amount that will depend on the Company’s achievement of specified performance objectives. 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. During 2012, the Company also granted 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 equal annual installments 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. During the years ended December 31, 2012, 2011 and 2010, the Company recognized non-cash general and administrative expenses for stock options and restricted stock awards totaling $18.9 million, $14.6 million and $12.6 million, respectively. The Company accounts for assets held in a Rabbi Trust for certain participants under the Company's deferred compensation plan in accordance with current accounting standards. See Note 14.

Guarantees

The Company applies current accounting standards regarding guarantor's accounting and disclosure requirements for guarantees, including indirect indebtedness of others, for the Company's obligations under certain guarantees.

Some of our products in our offshore products and accommodations businesses are sold with a warranty, generally ranging from 12 to 18 months. Parts and labor are covered under the terms of the warranty agreement. Warranty provisions are estimated based upon historical experience by product, configuration and geographic region. Our total liability related to warranties was $1.8 million at December 31, 2012 and 2011.

During the ordinary course of business, the Company also provides standby letters of credit or other guarantee instruments to certain parties as required for certain transactions initiated by either the Company or its subsidiaries. As of December 31, 2012, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements (letters of credit) was approximately $49.4 million. The Company has not recorded any liability in connection with these guarantee arrangements. The Company does not believe, based on historical experience and information currently available, that it is likely that any amounts will be required to be paid under these guarantee arrangements.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States 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. Examples of a few such estimates include potential future adjustments as a result of contingent consideration arrangements pursuant to business combinations and other contractual agreements, revenue and income recognized on the percentage-of-completion method, estimates of the amount and timing of costs to be incurred for asset retirement obligations, the valuation allowance recorded on net deferred tax assets, warranty, reserves on inventory and allowance for doubtful accounts. Actual results could materially differ from those estimates.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Accounting for Contingencies

Subsequent Events

In accordance with authoritative guidance, the Company evaluates all events and transactions that occur after the balance sheet date, but before financial statements are issued for possible recognition or disclosure.

3. Details of Selected Balance Sheet Accounts

Additional information regarding selected balance sheet accounts at December 31, 2012 and 2011 is presented below (in thousands):

	2012			2011
Inventories, net:
Tubular goods	$	450,244		$	420,519
Other finished goods and purchased products		90,974			80,184
Work in process		64,267			76,353
Raw materials		107,356			86,672
Total inventories		712,841			663,728
Allowance for excess, damaged, remnant or obsolete inventory		(11,345	)		(10,030	)
	$	701,496		$	653,698

		2012			2011
Accounts receivable, net:
Trade	$	616,680		$	553,481
Unbilled revenue		218,229			180,273
Other		3,691			2,449
Total accounts receivable		838,600			736,203
Allowance for doubtful accounts		(5,815	)		(3,963	)
	$	832,785		$	732,240

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

	Estimated Useful Life (years)			2012			2011
Property, plant and equipment, net:
Land				$	58,888		$	48,989
Accommodations assets (1)	3	-	15		1,481,830			1,160,661
Buildings and leasehold improvements (1)	3	-	40		194,676			154,233
Machinery and equipment	2	-	29		402,342			355,798
Completion services equipment	4	-	10		264,225			199,084
Office furniture and equipment	1	-	10		54,337			48,081
Vehicles	2	-	10		123,474			100,554
Construction in progress					149,665			166,371
Total property, plant and equipment					2,729,437			2,233,771
Accumulated depreciation					(877,311	)		(676,683	)
				$	1,852,126		$	1,557,088

(1)

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

	2012		2011
Accrued liabilities:
Accrued compensation	$	69,206	$	61,394
Insurance liabilities		11,411		12,396
Accrued taxes, other than income taxes		7,204		5,889
Accrued interest		4,042		6,035
Accrued commissions		3,763		2,228
Other		12,280		8,806
	$	107,906	$	96,748

Depreciation expense was $216.5 million, $174.9 million and $121.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.

4. Recent Accounting Pronouncements

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 its Quarterly Report on Form 10-Q for the three month period ended March 31, 2012.

In September 2011, the FASB issued an accounting standards update which is intended to simplify goodwill impairment testing by giving an entity the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. An entity has the option to bypass such qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. The amendments were effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company adopted this standard for its annual goodwill impairment tests in 2011. In 2012, the Company chose the option to bypass the qualitative assessment and performed a quantitative assessment of goodwill impairment. The adoption of this standard did not have a material effect on our consolidated financial statements.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

5. Acquisitions and Supplemental Cash Flow Information

Components of cash used for acquisitions as reflected in the consolidated statements of cash flows for the years ended December 31, 2012, 2011 and 2010 are summarized as follows (in thousands):

	2012			2011		2010
Fair value of assets acquired including intangibles and goodwill	$	108,833		$	2,412	$	850,557
Liabilities assumed		(12,508	)		--		(119,386	)
Noncash consideration		(15,825	)		--		(7,966	)
Cash acquired		(51	)		--		(13,630	)
Cash used in acquisition of businesses	$	80,449		$	2,412	$	709,575

2012

On December 14, 2012, we acquired all of the equity of Tempress Technologies, Inc. (Tempress) for purchase price consideration of $48.3 million consisting of $32.5 million in cash and contingent consideration with a fair value of $15.8 million. The Company funded escrow accounts totaling $25.3 million related to the contingent consideration and seller transaction indemnities which are classified as “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for contingent consideration and escrowed amounts potentially due to the seller total $21.1 million at December 31, 2012 and are classified as “Other noncurrent liabilities” in our Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.

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 cash consideration was $48.0 million. The operations of Piper have been included in our offshore products segment since the acquisition date.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

2011

On November 1, 2011, we purchased an open camp accommodations facility located in Carrizo Springs, Texas for total consideration of $2.2 million. This facility provides accommodations support to customers working in the Eagle Ford Shale oil and gas basin in Texas. The operations of the Carrizo Springs facility have been included in our accommodations segment since the acquisition date.

2010

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

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

	Year Ended December 31, 2010
	(Unaudited)
Revenues	$	2,526,677
Net income attributable to Oil States International, Inc.		163,529
Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	3.26
Diluted	$	3.10

Included in the pro forma results above for the year ended December 31, 2010 are (1) depreciation of the increased fair value of property, plant and equipment acquired as part of The MAC, totaling $8.6 million, net of tax, or $0.16 per diluted share, (2) amortization expense for intangibles acquired as part of the purchase of The MAC, totaling $6.0 million, net of tax, or $0.11 per diluted share and, (3) interest expense of $10.8 million, net of tax, or $0.20 per diluted share. The year ended December 31, 2010 pro forma results also include The MAC acquisition costs of approximately $12.5 million ($4.6 million recorded on the Company’s books and $7.9 million recorded on The MAC’s books), net of tax, or $0.24 per diluted share.

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

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The acquisitions of Tempress, Piper, Carrizo Springs, Acute and Mountain West were not material to the Company’s Consolidated Financial Statements, and, therefore, the Company does not present pro forma information for these acquisitions.

The Company funded all of its acquisitions with cash on hand and/or draws under our senior secured credit facilities. See Note 8 – Long Term Debt for additional information on our senior secured credit facilities.

Supplemental Cash Flow Information

Cash paid during the years ended December 31, 2012, 2011 and 2010 for interest and income taxes was as follows (in thousands):

	2012		2011		2010
Interest (net of amounts capitalized)	$	62,863	$	44,332	$	7,303
Income taxes, net of refunds	$	141,760	$	79,190	$	75,303

Non-cash investing activities:
Assets acquired through lease incentives	$	--	$	1,897	$	--

Non-cash financing activities:
Value of common stock issued in payment of 2 3/8% Notes conversion	$	220,597	$	--	$	--
Borrowings and contingent consideration for business and asset acquisition and related intangibles	$	15,825	$	--	$	7,966

6. Earnings Per Share (EPS)

	2012		2011		2010
	(in thousands, except per share data)
Basic earnings per share:
Net income attributable to Oil States International, Inc.	$	448,609	$	322,453	$	168,018

Weighted average number of shares outstanding		52,959		51,163		50,238

Basic earnings per share	$	8.47	$	6.30	$	3.34

Diluted earnings per share:
Net income attributable to Oil States International, Inc.	$	448,609	$	322,453	$	168,018

Weighted average number of shares outstanding (basic)		52,959		51,163		50,238

Effect of dilutive securities:
Options on common stock		488		644		630
2 3/8% Convertible Senior Subordinated Notes		1,793		3,023		1,647
Restricted stock awards and other		144		177		185

Total shares and dilutive securities		55,384		55,007		52,700

Diluted earnings per share	$	8.10	$	5.86	$	3.19

Our calculations of diluted earnings per share for the years ended December 31, 2012, 2011 and 2010 exclude 399,134 shares, 179,804 shares and 364,345 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect.

See Note 8 – Long Term Debt for a discussion of the conversion of our 2 3/8% Notes.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

7. Goodwill and Other Intangible Assets

The Company does not amortize goodwill but tests for impairment using a fair value approach, at the "reporting unit" level. A reporting unit is the operating segment, or a business one level below that operating segment (the "component" level) if discrete financial information is prepared and regularly reviewed by management at the component level. The Company had three reporting units with goodwill as of December 31, 2012. Goodwill is allocated to each of the reporting units based on actual acquisitions made by the Company and its subsidiaries. The Company recognizes an impairment loss for any amount by which the carrying amount of a reporting unit's goodwill exceeds the reporting unit's IFV of goodwill. If our initial qualitative assessment of potential goodwill impairment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, the Company uses, as appropriate in the current circumstance, comparative market multiples, discounted cash flow calculations and acquisition comparables to establish the reporting unit's fair value (a Level 3 fair value measurement).

The Company amortizes the cost of other intangibles over their estimated useful lives unless such lives are deemed indefinite. Amortizable intangible assets are reviewed for impairment if there are indicators of impairment based on undiscounted cash flows and, if impaired, written down to fair value based on either discounted cash flows or appraised values. Intangible assets with indefinite lives are tested for impairment annually, and written down to fair value as required. As of December 31, 2012, no provision for impairment of other intangible assets was required.

Changes in the carrying amount of goodwill for the years ended December 31, 2012 and 2011 are as follows (in thousands):

	Well Site Services
	Completion 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 and purchase price adjustments		31,254			--			31,254			--			17,757			--			49,011
Foreign currency translation and other changes		316			--			316			3,809			232			--			4,357
		106,753			--			106,753			295,132			118,933			--			520,818
Balance as of December 31, 2012
Goodwill		201,281			22,767			224,048			295,132			118,933			62,863			700,976
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		--			--			(62,863	)		(180,158	)
	$	106,753		$	--		$	106,753		$	295,132		$	118,933		$	--		$	520,818

The following table presents the total amount of intangibles assigned and the total accumulated amortization for major intangible asset classes as of December 31, 2012 and 2011 (in thousands):

	As of December 31,
	2012				2011
Other Intangible Assets	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships	$	88,616	$	18,206	$	77,878	$	10,789
Contracts/Agreements		52,071		11,250		51,373		6,009
Patents		10,801		3,377		7,199		2,811
Technology		10,304		--		--		--
Noncompete agreements		7,433		4,214		5,164		4,310
Trademarks and other		3,990		83		25		--
Total amortizable intangible assets	$	173,215	$	37,130	$	141,639	$	23,919
Indefinite-lived intangible assets not subject to amortization:
Brand names		9,976		--		9,840		--
Licenses		42		--		42		--
Total indefinite-lived intangible assets		10,018		--		9,882		--
Total other intangible assets	$	183,233	$	37,130	$	151,521	$	23,919

The weighted average remaining amortization period for all intangible assets, other than goodwill and indefinite- lived intangibles, was 8.6 years as of December 31, 2012 and December 31, 2011. Total amortization expense is expected to be $15.5 million in each of 2013 and 2014, $15.4 million in 2015, $15.3 million in 2016 and $15.0 million in 2017. Amortization expense was $13.6 million, $13.3 million and $2.6 million in the years ended December 31, 2012, 2011 and 2010, respectively.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

8. Long-term Debt

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

	2012		2011
US revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million; secured by substantially all of our U.S. assets; commitment fee on unused portion was 0.375% per annum in 2012 and ranged from 0.375% to 0.500% in 2011; variable interest rate payable monthly based on prime or LIBOR plus applicable percentage; weighted average rate was 2.6% for 2012 and 2.8% for 2011	$	--	$	68,065

US term loan, which matures December 10, 2015, original principal of $200 million; 2.5% of aggregate principal repayable per quarter in 2012 and thereafter; secured by substantially all of our U.S. assets; variable interest rate payable monthly based on prime or LIBOR plus applicable percentage; weighted average rate was 2.4% for 2012 and 2.6% for 2011		170,000		190,000

Canadian revolving credit facility, which matures on December 10, 2015, with available commitments up to $250 million; secured by substantially all of our U.S. and Canadian assets; commitment fee on unused portion was 0.375% per annum in 2012 and ranged from 0.375% per annum to 0.500% in 2011; variable interest rate payable monthly based on the Canadian prime rate or Bankers Acceptance discount rate plus applicable percentage; weighted average rate was 4.3% for 2012 and 3.9% for 2011		--		--

Canadian term loan, which matures December 10, 2015, original principal of $100 million; 2.5% of aggregate principal repayable per quarter in 2012 and thereafter; secured by substantially all of our U.S. and Canadian assets; variable interest rate payable monthly based on prime or LIBOR plus applicable percentage; weighted average rate was 3.4% for 2012 and 3.6% for 2011		85,786		93,795

Australian revolving credit facility, which was replaced September 18, 2012, with available commitments up to AUD$150 million; secured by substantially all of our Australian assets; commitment fee on unused portion was 1.050% per annum in 2012 and 2011; variable interest rate payable monthly based on the Australian prime rate plus applicable percentage; weighted average rate was 6.2% for 2012 and 6.9% for 2011		--		43,050

Australian revolving credit facility, which matures December 10, 2015, with available commitments up to AUD$300 million; secured by substantially all of our Australian assets; commitment fee on unused portion was 0.375% per annum in 2012; variable interest rate payable monthly based on the Australian prime rate plus applicable percentage; weighted average rate was 5.4% for 2012		47,803		--

6 1/2% senior unsecured notes - due June 2019		600,000		600,000

5 1/8% senior unsecured notes - due January 2023		400,000		--

2 3/8% contingent convertible senior subordinated notes, net		--		170,884

Subordinated unsecured notes payable to sellers of businesses, fixed interest rate of 6%, matured in December 2012		--		4,000

Capital lease obligations and other debt		6,696		7,146
Total debt		1,310,285		1,176,940
Less: Current portion		30,480		34,435
Total long-term debt and capitalized leases	$	1,279,805	$	1,142,505

Scheduled maturities of combined long-term debt as of December 31, 2012, are as follows (in thousands):

2013	$	30,480
2014		30,438
2015		243,755
2016		308
2017		304
Thereafter		1,005,000
	$	1,310,285

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The Company's capital leases consist primarily of plant facilities and equipment. The value of capitalized leases and the related accumulated depreciation totaled $1.4 million and $1.0 million, respectively, at December 31, 2012. The value of capitalized leases and the related accumulated depreciation totaled $2.1 million and $1.4 million, respectively, at December 31, 2011. In 2011, the Company’s purchased an office building previously held under a capital lease.

5 1/8% Senior Unsecured Notes

On December 21, 2012, the Company sold $400 million aggregate principal amount of 5 1/8% Senior Notes due 2023 (5 1/8% Notes) through a private placement to qualified institutional buyers. The 5 1/8% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 5 1/8% per annum and mature on January 1, 2023. At any time prior to January 15, 2016, the Company may redeem up to 35% of the 5 1/8% Notes at a redemption price of 105.125% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to January 15, 2018, the Company may redeem some or all of the 5 1/8% 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 January 15, 2018, the Company may redeem some or all of the 5 1/8% 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 January 15,	% of Principal Amount
2018	102.563	%
2019	101.708	%
2020	100.854	%
2021	100.000	%

The Company utilized approximately $334 million of the net proceeds of the 5 1/8% Notes to repay borrowings under its U.S. revolving credit facility. The remaining net proceeds of approximately $61 million were utilized for general corporate purposes.

On December 21, 2012, in connection with the issuance of the 5 1/8% Notes, the Company entered into an Indenture (the 5 1/8% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The 5 1/8% Notes 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 5 1/8% 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 5 1/8% Notes 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 December 31, 2012, the Company was in compliance with all covenants of the 5 1/8% Notes Indenture.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

6 1/2% Senior Unsecured Notes

On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% Senior Notes due 2019 (6 1/2% Notes) through a private placement to qualified institutional buyers. The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.500% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:

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

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

2 3/8% Contingent Convertible Senior Notes

On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025 (the 2 3/8% Notes), totaling $175 million 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 $175 million 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.

The carrying amount of our 2 3/8% Notes as of December 31, 2011 in our consolidated balance sheet 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	$	170,884

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

	Year ended December 31,
	2012		2011		2010

Interest expense	$	6,185	$	11,942	$	11,405

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Credit Facilities

On December 10, 2010, we replaced our existing $500 million bank credit facility with $1.05 billion in senior credit facilities governed by the Amended and Restated Credit Agreement. The new credit facilities totaled $1.05 billion of available commitments consisting of revolving borrowings, up to $750 million, and term borrowings, of $300 million. The Company borrowed all of the term commitment in connection with the acquisition of The MAC. Under these senior secured revolving credit facilities with a group of banks, up to $350 million is available in the form of loans denominated in Canadian dollars and may be made to the Company's principal Canadian operating subsidiaries. The facilities mature on 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. Amounts borrowed under these facilities bear interest, at the Company's election, at either:

•

a variable rate equal to LIBOR (or, in the case of Canadian dollar denominated loans, the Bankers' Acceptance discount rate) plus a margin ranging from 2.0% to 3.0%; or

•

an alternate base rate equal to the higher of the bank's prime rate and the federal funds effective rate (or, in the case of Canadian dollar denominated loans, the Canadian Prime Rate).

Commitment fees ranging from 0.375% to 0.50% per year are paid on the undrawn portion of the facilities, depending upon our leverage ratio.

The credit facilities are guaranteed by all of the Company's active domestic subsidiaries and, in some cases, the Company's Canadian and other foreign subsidiaries. The credit facilities are secured by a first priority lien on all the Company's inventory, accounts receivable and other material tangible and intangible assets, as well as those of the Company's active subsidiaries. However, no more than 65% of the voting stock of any foreign subsidiary is required to be pledged if the pledge of any greater percentage would result in adverse tax consequences.

Under the Company's credit facilities, the occurrence of specified change of control events involving our company would constitute an event of default that would permit the banks to, among other things, accelerate the maturity of the facilities and cause them to become immediately due and payable in full.

As of December 31, 2012, we had $255.8 million outstanding under these facilities and an additional $41.1 million of outstanding letters of credit, leaving $708.9 million available to be drawn under the facilities.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO 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. As of December 31, 2012, we were in compliance with our Australian debt covenants. The MAC Group Facility Agreement replaced The MAC’s previous AUD$150 million revolving loan facility. As of December 31, 2012, we had AUD$46 million outstanding under the Australian credit facility leaving AUD$254 million available to be drawn under this facility.

Interest expense on the consolidated statements of income is net of capitalized interest of $3.5 million, $5.3 million and $0.2 million, respectively, for the years ended December 31, 2012, 2011 and 2010.

9. 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 product revenues 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 December 31, 2012, the total notional amount of the derivative contracts was $12.4 million (€10.0 million). As of December 31, 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 December 31, 2012, the Company’s foreign currency forward contracts had remaining maturities ranging from less than one month to twenty-one months.

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

Foreign Currency Contracts	December 31, 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	$	937
Derivatives not designated as hedging instruments
Other current liabilities		--
Total liabilities	$	937

The amount of the gains and losses related to the Company’s derivative contracts designated as hedging instruments for the year ended December 31, 2012 were (in thousands):

	Pretax Gain (Loss) Recognized in Other Comprehensive Income on Effective Portion of Derivative
	Year ended December 31, 2012
Derivatives in Cash Flow Hedging Relationships: Foreign currency forward contracts	$	(1,032	)

		Pretax Gain (Loss) Recognized in Income on Effective Portion of Derivative as a Result of Reclassification from Accumulated Other Comprehensive Income
	Location	Year ended December 31, 2012
Derivatives in Cash Flow Hedging Relationships: Foreign currency forward contracts	Product revenues	$	(11	)

		Gain (Loss) on Ineffective Portion of Derivative Recognized in Income
	Location	Year ended December 31, 2012
Derivatives in Cash Flow Hedging Relationships: Foreign currency forward contracts	Product revenues	$	(11	)

At December 31, 2012, there was $1.0 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 twenty-one months as a result of underlying hedged transactions also being recorded in net sales.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

For the year ended December 31, 2012, the gains and losses from our derivative contracts not designated as hedging instruments recognized in net sales were zero.

10. 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 December 31, 2012, the Company had approximately 54.7 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 Board of Directors deems appropriate. As of December 31, 2012, a total of $15.2 million of our stock (225,796 shares) had been repurchased under this program, leaving a total authorization of up to approximately $184.8 million remaining available under the repurchase program.

11. Retirement Plans

The Company sponsors defined contribution plans. Participation in these plans is available to substantially all employees. The Company recognized expense of $13.7 million, $11.1 million and $7.7 million, respectively, related to matching contributions under its various defined contribution plans during the years ended December 31, 2012, 2011 and 2010, respectively.

12. Income Taxes

Consolidated pre-tax income (loss) for the years ended December 31, 2012, 2011 and 2010 consisted of the following (in thousands):

	2012		2011		2010
US operations	$	250,870	$	193,091	$	68,921
Foreign operations		376,025		261,978		171,707
Total	$	626,895	$	455,069	$	240,628

The components of the income tax provision for the years ended December 31, 2012, 2011 and 2010 consisted of the following (in thousands):

	2012			2011		2010
Current:
Federal	$	79,958		$	48,253	$	25,237
State		5,423			1,769		1,122
Foreign		74,295			48,921		44,249
		159,676			98,943		70,608
Deferred:
Federal		7,483			15,862		(1,572	)
State		(1,082	)		2,206		(58	)
Foreign		10,970			14,636		3,045
		17,371			32,704		1,415
Total Provision	$	177,047		$	131,647	$	72,023

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The provision for taxes differs from an amount computed at U.S. statutory rates as follows for the years ended December 31, 2012, 2011 and 2010 consisted (in thousands):

	2012			2011			2010
Federal tax expense at statutory rates	$	219,413		$	159,274		$	84,220
Effect of foreign income tax, net		(46,715	)		(33,818	)		(12,796	)
Nondeductible acquisition costs		156			183			2,315
Other nondeductible expenses		2,603			3,194			1,454
State tax expense, net of federal benefits		4,341			3,975			1,017
Domestic manufacturing deduction		(3,300	)		(1,839	)		(978	)
Uncertain tax positions adjustments, net		(3,209	)		(1,585	)		(1,036	)
Other, net		3,758			2,263			(2,173	)
Net income tax provision	$	177,047		$	131,647		$	72,023

The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows (in thousands):

	2012			2011
Deferred tax assets:
Allowance for doubtful accounts	$	1,991		$	1,232
Allowance for inventory reserves		7,486			6,466
Employee benefits		17,535			14,655
Deductible goodwill and other intangibles		8,185			11,586
Other reserves		5,332			5,432
Depreciation		1,244			1,045
Foreign tax credit carryover		11,326			8,538
Other		3,388			3,373
Gross deferred tax asset		56,487			52,327
Less: valuation allowance		--			--
Net deferred tax asset		56,487			52,327
Deferred tax liabilities:
Depreciation		(158,739	)		(130,793	)
Deferred revenue		(1,777	)		(1,705	)
Intangibles		(10,692	)		(5,082	)
Accrued liabilities		(4,117	)		(4,330	)
Lower of cost or market		(3,373	)		(2,141	)
Convertible notes		--			(1,514	)
Other		(4,171	)		(3,674	)
Deferred tax liability		(182,869	)		(149,239	)
Net deferred tax liability	$	(126,382	)	$	(96,912	)

Reclassifications of the Company's deferred tax balance based on net current items and net non-current items as of December 31, 2012 and 2011 are as follows (in thousands):

	2012			2011
Current deferred tax liability	$	(3,951	)	$	(5,298	)
Long-term deferred tax liability		(122,431	)		(91,614	)
Net deferred tax liability	$	(126,382	)	$	(96,912	)

Our primary deferred tax assets at December 31, 2012, were related to employee benefit costs for our Equity Participation Plan, deductible goodwill and other intangibles, allowance for inventory obsolescence and foreign tax credit carryforwards. The foreign tax credits will expire in varying amounts after 2019.

Appropriate U.S. and foreign income taxes have been provided for earnings of foreign subsidiary companies that are expected to be remitted in the near future. The cumulative amount of undistributed earnings of foreign subsidiaries that the Company intends to indefinitely reinvest, and upon which foreign taxes have been accrued or paid but no deferred US income taxes have been provided is $1.1 billion at December 31, 2012, the majority of which has been generated in Canada and Australia. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to U.S. income taxes (subject to adjustment for foreign tax credits) and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The American Jobs Creation Act of 2004 that was signed into law in October 2004 introduced a requirement for companies to disclose any penalties imposed on them or any of their consolidated subsidiaries by the IRS for failing to satisfy tax disclosure requirements relating to "reportable transactions." During the year ended December 31, 2012, no penalties were imposed on the Company or its consolidated subsidiaries for failure to disclose reportable transactions to the IRS.

The Company files tax returns in the jurisdictions in which they are required. All of these returns are subject to examination or audit and possible adjustment as a result of assessments by taxing authorities. The Company believes that it has recorded sufficient tax liabilities and does not expect the resolution of any examination or audit of its tax returns would have a material adverse effect on its operating results, financial condition or liquidity.

Tax years subsequent to 2009 remain open to U.S. federal tax audit and, because of Net Operating Losses (NOL's) utilized by the Company, years from 1994 to 2002 remain subject to federal tax audit with respect to NOL's available for tax carryforward. Our Canadian subsidiaries' federal tax returns subsequent to 2008 are subject to audit by the Canada Revenue Agency. Our Australian subsidiary’s federal tax returns subsequent to 2007 are subject to audit by the Australian Taxation Office.

We account for uncertain tax positions using a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

The total amount of unrecognized tax benefits as of December 31, 2012 was $0.7 million. The unrecognized tax benefits, if recognized, would affect the effective tax rate. The Company accrues interest and penalties related to unrecognized tax benefits as a component of the Company's provision for income taxes. As of December 31, 2012 and 2011, the Company had accrued $0.2 million and $2.3 million, respectively, of interest expense and penalties.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	2012			2011			2010
Balance as of January 1st	$	1,847		$	3,044		$	4,031
Additions for tax positions of prior years		--			--			128
Reductions for tax positions of prior years		(1,119	)		(798	)		--
Lapse of the applicable statute of limitations		--			(399	)		(1,115	)
Balance as of December 31st	$	728		$	1,847		$	3,044

It is reasonably possible that the amount of unrecognized tax benefits will change during the next twelve months due to the closing of the statute of limitations and that change, if it were to occur, could have a favorable or unfavorable impact on our results of operation.

13. Commitments and Contingencies

The Company leases a portion of its equipment, office space, computer equipment, automobiles and trucks under leases which expire at various dates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Minimum future operating lease obligations in effect at December 31, 2012, were as follows (in thousands):

	Operating Leases
2013	$	15,069
2014		13,077
2015		10,454
2016		8,002
2017		6,669
Thereafter		24,092
Total	$	77,363

Rental expense under operating leases was $17.0 million, $14.5 million and $12.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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. Stock-Based Compensation

Current accounting standards require companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period.

The fair value of each option grant is estimated on the date of grant using a Black-Scholes option pricing model that uses the assumptions noted in the following table. The risk-free interest rate is based on the U.S. Treasury yield curve in effect for the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future. The expected market price volatility of our common stock is based on an estimate made by us that considers the historical and implied volatility of our common stock as well as a peer group of companies over a time period equal to the expected term of the option. The expected life of the options awarded in 2012, 2011 and 2010 was based on a formula considering the vesting period, term of the options awarded and past experience.

	2012		2011		2010
Risk-free weighted interest rate	0.6	%	1.7	%	2.1	%
Expected life (in years)	4.1		4.1		4.3
Expected volatility	57	%	55	%	55	%

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The following table summarizes stock option activity for each of the three years ended December 31, 2012, 2011 and 2010:

	Options			Weighted Average Exercise Price		Weighted Average Contractual Life (Years)	Aggregate Intrinsic Value (Thousands)
Outstanding Options at December 31, 2009		2,481,951		$	25.55	3.6	$	34,618
Granted		417,250			37.67
Exercised		(866,436	)		26.96
Forfeited		(65,375	)		27.75
Outstanding Options at December 31, 2010		1,967,390			27.42	3.5		72,138
Granted		186,200			75.34
Exercised		(517,202	)		27.37
Forfeited		(53,125	)		41.85
Outstanding Options at December 31, 2011		1,583,263			32.59	3.4		69,311
Granted		155,250			84.52
Exercised		(471,780	)		28.89
Forfeited		(17,486	)		51.65
Outstanding Options at December 31, 2012		1,249,247			40.18	3.7		41,730

The weighted average fair values of options granted during 2012, 2011 and 2010 were $37.38, $33.23, and $17.13 per share, respectively. All options awarded in 2012 had a term of ten years and were granted with exercise prices at the grant date closing market price. The total intrinsic value of options exercised during 2012, 2011 and 2010 were $38.3 million, $24.9 million and $19.9 million, respectively. Cash received by the Company from option exercises during 2012, 2011 and 2010 totaled $13.6 million, $14.2 million and $23.4 million, respectively. The tax benefit realized for the tax deduction from stock options exercised during 2012, 2011 and 2010 totaled $6.9 million, $7.8 million and $6.1 million, respectively.

The following table summarizes information for stock options outstanding at December 31, 2012:

			Options Outstanding					Options Exercisable
Range of Exercise Prices			Number Outstanding as of 12/31/2012		Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable as of 12/31/2012		Weighted Average Exercise Price
$11.49	-	$ 16.65		414,712	1.87	$	15.97		270,475	$	15.60
$24.52	-	$ 37.67		517,588	2.30	$	35.79		342,090	$	34.83
$58.05	-	$ 84.63		316,947	8.33	$	79.02		42,503	$	69.87
$11.49	-	$ 84.63		1,249,247	3.69	$	40.18		655,068	$	29.17

At December 31, 2012, a total of 1,018,285 shares were available for future grant under the Equity Participation Plan.

During 2012, we granted restricted stock awards totaling 357,544 shares valued at a total of $29.2 million. Of the restricted stock awards granted in 2012, 218,000 awards vest in four equal annual installments beginning in February 2013, 55,250 awards vest 40% in October 2013 and 60% in October 2014, 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. During 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 217,415 and 233,493 shares of restricted stock were awarded in 2011 and 2010, respectively, with aggregate values of $16.3 million and $9.1 million, respectively.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Stock based compensation pre-tax expense recognized in the years ended December 31, 2012, 2011 and 2010 totaled $18.9 million, $14.6 million and $12.6 million, or $0.25, $0.20 and $0.18 per diluted share after tax, respectively. At December 31, 2012, $39.4 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.

Deferred Compensation Plan

The Company maintains a deferred compensation plan (Deferred Compensation Plan). This plan is available to directors and certain officers and managers of the Company. The plan allows participants to defer the receipt of all or a portion of their directors’ fees and/or salary and annual bonuses. Employee contributions to the Deferred Compensation Plan are matched by the Company at the same percentage as if the employee was a participant in the Company's 401(k) Retirement Plan and was not subject to the IRS limitations on match-eligible compensation. The Deferred Compensation Plan also permits the Company to make discretionary contributions to any employee's account, although none have been made to date. Director's contributions are not matched by the Company. Since inception of the plan, this discretionary contribution provision has been limited to a matching of the participants' contributions on a basis equivalent to matching permitted under the Company's 401(k) Retirement Savings Plan. The vesting of contributions to the participants’ accounts is also equivalent to the vesting requirements of the Company's 401(k) Retirement Savings Plan. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a Rabbi Trust (Trust) and, therefore, are available to satisfy the claims of the Company's creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest the assets in their individual accounts, including any discretionary contributions by the Company, in ten pre-approved mutual funds held by the Trust which cover a variety of securities and mutual funds. In addition, participants currently have the right to request that the Plan Administrator to re-allocate the portfolio of investments (i.e. cash or mutual funds) in the participants' individual accounts within the Trust. Company contributions are in the form of cash. Distributions from the plan are generally made upon the participants' termination as a director and/or employee, as applicable, of the Company. Participants receive payments from the Deferred Compensation Plan in cash. At December 31, 2012, Trust assets totaled $11.6 million, the majority of which is classified as “Other noncurrent assets” in the Company’s Consolidated Balance Sheet. The fair value of the investments was based on quoted market prices in active markets (a Level 1 fair value measurement). Amounts payable to the plan participants at December 31, 2012, including the fair value of the shares of the Company's common stock that are reflected as treasury stock, was $12.7 million and is classified as "Other noncurrent liabilities" in the consolidated balance sheet. The Company accounts for the Deferred Compensation Plan in accordance with current accounting standards regarding the accounting for deferred compensation arrangements where amounts earned are held in a Rabbi Trust and invested.

In accordance with current accounting standards, all fair value fluctuations of the Trust assets have been reflected in the consolidated statements of income. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as compensation adjustments in the respective statements of income. Increases or decreases in the fair value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are also included as compensation adjustments in the consolidated statements of income. In response to the changes in total fair value of the Company's common stock held by the Trust, the Company recorded net compensation expense adjustments to the liability of ($0.1) million in 2012, $0.2 million in 2011 and $0.4 million in 2010.

15. Segment and Related Information

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Financial information by industry segment for each of the three years ended December 31, 2012, 2011 and 2010, is summarized in the following table in thousands. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings (loss) of unconsolidated affiliates			Capital expenditures		Total assets
2012
Well site services -
Completion services	$	522,618	$	50,611	$	124,620		$	--		$	86,567	$	574,203
Drilling services		191,034		22,411		32,160			--			32,136		157,658
Total well site services		713,652		73,022		156,780			--			118,703		731,861
Accommodations		1,113,470		139,047		364,629			(2	)		314,047		2,123,412
Offshore products		804,067		14,720		134,051			(417	)		48,792		804,980
Tubular services		1,781,899		2,306		75,042			662			5,027		714,199
Corporate and eliminations		--		1,003		(46,722	)		--			1,368		65,510
Total	$	4,413,088	$	230,098	$	683,780		$	243		$	487,937	$	4,439,962

2011
Well site services -
Completion services	$	487,941	$	41,612	$	120,849		$	--		$	81,024	$	462,189
Drilling services		165,903		19,818		20,394			--			29,477		128,721
Total well site services		653,844		61,430		141,243			--			110,501		590,910
Accommodations		864,701		110,705		248,977			1			348,504		1,789,868
Offshore products		585,818		13,454		94,666			(847	)		19,987		622,466
Tubular services		1,374,817		1,758		64,422			683			8,129		645,422
Corporate and eliminations		--		800		(41,785	)		--			361		54,975
Total	$	3,479,180	$	188,147	$	507,523		$	(163	)	$	487,482	$	3,703,641

2010
Well site services -
Completion services	$	342,953	$	40,859	$	47,326		$	--		$	42,884	$	383,778
Drilling services		133,214		24,149		576			--			10,300		108,163
Total well site services		476,167		65,008		47,902			--			53,184		491,941
Accommodations		537,690		45,694		151,417			(25	)		107,347		1,491,682
Offshore products		428,963		11,496		60,664			--			13,299		520,944
Tubular services		969,164		1,301		35,941			264			7,889		458,808
Corporate and eliminations		--		703		(40,342	)		--			488		52,624
Total	$	2,411,984	$	124,202	$	255,582		$	239		$	182,207	$	3,015,999

Financial information by geographic segment for each of the three years ended December 31, 2012, 2011 and 2010, is summarized below in thousands. Revenues in the United States include export sales. Revenues are attributable to countries based on the location of the entity selling the products or performing the services. Total assets are attributable to countries based on the physical location of the entity and its operating assets and do not include intercompany balances.

	United States		Canada		Australia		United Kingdom		Other Non U.S.		Total
2012
Revenues from unaffiliated customers	$	3,024,837	$	734,197	$	276,433	$	205,618	$	172,003	$	4,413,088
Long-lived assets		936,482		655,714		932,246		23,626		59,004		2,607,072
2011
Revenues from unaffiliated customers	$	2,424,669	$	590,242	$	197,095	$	130,407	$	136,767	$	3,479,180
Long-lived assets		714,541		608,054		827,271		18,357		39,996		2,208,219
2010
Revenues from unaffiliated customers	$	1,708,709	$	512,288	$	-	$	77,180	$	113,807	$	2,411,984
Long-lived assets		639,120		502,322		724,522		17,275		28,088		1,911,327

No customers accounted for more than 10% of the Company's revenues in any of the years ended December 31, 2012, 2011 and 2010. Equity in net income of unconsolidated affiliates is not included in operating income.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

16. Valuation Allowances

Activity in the valuation accounts was as follows (in thousands):

	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (net of recoveries)			Translation and Other, Net			Balance at End of Period
Year Ended December 31, 2012:
Allowance for doubtful accounts receivable	$	3,963	$	2,565	$	(731	)	$	18		$	5,815
Allowance for excess, damaged, remnant or obsolete inventory		10,030		5,792		(4,551	)		74			11,345

Year Ended December 31, 2011:
Allowance for doubtful accounts receivable	$	4,100	$	2,239	$	(2,310	)	$	(66	)	$	3,963
Allowance for excess, damaged, remnant or obsolete inventory		8,454		2,366		(783	)		(7	)		10,030

Year Ended December 31, 2010:
Allowance for doubtful accounts receivable	$	4,946	$	869	$	(1,915	)	$	200		$	4,100
Allowance for excess, damaged, remnant or obsolete inventory		8,279		1,288		(510	)		(603	)		8,454

17. Quarterly Financial Information (Unaudited)

The following table summarizes quarterly financial information for 2012 and 2011 (in thousands, except per share amounts):

	First Quarter(2)		Second Quarter(3)		Third Quarter(4)		Fourth Quarter
2012
Revenues	$	1,098,992	$	1,091,088	$	1,080,673	$	1,142,336
Gross profit(1)		303,195		271,924		266,639		278,361
Net income		135,065		111,234		103,792		98,519
Basic earnings per share		2.63		2.15		1.92		1.80
Diluted earnings per share		2.43		2.01		1.87		1.78

2011
Revenues	$	760,441	$	820,317	$	902,621	$	995,801
Gross profit(1)		186,043		203,539		236,766		253,565
Net income		62,077		74,243		91,851		94,282
Basic earnings per share		1.22		1.45		1.79		1.84
Diluted earnings per share		1.13		1.34		1.67		1.72

(1)

Represents "revenues" less "product costs" and "service and other costs" included in the Company's consolidated statements of income.

(2)

In the first quarter of 2012, we recorded 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.

(3)

In the second quarter of 2012, we recorded 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.

(4)

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. 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 full year 2012 results and to our earnings’ trends.

Amounts are calculated independently for each of the quarters presented. Therefore, the sum of the quarterly amounts may not equal the total calculated for the year.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

18. Condensed Consolidating Financial Information

Certain wholly-owned subsidiaries, as detailed below (the Guarantor Subsidiaries), have guaranteed all of the 6 1/2% Notes issued by Oil States International, Inc. in 2011 and all of the 5 1/8% Notes issued in 2012. These guarantees are full and unconditional, subject to the following release provisions:

in connection with any sale, exchange or transfer (by merger, consolidation or otherwise) of the capital stock of that guarantor after which that guarantor is no longer a restricted subsidiary;

upon proper designation of a guarantor by the Company as an unrestricted subsidiary;

upon the release or discharge of all outstanding guarantees by a guarantor of indebtedness of the Company and its restricted subsidiaries under any credit facility;

upon legal or covenant defeasance or satisfaction and discharge of the indenture; or

upon the dissolution of a guarantor, provided no event of default has occurred under the indentures and is continuing.

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 consolidating financial information presents: condensed consolidating statements of income for each of the years ended December 31, 2012, 2011 and 2010, condensed consolidating balance sheets as December 31, 2012 and December 31, 2011 and the statements of cash flows for each of the years ended December 31, 2012, 2011 and 2010 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, Tempress Technologies, Inc. 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. As of January 1, 2012, Specialty Rental Tools & Supply, L.L.C., Stinger Wellhead Protection, Incorporated and Well Testing, Inc. were combined to form Oil States Energy Services L.L.C.

We have corrected the presentation of our condensed consolidating statements of income for the years ended December 31, 2011 and 2010, our condensed consolidating balance sheet as of December 31, 2011 and our statement of cash flows for years ended December 31, 2011 and 2010 to properly reflect the investment in and equity earnings of certain non-guarantor subsidiaries by certain guarantor subsidiaries in accordance with SEC Regulation S-X, which were previously only presented in the Parent/Guarantor column. We have also corrected other immaterial amounts previously disclosed to properly present (i) the activity and balances of a certain guarantor subsidiary in the Guarantor Subsidiaries column which was previously presented in the Parent/Guarantor column and (ii) the activity and balances of a certain non-guarantor subsidiary in the Non-Guarantors column which was previously presented in the Guarantor Subsidiaries column. The effect of these corrections increased net income for the Guarantor Subsidiaries and Non-Guarantor Subsidiaries by $158.6 million and $4.8 million, respectively, for year ended December 31, 2011 and increased the net income for the Guarantor Subsidiaries and Non-Guarantor Subsidiaries by $1.7 million and $1.0 million, respectively, for the year ended December 31, 2010. 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.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Year Ended December 31, 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	$	—	$	3,025,484	$	1,387,604	$	—	$	4,413,088
Intercompany revenues		—		27,567		16,846		(44,413)		—
Total revenues		—		3,053,051		1,404,450		(44,413)		4,413,088

OPERATING EXPENSES
Cost of sales and services		—		2,523,929		776,386		(7,346)		3,292,969
Intercompany cost of sales and services		—		20,148		15,326		(35,474)		—
Selling, general and administrative expenses		1,772		131,828		70,051		—		203,651
Depreciation and amortization expense		1,003		93,341		135,774		(20)		230,098
Other operating (income)/expense		(289)		347		2,533		(1)		2,590
Operating income (loss)		(2,486)		283,458		404,380		(1,572)		683,780

Interest expense, net of capitalized interest		(62,712)		(884)		(72,818)		67,492		(68,922)
Interest income		20,456		140		48,478		(67,491)		1,583
Equity in earnings (loss) of unconsolidated affiliates		479,800		289,414		(419)		(768,552)		243
Other income		—		9,902		309		—		10,211
Income before income taxes		435,058		582,030		379,930		(770,123)		626,895
Income tax provision		13,551		(100,845)		(89,753)		—		(177,047)
Net income		448,609		481,185		290,177		(770,123)		449,848

Other comprehensive income:
Foreign currency translation adjustment		33,450		25,285		25,157		(50,442)		33,450
Unrealized loss on forward contracts		—		(724)		—		—		(724)
Total other comprehensive income		33,450		24,561		25,157		(50,442)		32,726

Comprehensive income		482,059		505,746		315,334		(820,565)		482,574
Comprehensive income attributable to noncontrolling interest		—		—		(1,318)		62		(1,256)
Comprehensive income attributable to Oil States International, Inc.	$	482,059	$	505,746	$	314,016	$	(820,503)	$	481,318

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

	Year Ended December 31, 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	$	—	$	2,428,651	$	1,050,529	$	—	$	3,479,180
Intercompany revenues		—		19,857		966		(20,823)		—
Total revenues		—		2,448,508		1,051,495		(20,823)		3,479,180

OPERATING EXPENSES
Cost of sales and services		—		1,998,213		605,304		(4,250)		2,599,267
Intercompany cost of sales and services		—		15,462		771		(16,233)		—
Selling, general and administrative expenses		1,519		122,326		58,589		—		182,434
Depreciation and amortization expense		800		81,479		105,881		(13)		188,147
Other operating (income)/expense		742		134		931		2		1,809
Operating income (loss)		(3,061)		230,894		280,019		(329)		507,523

Interest expense, net of capitalized interest		(52,363)		(1,237)		(76,694)		72,788		(57,506)
Interest income		15,252		38		59,197		(72,787)		1,700
Equity in earnings (loss) of unconsolidated affiliates		357,135		198,704		(845)		(555,157)		(163)
Other income		—		3,409		106		—		3,515
Income before income taxes		316,963		431,808		261,783		(555,485)		455,069
Income tax provision		5,490		(74,251)		(62,886)		—		(131,647)
Net income		322,453		357,557		198,897		(555,485)		323,422

Other comprehensive income:
Foreign currency translation adjustment		(10,079)		7,049		(12,201)		5,152		(10,079)
Other comprehensive loss		—		(99)		—		—		(99)
Total other comprehensive income		(10,079)		6,950		(12,201)		5,152		(10,178)

Comprehensive income		312,374		364,507		186,696		(550,333)		313,244
Comprehensive income attributable to noncontrolling interest		—		—		(905)		(43)		(948)
Comprehensive income attributable to Oil States International, Inc.	$	312,374	$	364,507	$	185,791	$	(550,376)	$	312,296

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Income and Comprehensive Income

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

REVENUES
Operating revenues	$	—	$	1,698,363	$	713,621	$	—	$	2,411,984
Intercompany revenues		—		28,359		930		(29,289)		—
Total revenues		—		1,726,722		714,551		(29,289)		2,411,984

OPERATING EXPENSES
Cost of sales and services		—		1,433,931		447,885		(7,522)		1,874,294
Intercompany cost of sales and services		—		21,294		473		(21,767)		—
Selling, general and administrative expenses		1,142		113,355		36,368		—		150,865
Depreciation and amortization expense		703		74,151		49,355		(7)		124,202
Other operating (income)/expense		(102)		6,036		1,107		—		7,041
Operating income (loss)		(1,743)		77,955		179,363		7		255,582

Interest expense, net of capitalized interest		(14,906)		(680)		(4,746)		4,058		(16,274)
Interest income		471		57		4,282		(4,059)		751
Equity in earnings (loss) of unconsolidated affiliates		167,114		31,054		(25)		(197,904)		239
Other income		—		2,182		(1,852)		—		330
Income before income taxes		150,936		110,568		177,022		(197,898)		240,628
Income tax provision		17,082		(40,431)		(48,675)		1		(72,023)
Net income		168,018		70,137		128,347		(197,897)		168,605

Other comprehensive income:
Foreign currency translation adjustment		40,274		30,112		30,126		(60,238)		40,274
Other comprehensive loss		—		160		—		—		160
Total other comprehensive income		40,274		30,272		30,126		(60,238)		40,434

Comprehensive income		208,292		100,409		158,473		(258,135)		209,039
Comprehensive income attributable to noncontrolling interest		—		—		(601)		(11)		(612)
Comprehensive income attributable to Oil States International, Inc.	$	208,292	$	100,409	$	157,872	$	(258,146)		208,427

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Balance Sheets

	December 31, 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	$	3,222	$	57,205	$	192,745	$	—	$	253,172
Accounts receivable, net		431		486,975		345,379		—		832,785
Inventories, net		—		583,002		118,494		—		701,496
Prepaid expenses and other current assets		4,592		20,770		13,277		—		38,639
Total current assets		8,245		1,147,952		669,895		—		1,826,092

Property, plant and equipment, net		1,922		578,029		1,274,106		(1,931)		1,852,126
Goodwill, net		—		221,610		299,208		—		520,818
Other intangible assets, net		—		58,269		87,834		—		146,103
Investments in unconsolidated affiliates		2,658,946		1,621,536		3,000		(4,273,768)		9,714
Long-term intercompany receivables (payables)		855,354		(495,655)		(359,697)		(2)		—
Other noncurrent assets		40,989		25,984		18,136		—		85,109
Total assets	$	3,565,456	$	3,157,725	$	1,992,482	$	(4,275,701)	$	4,439,962

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,847	$	180,849	$	97,237	$	—	$	279,933
Accrued liabilities		17,147		53,494		37,267		(2)		107,906
Income taxes		(95,930)		94,996		30,522		—		29,588
Current portion of long-term debt and capitalized leases		20,022		314		10,144		—		30,480
Deferred revenue		—		49,584		16,727		—		66,311
Other current liabilities		—		4,027		287		—		4,314
Total current liabilities		(56,914)		383,264		192,184		(2)		518,532

Long-term debt and capitalized leases		1,150,024		6,203		123,578		—		1,279,805
Deferred income taxes		(4,772)		80,481		53,526		—		129,235
Other noncurrent liabilities		12,713		26,906		7,420		(449)		46,590
Total liabilities		1,101,051		496,854		376,708		(451)		1,974,162

Stockholders’ equity		2,464,405		2,660,871		1,614,526		(4,275,397)		2,464,405
Non-controlling interest		—		—		1,248		147		1,395
Total stockholders’ equity		2,464,405		2,660,871		1,615,774		(4,275,250)		2,465,800
Total liabilities and stockholders’ equity	$	3,565,456	$	3,157,725	$	1,992,482	$	(4,275,701)	$	4,439,962

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO 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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 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:	$	(185,138)	$	397,711	$	437,316	$	(12,406)	$	637,483

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(1,367)		(202,336)		(286,017)		1,783		(487,937)
Acquisitions of businesses, net of cash acquired		—		(80,449)		—		—		(80,449)
Proceeds from dispositions of property, plant and equipment		—		8,887		5,766		—		14,653
Deposits held in escrow related to acquisitions of businesses		—		(20,000)		—		—		(20,000)
Payments for equity contributions		(66,512)		(10,006)		—		76,518		—
Other, net		1		272		(3,398)		(119)		(3,244)
Net cash provided by (used in) investing activities		(67,878)		(303,632)		(283,469)		78,182		(576,977)

CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		(68,065)		—		3,814		—		(64,251)
Payment of principal on 2 3/8% Notes conversion		(174,990)		—		—		—		(174,990)
5 1/8 % senior notes issued		400,000		—		—		—		400,000
Term loan borrowings (repayments)		(20,000)		—		(10,047)		—		(30,047)
Debt and capital lease repayments		(19)		(4,407)		(143)		—		(4,569)
Issuance of common stock from share-based payment arrangements		13,628		—		—		—		13,628
Purchase of treasury stock		(15,245)		—		—		—		(15,245)
Excess tax benefits from share-based payment arrangements		8,164		—		—		—		8,164
Payment of financing costs		(4,472)		—		(3,442)		—		(7,914)
Proceeds from (funding of) accounts and notes with affiliates, net		121,749		(100,560)		(18,580)		(2,609)		—
Proceeds from equity contributions		—		66,512		7,397		(73,909)		—
Payment of dividends		—		—		(10,741)		10,741		—
Tax withholdings related to net share settlements of restricted stock		(4,218)		—		—		—		(4,218)
Other, net		1		—		(2)		1		—
Net cash provided by (used in) financing activities		256,533		(38,455)		(31,744)		(65,776)		120,558

Effect of exchange rate changes on cash		—		138		542		—		680
Net change in cash and cash equivalents from continuing operations		3,517		55,762		122,465		—		181,744
Net cash used in discontinued operations operating activities		—		(293)		—		—		(293)
Cash and cash equivalents, beginning of period		(295)		1,736		70,280		—		71,721

Cash and cash equivalents, end of period	$	3,222	$	57,205	$	192,745	$	—	$	253,172

- 112 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 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:	$	(78,624)	$	107,412	$	210,114			(22,989)		$	215,913

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(361)		(138,923)		(348,308)			110			(487,482)
Acquisitions of businesses, net of cash acquired		—		(2,412)		—			—			(2,412)
Proceeds from dispositions of property, plant and equipment		—		2,339		3,610			—			5,949
Payments for equity contributions		—		(6,787)		—			6,787			—
Other, net		—		(202)		(4,808)			—			(5,010)
Net cash provided by (used in) investing activities		(361)		(145,985)		(349,506)			6,897			(488,955)

CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		(278,676)		—		(38,060)			—			(316,736)
6 1/2 % senior notes issued		600,000		—		—			—			600,000
Term loan borrowings (repayments)		(10,000)		—		(4,972)			—			(14,972)
Debt and capital lease repayments		(19)		(455)		(2,055)			—			(2,529)
Issuance of common stock from share-based payment arrangements		14,154		—		—			—			14,154
Purchase of treasury stock		(12,632)		—		—			—			(12,632)
Excess tax benefits from share-based payment arrangements		8,583		—		—			—			8,583
Payment of financing costs		(13,205)		—		(259)			—			(13,464)
Proceeds from (funding of) accounts and notes with affiliates, net		(226,576)		41,487		185,089			—			—
Proceeds from equity contributions		—		—		6,787			(6,787	)		—
Payment of dividends		—		—		(22,879	)		22,879			—
Tax withholdings related to net share settlements of restricted stock		(2,702)		—		—			—			(2,702)
Other, net		(10)		(1,805)		1			—			(1,814)
Net cash provided by (used in) financing activities		78,917		39,227		123,652			16,092			257,888

Effect of exchange rate changes on cash		—		9		(9,341)			—			(9,332)
Net change in cash and cash equivalents from continuing operations		(68)		663		(25,081)			—			(24,486)
Net cash used in discontinued operations operating activities		—		(143)		—			—			(143)
Cash and cash equivalents, beginning of period		(227)		1,216		95,361			—			96,350

Cash and cash equivalents, end of period	$	(295)	$	1,736	$	70,280			—		$	71,721

- 113 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Condensed Consolidating Statements of Cash Flows

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

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(38,152)	$	92,422	$	176,652		—	$	230,922

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(490)		(68,249)		(113,468)		—		(182,207)
Acquisition of businesses, net of cash acquired		—		(71,992)		(637,583)		—		(709,575)
Proceeds from dispositions of property, plant and equipment		—		2,260		474		—		2,734
Payments for equity contributions		(283,749)		(280,911)		—		564,660		—
Other, net		—		(28)		(604)		—		(632)
Net cash provided by (used in) investing activities		(284,239)		(418,920)		(751,181)		564,660		(889,680)

CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		346,742		—		387		—		347,129
Term loan borrowings		200,000		—		100,955		—		300,955
Debt and capital lease payments		(30)		(403)		(54)		—		(487)
Issuance of common stock from share-based payment arrangements		23,361		—		—		—		23,361
Excess tax benefits from share-based payment arrangements		4,029		—		—		—		4,029
Payment of financings costs		(24,548)		—		—		—		(24,548)
Proceeds from (funding of) accounts and notes with affiliates, net		(233,044)		47,116		185,928		—		—
Proceeds from equity contributions		—		280,911		283,749		(564,660)		—
Tax withholdings related to net share settlements of restricted stock		(1,406)		—		—		—		(1,406)
Other, net		(1)		—		—		—		(1)
Net cash provided by (used in) financing activities		315,103		327,624		570,965		(564,660)		649,032

Effect of exchange rate changes on cash		—		(2)		16,479		—		16,477
Net change in cash and cash equivalents from continuing operations		(7,288)		1,124		12,915		—		6,751
Net cash used in discontinued operations operating activities		—		(143)		—		—		(143)
Cash and cash equivalents, beginning of period		7,061		235		82,446		—		89,742

Cash and cash equivalents, end of period	$	(227)	$	1,216	$	95,361		—	$	96,350

- 114 -

Delaware	76-0476605
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

Title of Each Class	Name of Exchange on Which Registered
Common Stock, par value $.01 per share	New York Stock Exchange

Large accelerated filer [X]	Accelerated filer [ ]

Non-accelerated filer [ ] (Do not check if a smaller reporting company)	Smaller reporting company [ ]

	December 31,
	2012		2011		2010
Canadian Oil Sands Lodges

Wapasu		5,174		5,174		4,013
Athabasca		1,877		1,776		1,537
Henday		1,698		1,120		-
Conklin		948		584		608
Beaver River		876		732		732
Lakeside		510		510		510
Other		10		72		83
Total Canadian Oil Sands Lodges		11,093		9,968		7,483

Australian Villages

Coppabella		2,912		2,556		1,654
Dysart		1,912		1,491		1,249
Moranbah		1,240		1,180		889
Middlemount		816		816		690
Narrabri		502		242		-
Nebo		490		490		490
Calliope		300		300		-
Kambalda		238		238		238
Karratha		208		-		-
Total Australian Villages		8,618		7,313		5,210

Location	Approximate Square Footage/ Acreage	Description
United States:
Houston, Texas (lease)	21,420	Principal executive offices
Arlington, Texas (own and lease)	41 acres	Various contiguous offices, manufacturing and warehouse facilities located in thirteen buildings
Houston, Texas	25 acres	Offshore products office, manufacturing facility and yard
Houston, Texas	22 acres	Offshore products manufacturing facility and yard
Houston, Texas (lease)	50,750	Offshore products service facility and office
Houma, Louisiana	40 acres	Offshore products manufacturing facility and yard
Tulsa, Oklahoma	74,600	Molding facility for offshore products
Tulsa, Oklahoma (lease)	14,000	Molding facility for offshore products
Oklahoma City, Oklahoma	70,000	Offshore products service facility and office
Lampasas, Texas	48,500	Molding facility for offshore products
Lampasas, Texas (lease)	20,000	Warehouse for offshore products
Crosby, Texas	109 acres	Tubular yard
Midland, Texas	389 acres	Tubular yard
Godley, Texas	31 acres	Tubular yard
Montoursville, Pennsylvania	24 acres	Tubular yard
Searcy, Arkansas	14 acres	Tubular yard
Tulsa, Oklahoma (lease)	11,955	Tubular services business office
Houston, Texas (lease)	9,945	Tubular services business office
Dickinson, North Dakota (lease)	26 acres	Accommodations facility and yard
Vernal, Utah (lease)	21 acres	Accommodations facility and yard
Carrizo Springs, Texas (lease)	20 acres	Accommodations facility
Johnstown, Colorado	13 acres	Accommodations manufacturing facility and yard
Belle Chasse, Louisiana (own and lease)	10 acres	Accommodations manufacturing facility and yard
Three Rivers, Texas (lease)	9 acres	Accommodations facility
Big Piney, Wyoming (lease)	7 acres	Accommodations facility and yard
Stanley, North Dakota (lease)	7 acres	Accommodations facility
Englewood, Colorado (lease)	5,480	Accommodations office
Houston, Texas	23,441	Completion services office
Midland, Texas	11 acres	Completion services shop
Houma, Louisiana	10 acres	Completion services shop
Rock Springs, Wyoming	10 acres	Completion services shop
Conway, Arkansas	7 acres	Completion services shop
Oklahoma City, Oklahoma	3 acres	Completion services shop
Odessa, Texas	22 acres	Office, shop, warehouse and yard in support of drilling operations for well site services
Casper, Wyoming	7 acres	Office, shop and yard in support of drilling operations for well site services

Canada:
Fort McMurray, Alberta (Wapasu Creek and Henday Lodges) (lease)	240 acres	Accommodations facility
Fort McMurray, Alberta (Pebble Beach) (lease)	140 acres	Accommodations facility
Fort McMurray, Alberta (Conklin Lodge)(lease)	135 acres	Accommodations facility
Fort McMurray, Alberta (Beaver River and Athabasca Lodges) (lease)	128 acres	Accommodations facility
Fort McMurray, Alberta (Christina Lake Lodge)	45 acres	Accommodations facility
Edmonton, Alberta	33 acres	Accommodations manufacturing facility
Grimshaw, Alberta (lease)	20 acres	Accommodations equipment yard
Nisku, Alberta	9 acres	Accommodations manufacturing facility
Edmonton, Alberta (lease)	86,376	Accommodations office and warehouse
Edmonton, Alberta (lease)	28,253	Accommodations office
Edmonton, Alberta (lease)	16,130	Accommodations office
Spruce Grove, Alberta	15,000	Accommodations facility and equipment yard

PART I		Page
Cautionary Statement Regarding Forward-Looking Statements		4
Item 1.	Business	5 – 22
Item 1A.	Risk Factors	22 – 37
Item 1B.	Unresolved Staff Comments	37
Item 2.	Properties	38 – 39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39

PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39 – 42
Item 6.	Selected Financial Data	43 – 44
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	44 – 62
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	63
Item 9A.	Controls and Procedures	63 – 64
Item 9B.	Other Information	65

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	65
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	65
Item 13.	Certain Relationships and Related Transactions, and Director Independence	65
Item 14.	Principal Accounting Fees and Services	65

PART IV
Item 15.	Exhibits, Financial Statement Schedules	65 – 70
SIGNATURES		71
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		72

Australia:
Coppabella, Queensland, Australia	198 acres	Accommodations facility
Calliope, Queensland, Australia	124 acres	Accommodations facility
Narrabri, New South Wales, Australia	82 acres	Accommodations facility
Dysart, Queensland, Australia	50 acres	Accommodations facility
Middlemount, Queensland, Australia	37 acres	Accommodations facility
Karratha, Western Australia, Australia (lease)	34 acres	Accommodations facility
Kambalda, Western Australia, Australia	27 acres	Accommodations facility
Nebo, Queensland, Australia	26 acres	Accommodations facility
Moranbah, Queensland, Australia	17 acres	Accommodations facility
Ormeau, Queensland, Australia (lease)	3 acres	Accommodations manufacturing facility
Yatala, Queensland, Australia (lease)	2 acres	Accommodations manufacturing facility
Sydney, New South Wales, Australia (lease)	17,276	Accommodations office
Brisbane, Queensland, Australia (lease)	7,115	Accommodations office

Other International:
Aberdeen, Scotland (lease)	15 acres	Offshore products manufacturing facility and yard
Rio de Janeiro, Brazil	31 acres	Offshore products manufacturing facility and yard
Macaé, Brazil	17 acres	Offshore products manufacturing facility and yard
Macaé, Brazil (lease)	6 acres	Offshore products manufacturing facility and yard
Singapore (lease)	155,398	Offshore products manufacturing facility
Bathgate, Scotland	3 acres	Offshore products manufacturing facility and yard
Barrow-in-Furness, England (own and lease)	63,300	Offshore products service facility and yard
Rayong Province, Thailand (lease)	28,000	Offshore products service and manufacturing facility

	Sales Price
	High		Low
2011
First Quarter	$	78.43	$	60.76
Second Quarter		83.13		68.49
Third Quarter		87.00		49.40
Fourth Quarter		78.53		44.77
2012
First Quarter	$	87.65	$	75.17
Second Quarter		82.83		60.03
Third Quarter		87.63		65.17
Fourth Quarter		80.46		63.42