OIL STATES INTERNATIONAL, INC - Quarter Report: 2009 June (Form 10-Q)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

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

Commission file number: 1-16337

OIL STATES INTERNATIONAL, INC.

(Exact name of registrant as specified in its charter)

Delaware		76-0476605
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
Three Allen Center, 333 Clay Street, Suite 4620,		77002
Houston, Texas		(Zip Code)
(Address of principal executive offices)

(713) 652-0582

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year,

if changed since last report)

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

YES þ       NO o

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

YES o       NO o

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

YES o       NO þ

The Registrant had 49,651,602 shares of common stock outstanding and 3,232,118 shares of treasury stock as of
July 28, 2009.

 

 

OIL STATES INTERNATIONAL, INC.

INDEX

		Page No.
Part I — FINANCIAL INFORMATION
Item 1. Financial Statements:
Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Month Periods Ended June 30, 2009 and 2008			3
Unaudited Consolidated Balance Sheets – June 30, 2009 and December 31, 2008			4
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008			5
Notes to Unaudited Condensed Consolidated Financial Statements			6–15
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			16–27
Item 3. Quantitative and Qualitative Disclosures About Market Risk			27
Item 4. Controls and Procedures			27
Part II — OTHER INFORMATION
Item 1. Legal Proceedings			28
Item 1A. Risk Factors			28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities			28
Item 3. Defaults Upon Senior Securities			28
Item 4. Submission of Matters to a Vote of Security Holders			28–29
Item 5. Other Information			29
Item 6. Exhibits			29
(a) Index of Exhibits			29–30
Signature Page			31
EX-31.1
EX-31.2
EX-32.1
EX-32.2

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

		THREE MONTHS ENDED								SIX MONTHS ENDED
		JUNE 30,								JUNE 30,
		2009				2008				2009				2008
						AS ADJUSTED								AS ADJUSTED
						(NOTE 11)								(NOTE 11)
Revenues		$	456,334			$	631,364			$	1,123,433			$	1,232,611
Costs and expenses:
Cost of sales and services			361,692				478,435				881,902				923,519
Selling, general and administrative expenses			33,768				35,976				68,413				68,083
Depreciation and amortization expense			28,647				25,689				56,670				48,417
Impairment of goodwill			94,528				—				94,528				—
Other operating expense			935				244				258				234
			519,570				540,344				1,101,771				1,040,253
Operating income/(loss)			(63,236	)			91,020				21,662				192,358
Interest expense			(3,856	)			(6,061	)			(8,101	)			(12,760	)
Interest income			4				894				323				1,815
Equity in earnings of unconsolidated affiliates			475				1,242				934				2,737
Gain on sale of investment			—				2,708				—				2,708
Other income/(expense)			(59	)			(168	)			103				194
Income/( loss) before income taxes			(66,672	)			89,635				14,921				187,052
Income tax (expense) benefit			3,303				(30,338	)			(22,044	)			(62,085	)
Net income/(loss)			(63,369	)			59,297				(7,123	)			124,967
Less: Net income attributable to noncontrolling interest			117				89				235				230
Net income/(loss) attributable to Oil States International, Inc.		$	(63,486	)		$	59,208			$	(7,358	)		$	124,737
Net income/(loss) per share attributable to Oil States International, Inc. common stockholders
Basic		$	(1.28	)		$	1.19			$	(0.15	)		$	2.52
Diluted		$	(1.28	)		$	1.13			$	(0.15	)		$	2.41
Weighted average number of common shares outstanding:
Basic			49,581				49,633				49,549				49,527
Diluted			49,581				52,627				49,549				51,763

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

(In Thousands)

		JUNE 30,				DECEMBER 31,
		2009				2008
						AS ADJUSTED
						(NOTE 11)
ASSETS
Current assets:
Cash and cash equivalents		$	56,099			$	30,199
Accounts receivable, net			319,690				575,982
Inventories, net			502,999				612,488
Prepaid expenses and other current assets			16,741				18,815
Total current assets			895,529				1,237,484
Property, plant, and equipment, net			707,996				695,338
Goodwill, net			214,541				305,441
Investments in unconsolidated affiliates			4,639				5,899
Other non-current assets			35,115				54,356
Total assets		$	1,857,820			$	2,298,518
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	158,858			$	371,789
Income taxes			8,691				52,546
Current portion of long-term debt			4,940				4,943
Deferred revenue			113,457				105,640
Other current liabilities			916				1,587
Total current liabilities			286,862				536,505
Long-term debt			238,881				449,058
Deferred income taxes			54,185				64,780
Other noncurrent liabilities			12,700				12,634
Total liabilities			592,628				1,062,977
Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock			529				526
Additional paid-in capital			459,104				453,733
Retained earnings			893,643				901,001
Accumulated other comprehensive income/(loss)			3,446				(28,409	)
Treasury stock			(92,313	)			(91,831	)
Total Oil States International, Inc. stockholders’ equity			1,264,409				1,235,020
Noncontrolling interest			783				521
Total stockholders’ equity			1,265,192				1,235,541
Total liabilities and stockholders’ equity		$	1,857,820			$	2,298,518

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

		SIX MONTHS
		ENDED JUNE 30,
		2009				2008
						AS ADJUSTED
						(NOTE 11)
Cash flows from operating activities:
Net Income/(loss)		$	(7,123	)		$	124,967
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			56,670				48,417
Deferred income tax provision			(13,285	)			6,372
Excess tax benefits from share-based payment arrangements			—				(3,108	)
Loss on impairment of goodwill			94,528				—
Equity in earnings of unconsolidated subsidiaries, net of dividends			(934	)			(2,484	)
Non-cash compensation charge			5,818				5,124
Accretion of debt discount			3,314				3,086
Gains on sale of investment and disposals of assets			(260	)			(2,788	)
Other, net			1,841				1,091
Changes in working capital			130,627				7,449
Net cash flows provided by operating activities			271,196				188,126
Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired			18				(29,816	)
Capital expenditures			(52,784	)			(135,706	)
Proceeds from note receivable			21,166				—
Proceeds from sale of investment			—				11,156
Other, net			(2,043	)			894
Net cash flows used in investing activities			(33,643	)			(153,472	)
Cash flows from financing activities:
Revolving credit repayments			(216,572	)			(28,738	)
Debt repayments			(225	)			(204	)
Issuance of common stock			501				7,607
Purchase of treasury stock			—				(129	)
Excess tax benefits from share-based payment arrangements			—				3,108
Other, net			(482	)			(981	)
Net cash flows provided by (used in) financing activities			(216,778	)			(19,337	)
Effect of exchange rate changes on cash			5,241				121
Net increase in cash and cash equivalents from continuing operations			26,016				15,438
Net cash used in discontinued operations – operating activities			(116	)			(31	)
Cash and cash equivalents, beginning of period			30,199				30,592
Cash and cash equivalents, end of period		$	56,099			$	45,999
Non-cash investing and financing activities:
Building capital lease		$	—			$	8,304
Non-cash financing activities:
Reclassification of 2 3/8% contingent convertible senior notes to current liabilities			—				145,913

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

1. ORGANIZATION AND BASIS OF PRESENTATION

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

     Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosed amounts of contingent assets and liabilities and the reported amounts of revenues and expenses. If the underlying estimates and assumptions, upon which the financial statements are based, change in future periods, actual amounts may differ from those included in the accompanying condensed consolidated financial statements.

     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 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.

     The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2008. Further, in connection with preparation of the consolidated financial statements and in accordance with the recently issued Statement of Financial Accounting Standards No. 165 (SFAS 165), “Subsequent Events,” the Company evaluated subsequent events after the balance sheet date of June 30, 2009 through the time of filing on July 30, 2009. There were no material subsequent events requiring additional disclosure in or amendment to the quarterly financial statements as of July 30, 2009.

2. RECENT ACCOUNTING PRONOUNCEMENTS

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (SFAS 157), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which deferred the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption was permitted, provided the company had not yet issued financial statements, including for interim periods, for that fiscal year. We adopted those provisions of SFAS 157 that were unaffected by the delay in the first quarter of 2008. Such adoption did not have a material effect on our consolidated statements of financial position, results of operations or cash flows. In the first quarter of 2009, we adopted the remaining provisions of SFAS 157. Certain assets are measured at fair value on a nonrecurring basis; that is, they are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment).

     In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) (SFAS 141R), “Business Combinations,” which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired,

the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and interim periods within those fiscal years. SFAS 141R was effective beginning January 1, 2009; accordingly, any business combinations we engage in after this date will be recorded and disclosed in accordance with this statement. No business combination transactions occurred during the six months ended June 30, 2009.

     In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160 (SFAS 160), “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. SFAS 160 applies prospectively, except for presentation and disclosure requirements, which are applied retrospectively. Effective January 1, 2009, we have presented our noncontrolling interests in accordance with this standard.

     In May 2008, the FASB issued FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement),” which changed the accounting for our Contingent Convertible Senior Subordinated 2 3/8% Notes (2 3/8% Notes). Under the new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity is required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The difference between bond cash proceeds and the estimated fair value is recorded as a debt discount and accreted to interest expense over the expected life of the bond. Although the FSP has no impact on the Company’s actual past or future cash flows, it requires the Company to record a material increase in non-cash interest expense as the debt discount is amortized. The FSP became effective for the Company beginning January 1, 2009 and is applied retrospectively to all periods presented. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this quarterly report on Form 10-Q.

     In May 2009, the FASB issued Statement of Financial Accounting Standards No. 165 (SFAS 165), “Subsequent Events,” which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Under SFAS 165, as under current practice, an entity must record the effects of subsequent events that provide evidence about conditions that existed at the balance sheet date and must disclose but not record the effects of subsequent events which provide evidence about conditions that did not exist at the balance sheet date. This statement is effective for fiscal years, and interim periods within those fiscal years, ending after June 15, 2009. The adoption of SFAS 165 did not have a material impact on the Company’s financial condition, results of operation or disclosures contained in our notes to the condensed consolidated financial statements.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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

		JUNE 30,				DECEMBER 31,
		2009				2008
Accounts receivable, net:
Trade		$	238,151			$	456,975
Unbilled revenue			85,350				119,907
Other			1,372				3,268
Total accounts receivable			324,873				580,150
Allowance for doubtful accounts			(5,183	)			(4,168	)
		$	319,690			$	575,982

		JUNE 30,				DECEMBER 31,
		2009				2008
Inventories, net:
Tubular goods		$	296,222			$	396,462
Other finished goods and purchased products			81,368				88,848
Work in process			60,329				65,009
Raw materials			72,728				68,881
Total inventories			510,647				619,200
Inventory reserves			(7,648	)			(6,712	)
		$	502,999			$	612,488

		ESTIMATED				JUNE 30,				DECEMBER 31,
		USEFUL LIFE				2009				2008
Property, plant and equipment, net:
Land						$	18,750			$	18,298
Buildings and leasehold improvements		3-50 years					144,418				135,080
Machinery and equipment		2-29 years					282,949				270,434
Accommodations assets		10-15 years					331,265				300,765
Rental tools		4-10 years					149,702				141,644
Office furniture and equipment		1-10 years					27,990				26,506
Vehicles		2-10 years					70,759				68,645
Construction in progress							57,750				49,915
Total property, plant and equipment							1,083,583				1,011,287
Less: Accumulated depreciation							(375,587	)			(315,949	)
						$	707,996			$	695,338

		JUNE 30,				DECEMBER 31,
		2009				2008
Accounts payable and accrued liabilities:
Trade accounts payable		$	104,510			$	307,132
Accrued compensation			22,950				35,864
Accrued insurance			9,239				7,551
Accrued taxes, other than income taxes			6,874				7,257
Reserves related to discontinued operations			2,429				2,544
Other			12,856				11,441
		$	158,858			$	371,789

4. EARNINGS PER SHARE

     The calculation of earnings per share attributable to Oil States International, Inc. is presented below (in thousands, except per share amounts):

		THREE MONTHS ENDED								SIX MONTHS ENDED
		JUNE 30								JUNE 30,
		2009				2008				2009				2008
						AS ADJUSTED								AS ADJUSTED
						(NOTE 11)								(NOTE 11)
Basic earnings (loss) per share:
Net income/(loss) attributable to Oil States International, Inc.		$	(63,486	)		$	59,208			$	(7,358	)		$	124,737
Weighted average number of shares outstanding			49,581				49,633				49,549				49,527
Basic earnings (loss) per share		$	(1.28	)		$	1.19			$	(0.15	)		$	2.52
Diluted earnings (loss) per share:
Net income/(loss) attributable to Oil States International, Inc.		$	(63,486	)		$	59,208			$	(7,358	)		$	124,737
Weighted average number of shares outstanding			49,581				49,633				49,549				49,527
Effect of dilutive securities:
Options on common stock			—				614				—				519
2 3/8% Convertible Senior Subordinated Notes			—				2,238				—				1,591
Restricted stock awards and other			—				142				—				126
Total shares and dilutive securities			49,581				52,627				49,549				51,763
Diluted earnings (loss) per share		$	(1.28	)		$	1.13			$	(0.15	)		$	2.41

     Our calculation of diluted earnings per share for the three and six months ended June 30, 2009 excludes 2,063,763 shares and 2,144,140 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect. Our calculation of diluted earnings per share for the three and six months ended June 30, 2008 excludes anti-dilutive shares of 196,793 and 434,877, respectively.

5. BUSINESS ACQUISITIONS AND GOODWILL

     On February 1, 2008, we purchased all of the equity of Christina Lake Enterprises Ltd., an accommodations lodge (Christina Lake Lodge) in the Conklin area of Alberta, Canada. Christina Lake Lodge provides lodging and catering in the southern area of the oil sands region. Consideration for the lodge consisted of $6.9 million in cash, net of cash acquired, including transaction costs, funded from borrowings under the Company’s existing credit facility, and the assumption of certain liabilities and is subject to post-closing working capital adjustments. The Christina Lake Lodge has been included in the accommodations business within the well site services segment since the date of acquisition.

     On February 15, 2008, we acquired a waterfront facility on the Houston ship channel for use in our offshore products segment. This waterfront facility expanded our ability to manufacture, assemble, test and load out larger subsea production and drilling rig equipment thereby expanding our capabilities. Consideration paid for the facility was approximately $22.9 million in cash, including transaction costs, funded from borrowings under the Company’s existing credit facility.

     In June 2009, we acquired the 51% majority interest in a venture we had previously accounted for under the equity method. The business acquired supplies accommodations and other services to mining operations in Canada. Consideration paid for the business was $2.3 million in cash and estimated contingent consideration of $0.3 million.

     Changes in the carrying amount of goodwill for the six month period ended June 30, 2009 are as follows (in thousands):

		Balance as of				Acquisitions				Foreign currency								Balance as of
		January 1,				and				translation and				Goodwill				June 30,
		2009				adjustments				other changes				impairment				2009
Offshore Products		$	85,074			$	—			$	623			$	—			$	85,697
Well Site Services			220,367				337				2,668				(94,528	)			128,844
Total		$	305,441			$	337			$	3,291			$	(94,528	)		$	214,541

     Based on a combination of factors (including the current global economic environment, the Company’s outlook for U.S. drilling activity and pricing and the current market capitalization for the Company and comparable oilfield service companies), and consistent with methodologies utilized by the Company in the past as described in its Annual Report on Form 10-K for the year ended December 31, 2008, the Company concluded that the goodwill amounts previously recorded in its rental tools reporting unit were partially impaired as of June 30, 2009. The total goodwill impairment charge recognized in the second quarter of 2009 was $94.5 million before taxes and $84.5 million after-tax. This non-cash charge did not impact the Company’s liquidity position, its debt covenants or cash flows. The fair value measurements used for our goodwill impairment testing use significant unobservable Level 3 inputs which reflect our own assumptions about the assumptions that market participants would use in measuring fair value including assumptions about risk.

6. DEBT

     As of June 30, 2009 and December 31, 2008, long-term debt consisted of the following (in thousands):

		June 30,				December 31,
		2009				2008
						As Adjusted
		(Unaudited)				(Note 11)
U.S. revolving credit facility which matures on December 5, 2011, with available commitments up to $325 million and with an average interest rate of 1.3% for the six month period ended June 30, 2009		$	77,200			$	226,000
Canadian revolving credit facility which matures on December 5, 2011, with available commitments up to $175 million and with an average interest rate of 1.9% for the six month period ended June 30, 2009			—				61,244
2 3/8% contingent convertible senior subordinated notes, net — due 2025			152,425				149,110
Subordinated unsecured notes payable to sellers of businesses, interest rate of 6%, maturing in 2009			4,500				4,500
Capital lease obligations and other debt			9,696				13,147
Total debt			243,821				454,001
Less: current maturities			(4,940	)			(4,943	)
Total long-term debt		$	238,881			$	449,058

     As of June 30, 2009, we have classified the $175.0 million principal amount of our 2 3/8% Notes, net of unamortized discount, as a noncurrent liability because certain contingent conversion thresholds based on the Company’s stock price were not met at that date and, as a result, note holders could not present their notes for conversion during the quarter following the June 30, 2009 measurement date. The future convertibility and resultant balance sheet classification of this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company’s common stock during the prescribed measurement periods.

     In May 2008, the FASB issued FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which changed the accounting for our 2 3/8% Notes. Under the new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity is required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The FSP is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this quarterly report on Form 10-Q.

     At June 30, 2009, the Company had approximately $56.1 million of cash and cash equivalents. In addition, at June 30, 2009, $403.3 million of the Company’s $500 million U.S. and Canadian revolving credit facility was available for future financing needs.

     The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, notes receivable, payables, and debt instruments. The Company believes that the carrying values of these instruments, other than our fixed rate contingent convertible senior notes, on the accompanying consolidated balance sheets approximate their fair values.

     The fair value of our 2 3/8% contingent convertible senior notes is estimated based on prices quoted from third-party financial institutions. The carrying and fair values of these notes are as follows (in thousands):

						June 30, 2009								December 31, 2008
		Interest				Carrying				Fair				Carrying				Fair
		Rate				Value				Value				Value				Value
Principal amount due 2025			2 3/8	%		$	175,000			$	176,792			$	175,000			$	133,613
Less: Unamortized discount							(22,575	)			—				(25,890	)			—
Net value						$	152,425			$	176,792			$	149,110			$	133,613

     As of June 30, 2009, the estimated fair value of the Company’s debt outstanding under its revolving credit facility is estimated to be lower than carrying value since the terms of this facility are more favorable than those that might be expected to be available in the current credit and lending environment. We are unable to estimate the fair value of the Company’s bank debt due to the potential variability of expected outstanding balances under the facility.

7.

COMPREHENSIVE INCOME (LOSS) AND CHANGES IN COMMON STOCK OUTSTANDING:

     Comprehensive income (loss) for the three and six months ended June 30, 2009 and 2008 was as follows (dollars in thousands):

		THREE MONTHS								SIX MONTHS
		ENDED JUNE 30,								ENDED JUNE 30,
		2009				2008				2009				2008
						As Adjusted								As Adjusted
						(Note 11)								(Note 11)
Net income/(loss)		$	(63,369	)		$	59,297			$	(7,123	)		$	124,967
Other comprehensive income/(loss):
Cumulative translation adjustment			43,676				4,037				31,855				(8,459	)
Unrealized gain on marketable securities			—				1,804				—				1,804
Total other comprehensive income/(loss)			43,676				5,841				31,855				(6,655	)
Comprehensive income/(loss)			(19,693	)			65,138				24,732				118,312
Comprehensive income attributable to noncontrolling interest		(117)					(89	)			(235	)			(230	)
Comprehensive income/(loss) attributable to Oil States International, Inc.		$	(19,810	)		$	65,049			$	24,497			$	118,082

Shares of common stock outstanding – January 1, 2009			49,500,708
Shares issued upon exercise of stock options and vesting of stock awards			166,967
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury			(24,329	)
Shares of common stock outstanding – June 30, 2009			49,643,346

8. STOCK BASED COMPENSATION

     During the first six months of 2009, we granted restricted stock awards totaling 191,487 shares valued at $3.6 million. A total of 121,500 of these awards vest in four equal annual installments, 25,500 awards vest in their entirety only after three years of service, 43,328 awards made to directors vest after one year and the remaining 1,159 awards vested immediately as part of compensation paid to the chairman of the Company’s board of directors. A total of 768,650 stock options were awarded in the six months ended June 30, 2009 with an average exercise price of $17.20 and a six-year term. A total of 714,450 of these options vest in annual 25% increments over the next four years and the remaining 54,200 options vest in their entirety only after three years of service.

     Stock based compensation pre-tax expense recognized in the six month period ended June 30, 2009 totaled $5.8 million, or $0.08 per diluted share after tax (excluding the impact on the Company’s effective tax rate of the goodwill impairment recognized during the period.) Stock based compensation pre-tax expense recognized in the six month period ended June 30, 2008 totaled $5.1 million, or $0.07 per diluted share after tax. Stock based compensation pre-tax expense recognized in the three month period ended June 30, 2009 totaled $2.9 million, or $0.04 per diluted share after tax (excluding the impact on the Company’s effective tax rate of the goodwill impairment recognized during the period.) Stock based compensation pre-tax expense recognized in the three month period ended June 30, 2008 totaled $2.6 million, or $0.03 per diluted share after tax. The total fair value of restricted stock awards that vested during the six months ended June 30, 2009 was $2.5 million. At June 30, 2009, $21.5 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.

9. INCOME TAXES

     The Company’s income tax benefit for the three months ended June 30, 2009 totaled $3.3 million, or 5.0% of pretax losses, compared to income tax expense of $30.3 million, or 33.8% of pretax income, for the three months ended June 30, 2008. The Company’s income tax provision for the six months ended June 30, 2009 totaled $22.0 million, or 147.7% of pretax income, compared to $62.1 million, or 33.2% of pretax income, for the six months ended June 30, 2008. The effective tax rates in the three and six months ended June 30, 2009 were negatively impacted by a significant amount of the goodwill impairment charges which were non-deductible for tax purposes. Excluding the goodwill impairment, the effective tax rates for the three and six months ended June 30, 2009 would have approximated 24.0% and 29.3%, respectively. The decrease in effective tax rates (excluding the goodwill impairment) from the prior year is largely the result of proportionately higher foreign sourced income in 2009 compared to 2008 which is taxed at lower statutory rates, coupled with domestic benefits derived from estimated tax losses.

10. SEGMENT AND RELATED INFORMATION

     In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” the Company has identified the following reportable segments: well site services, offshore products and tubular services. The Company’s reportable segments are strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. The separate business lines within the well site services segment have been disclosed to provide additional detail for that segment. Results of a portion of our Canadian business related to the provision of work force accommodations, catering and logistics services are seasonal with a major part of expected activity occurring in the winter drilling season.

     Financial information by business segment for each of the three and six months ended June 30, 2009 and 2008 is summarized in the following table (in thousands):

		Revenues from				Depreciation
		unaffiliated				and				Operating				Capital
		customers				amortization				income (loss)				expenditures				Total assets
Three months ended June 30, 2009
Well Site Services —
Accommodations		$	88,400			$	9,050			$	25,770			$	9,370			$	496,513
Rental tools			53,629				9,859				(98,612	)			4,975				342,699
Drilling and other			10,861				6,483				(6,313	)			2,028				120,091
Total Well Site Services			152,890				25,392				(79,155	)			16,373				959,303
Offshore Products			122,511				2,742				17,548				2,830				504,698
Tubular Services			180,933				377				5,967				101				378,664
Corporate and Eliminations			—				136				(7,596	)			810				15,155
Total		$	456,334			$	28,647			$	(63,236	)		$	20,114			$	1,857,820

		Revenues from				Depreciation
		unaffiliated				and				Operating				Capital
		customers				amortization				income (loss)				expenditures				Total assets
Three months ended June 30, 2008
Well Site Services —
Accommodations		$	80,880			$	8,581			$	17,257			$	41,075			$	515,164
Rental tools			84,576				9,036				16,293				17,443				447,491
Drilling and other (1)			44,426				4,810				10,794				10,667				194,798
Total Well Site Services			209,882				22,427				44,344				69,185				1,157,453
Offshore Products			139,850				2,859				24,936				5,057				500,147
Tubular Services			281,632				336				28,751				471				416,607
Corporate and Eliminations			—				67				(7,011	)			148				22,334
Total		$	631,364			$	25,689			$	91,020			$	74,861			$	2,096,541

		Revenues from				Depreciation
		unaffiliated				and				Operating				Capital
		customers				amortization				income (loss)				expenditures				Total assets
Six months ended June 30, 2009
Well Site Services —
Accommodations		$	230,232			$	17,491			$	74,014			$	21,604			$	496,513
Rental tools			125,354				19,816				(94,967	)			16,770				342,699
Drilling and other			28,145				12,916				(9,808	)			7,240				120,091
Total Well Site Services			383,731				50,223				(30,761	)			45,614				959,303
Offshore Products			250,510				5,436				38,734				5,898				504,698
Tubular Services			489,192				753				28,878				196				378,664
Corporate and Eliminations			—				258				(15,189	)			1,076				15,155
Total		$	1,123,433			$	56,670			$	21,662			$	52,784			$	1,857,820

		Revenues from				Depreciation
		unaffiliated				and				Operating				Capital
		customers				amortization				income (loss)				expenditures				Total assets
Six months ended June 30, 2008
Well Site Services —
Accommodations		$	227,137			$	16,389			$	70,065			$	69,368			$	515,164
Rental tools			167,069				16,872				33,924				34,952				447,491
Drilling and other (1)			81,230				8,847				16,846				20,424				194,798
Total Well Site Services			475,436				42,108				120,835				124,744				1,157,453
Offshore Products			266,772				5,512				46,383				9,880				500,147
Tubular Services			490,403				664				38,272				919				416,607
Corporate and Eliminations			—				133				(13,132	)			163				22,334
Total		$	1,232,611			$	48,417			$	192,358			$	135,706			$	2,096,541

11. ADOPTION OF FSP APB 14-1

     Effective January 1, 2009, we adopted FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement.)” Under the new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity is required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. FSP APB 14-1 requires retrospective restatement of all periods presented back to the date of issuance with the cumulative effect of the change in accounting principle on prior periods being recognized as of the beginning of the first period. The adoption of FSP APB 14-1 affects the accounting, both retrospectively and prospectively, for our 2 3/8% Notes issued in June 2005. Although the FSP has no impact on the Company’s actual past or future cash flows, it requires the Company to record a material increase in non-cash interest expense as the debt discount is amortized.

The following tables present the effect of our adoption of FSP APB 14-1 on our condensed consolidated statements of operations for the three and six months ended June 30, 2008 and our condensed consolidated balance sheet as of December 31, 2008, applied retrospectively (in thousands, except per share data):

		Three months ended June 30, 2008												Six months ended June 30, 2008
		Prior to				Effect of				As				Prior to				Effect of				As
		adoption				adoption				adjusted				adoption				adoption				adjusted
Interest expense		$	4,561			$	1,500			$	6,061			$	9,788			$	2,972			$	12,760
Income before income taxes			91,135				(1,500	)			89,635				190,024				(2,972	)			187,052
Net income (a)			60,252				(955	)			59,297				126,860				(1,893	)			124,967
Net income attributable to Oil States International, Inc. (a)		$	60,163			$	(955	)		$	59,208			$	126,630			$	(1,893	)		$	124,737
Net income per share attributable to Oil States International common stockholders:
Basic		$	1.21			$	(0.02	)		$	1.19			$	2.56			$	(0.04	)		$	2.52
Diluted		$	1.14			$	(0.01	)		$	1.13			$	2.45			$	(0.04	)		$	2.41

		December 31, 2008
		Prior to				Effect of
		adoption				adoption				As adjusted
Other non-current assets		$	55,085			$	(729	)		$	54,356
Total assets			2,299,247				(729	)			2,298,518
Long-term debt		$	474,948			$	(25,890	)		$	449,058
Deferred income taxes			55,646				9,134				64,780
Total liabilities			1,079,733				(16,756	)			1,062,977
Additional paid-in capital			425,284				28,449				453,733
Retained earnings			913,423				(12,422	)			901,001
Total Oil States International, Inc. stockholders’ equity (a)			1,218,993				16,027				1,235,020
Total stockholders’ equity (a)			1,219,514				16,027				1,235,541
Total liabilities and stockholders’ equity		$	2,299,247			$	(729	)		$	2,298,518

     Debt issue costs at December 31, 2008, recorded in other noncurrent assets, decreased $0.7 million as a result of the adoption of FSP APB 14-1, representing the cumulative adjustment caused by the reclassification of a portion of debt issue costs to additional paid-in capital as required by FSP APB 14-1.

     The cumulative effect of the change on retained earnings as of January 1, 2008, is $8.6 million due to the retrospective increase in interest expense for the years 2005, 2006 and 2007.

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

		June 30, 2009				December 31, 2008
Carrying amount of the equity component in additional paid-in capital		$	28,449			$	28,449
Principal amount of the liability component		$	175,000			$	175,000
Less: Unamortized discount			(22,575	)			(25,890	)
Net carrying amount of the liability component		$	152,425			$	149,110

     Following our adoption of FSP APB 14-1, the effective interest rate was 7.17% for our 2 3/8% Notes. Interest expense, excluding amortization of debt issue costs, was as follows (in thousands):

		Three months ended June 30,								Six months ended June 30,
		2009				2008				2009				2008
Interest expense		$	2,711			$	2,596			$	5,392			$	5,162

		June 30, 2009
Remaining period over which discount will be amortized		3.0 years
Conversion price		$	31.75
Number of shares to be delivered upon conversion (1)			n/a
Conversion value in excess of principal amount (1)			n/a
Derivative transactions entered into in connection with the convertible notes		None

12. COMMITMENTS AND CONTINGENCIES

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

     This quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Exchange Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to Item “Part I, Item 1.A. Risk Factors” and the financial statement line item discussions set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission on February 20, 2009. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.

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

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

Overview

     We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices except for our accommodations activities supporting oil sands developments which we believe are more tied to the long-term outlook for crude oil prices. Our offshore products segment provides highly engineered and technically designed products for offshore oil and gas development and production systems and facilities. Sales of our offshore products and services depend upon the development of 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 activities, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales and gross margins of our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled, and the level of OCTG inventory and pricing. Historically, tubular services’ gross margin expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. In our well site services business segment, we provide land drilling services, work force accommodations and associated services and rental tools. Demand for our drilling services is driven by land drilling activity in our primary drilling markets in Texas, Ohio and in the Rocky Mountains area in the U.S. Our rental tools and services depend primarily upon the level of drilling, completion and workover activity in North America. Our accommodations business is conducted principally in Canada and its activity levels are currently being driven primarily by oil sands development activities in northern Alberta.

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

		Average Drilling Rig Count for
		Three Months Ended								Six Months Ended
		June 30,				June 30,				June 30,				June 30,
		2009				2008				2009				2008
U.S. Land			887				1,797				1,078				1,755
U.S. Offshore			49				67				53				62
Total U.S.			936				1,864				1,131				1,817
Canada			90				169				210				338
Total North America			1,026				2,033				1,341				2,155

     The average North American rig count for the three months ended June 30, 2009 decreased by 1,007 rigs, or 49.5%, compared to the three months ended June 30, 2008. As of July 24, 2009, the North American rig count has increased to 1,123 rigs.

     Since late 2008 and throughout 2009 to date, we have seen unprecedented declines in the global economic outlook that were initially fueled by the housing and credit crises which have led to reduced growth, and in some instances, decreased overall output. Energy prices have declined precipitously from prior record levels attained in 2008. Given our customers’ decreased cash flows caused by lower energy prices as well as shrinking credit availability affecting some of them, funds available for exploration and development have been reduced. This has led to material declines in the drilling rig count, particularly in North America. Although our Company remains financially strong with significant undrawn revolver capacity and cash on our balance sheet, our operations have been materially adversely affected by the reduced rig count in the North American energy sector as well as the uncertainty about the level of future oil and natural gas prices. We have experienced a significant decline in the utilization of our land drilling rigs beginning in late 2008 and continuing in the first half of 2009. Our customers have delayed or cancelled exploration and development plans and have sought pricing concessions from us.

     An additional important factor in our business, particularly in our land based North American businesses, has been the successful development of several shale discoveries which we support through our rental tool and OCTG businesses. Much of the continuing exploration and development activity has focused in these shale areas leading us and many of our competitors to relocate equipment to and also concentrate on these areas leading to increased competition and lower pricing. Domestic U.S. natural gas prices have decreased from a peak of approximately $13.00 per Mcf in July 2008 to recent levels of approximately $3.00 to $3.75 per Mcf. Analysts are expecting continued weakness in natural gas prices until reduced drilling activity and forced production shut-ins reverse gas supply excesses or demand for the commodity increases. The rig count is not currently expected to recover to levels reached during peak activity levels in 2008.

     Since our evaluation of market conditions at year-end, we have markedly reduced our expectations for the level of North American drilling activity, which is the primary driver of our rental tools utilization and pricing. We considered the factors driving these diminished expectations, among others, in assessing goodwill for potential impairment. As a result of our assessment, we wrote off a total of $94.5 million, or $84.5 million after tax, of goodwill in our rental tools reporting unit in the second quarter of 2009. See Note 5 to the Consolidated Financial Statements included in this Quarterly Report on Form 10-Q. Should conditions related to our rental tools reporting unit deteriorate further, we could potentially write off all or part of that reporting unit’s remaining goodwill balance of $73.6 million.

     Crude oil prices fell to approximately $30 to $35 per barrel during the quarter ended March 31, 2009. We have seen oil prices recover from recent lows experienced in the first quarter of 2009. As of mid-July 2009, crude oil was trading in a range of $59 to $65 per barrel, which though improved, is far below its all time high closing price of $147 per barrel. Current crude oil prices have led to a partial recovery of drilling activity in the oil related rig count in the United States and the sanctioning of some oil sands development projects in Canada. However, it is unknown whether crude oil prices will stabilize at levels that will continue to support significant levels of exploration and production.

     For the first six months of 2009, the Canadian dollar was valued at an average exchange rate of U.S. $0.83 compared to U.S. $0.99 for the first six months of 2008, a decrease of 16%. This weakening of the Canadian dollar had a significant negative impact on the translation of earnings generated from our Canadian subsidiaries.

     The major U.S. steel mills increased OCTG prices during 2008 because of high product demand, overall tight supplies and also in response to raw material and other cost increases. However, steel prices have declined precipitously during 2009 on a global basis and industry inventories have increased materially as the rig count has declined. These trends have had a material detrimental impact on OCTG pricing and, accordingly, on our revenues and margins realized during the second quarter of 2009 in our tubular services segment. These trends, if continued for an extended period, could also negatively impact the valuation of our OCTG inventory, potentially resulting in lower of cost or market write-downs in the future.

     We continue to monitor the effect of the financial crisis on the global economy, the demand for crude oil and natural gas, and the resulting impact on the capital spending budgets of exploration and production companies in order to estimate the effect on our Company. We have reduced our capital spending significantly in 2009 compared to 2008. We currently expect that 2009 capital expenditures will total approximately $140 million compared to 2008 capital expenditures of $247.4 million. Our 2009 capital expenditures include funding to complete projects in progress at December 31, 2008, including expansion of our Wapasu Creek facility, for international expansion at offshore products and for ongoing maintenance capital requirements. In our well site services segment, we continue to monitor industry capacity additions and make future capital expenditure decisions based on a careful evaluation of both the market outlook and industry fundamentals. In our tubular services segment, we remain focused on industry inventory levels, future drilling and completion activity and OCTG prices. Throughout our businesses, we have implemented a variety of cost saving measures, including headcount reductions and reductions in overhead costs, in response to industry conditions to reduce expense levels in line with decreased revenues.

Consolidated Results of Operations (in millions)

		THREE MONTHS ENDED																SIX MONTHS ENDED
		JUNE 30,																JUNE 30,
										Variance																Variance
										2009 vs. 2008																2009 vs. 2008
		2009				2008				$				%				2009				2008				$				%
Revenues
Well Site Services —
Accommodations		$	88.4			$	80.9			$	7.5				9	%		$	230.2			$	227.1			$	3.1				1	%
Rental Tools			53.6				84.6				(31.0	)			(37	%)			125.4				167.1				(41.7	)			(25	%)
Drilling and Other			10.9				44.4				(33.5	)			(75	%)			28.1				81.2				(53.1	)			(65	%)
Total Well Site Services			152.9				209.9				(57.0	)			(27	%)			383.7				475.4				(91.7	)			(19	%)
Offshore Products			122.5				139.9				(17.4	)			(12	%)			250.5				266.8				(16.3	)			(6	%)
Tubular Services			180.9				281.6				(100.7	)			(36	%)			489.2				490.4				(1.2	)			0	%
Total		$	456.3			$	631.4			$	(175.1	)			(28	%)		$	1,123.4			$	1,232.6			$	(109.2	)			(9	%)
Product costs; Service and other costs (“Cost of sales and service”)
Well Site Services —
Accommodations		$	48.8			$	48.6			$	0.2				0	%		$	128.7			$	128.2			$	0.5				0	%
Rental Tools			40.3				50.3				(10.0	)			(20	%)			90.1				98.4				(8.3	)			(8	%)
Drilling and Other			10.0				27.9				(17.9	)			(64	%)			23.6				53.9				(30.3	)			(56	%)
Total Well Site Services			99.1				126.8				(27.7	)			(22	%)			242.4				280.5				(38.1	)			(14	%)
Offshore Products			91.2				102.7				(11.5	)			(11	%)			186.6				198.1				(11.5	)			(6	%)
Tubular Services			171.4				248.9				(77.5	)			(31	%)			452.9				444.9				8.0				2	%
Total		$	361.7			$	478.4			$	(116.7	)			(24	%)		$	881.9			$	923.5			$	(41.6	)			(5	%)
Gross margin
Well Site Services —
Accommodations		$	39.6			$	32.3			$	7.3				23	%		$	101.5			$	98.9			$	2.6				3	%
Rental Tools			13.3				34.3				(21.0	)			(61	%)			35.3				68.7				(33.4	)			(49	%)
Drilling and Other			0.9				16.5				(15.6	)			(95	%)			4.5				27.3				(22.8	)			(84	%)
Total Well Site Services			53.8				83.1				(29.3	)			(35	%)			141.3				194.9				(53.6	)			(28	%)
Offshore Products			31.3				37.2				(5.9	)			(16	%)			63.9				68.7				(4.8	)			(7	%)
Tubular Services			9.5				32.7				(23.2	)			(71	%)			36.3				45.5				(9.2	)			(20	%)
Total		$	94.6			$	153.0			$	(58.4	)			(38	%)		$	241.5			$	309.1			$	(67.6	)			(22	%)
Gross margin as a percentage of revenues
Well Site Services —
Accommodations			45	%			40	%											44	%			44	%
Rental Tools			25	%			41	%											28	%			41	%
Drilling and Other			8	%			37	%											16	%			34	%
Total Well Site Services			35	%			40	%											37	%			41	%
Offshore Products			26	%			27	%											26	%			26	%
Tubular Services			5	%			12	%											7	%			9	%
Total			21	%			24	%											22	%			25	%