UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2008

OR

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

For the transition period from                                          to                                        

OIL STATES INTERNATIONAL, INC.

 

(Exact name of registrant as specified in its charter)

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

(713) 652-0582

(Registrant’s telephone number, including area code)

None
(Former name, former address and former fiscal year,
if changed since last report)

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

YES þ NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “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 49,841,790 shares of common stock outstanding and 2,812,260 shares of treasury stock as of July 28, 2008.

 

 

OIL STATES INTERNATIONAL, INC.

INDEX

		Page No.
Part I — FINANCIAL INFORMATION
Item 1. Financial Statements:
Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Statements of Income for the Three and Six Month Periods Ended June 30, 2008 and 2007			3
Consolidated Balance Sheets — June 30, 2008 (unaudited) and December 31, 2007			4
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2008 and 2007			5
Notes to Unaudited Condensed Consolidated Financial Statements			6 – 13
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			14 – 23
Item 3. Quantitative and Qualitative Disclosures About Market Risk			23
Item 4. Controls and Procedures			23
Part II — OTHER INFORMATION
Item 1. Legal Proceedings			24
Item 1A. Risk Factors			24
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities			24
Item 3. Defaults Upon Senior Securities			24
Item 4. Submission of Matters to a Vote of Security Holders			24 – 25
Item 5. Other Information			25
Item 6. Exhibits			25
(a) Index of Exhibits			25 – 26
Signature Page			27
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to Rule 13a-14(b)
Certification of CFO Pursuant to Rule 13a-14(b)

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

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

		THREE MONTHS ENDED								SIX MONTHS ENDED
		JUNE 30,								JUNE 30,
		2008				2007				2008				2007
Revenues		$	631,364			$	499,308			$	1,232,611			$	979,824
Costs and expenses:
Cost of sales			478,435				386,710				923,519				742,513
Selling, general and administrative expenses			35,976				28,225				68,083				55,548
Depreciation and amortization expense			25,689				16,113				48,417				30,532
Other operating (income)/expense			244				(221	)			234				(141	)
			540,344				430,827				1,040,253				828,452
Operating income			91,020				68,481				192,358				151,372
Interest expense			(4,561	)			(3,739	)			(9,788	)			(8,581	)
Interest income			894				784				1,815				1,710
Equity in earnings of unconsolidated affiliates			1,242				748				2,737				1,290
Gain on sale of investment			2,708				12,774				2,708				12,774
Other income/(expense)			(257	)			237				(36	)			351
Income before income taxes			91,046				79,285				189,794				158,916
Income tax expense			(30,883	)			(27,052	)			(63,164	)			(54,222	)
Net income		$	60,163			$	52,233			$	126,630			$	104,694
Net income per share:
Basic		$	1.21			$	1.06			$	2.56			$	2.12
Diluted		$	1.14			$	1.03			$	2.45			$	2.08
Weighted average number of common shares outstanding:
Basic			49,633				49,341				49,527				49,305
Diluted			52,627				50,833				51,763				50,414

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In Thousands)

		JUNE 30,				DECEMBER 31,
		2008				2007
		(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents		$	45,999			$	30,592
Accounts receivable, net			442,389				450,153
Inventories, net			402,715				349,347
Prepaid expenses and other current assets			33,417				35,575
Total current assets			924,520				865,667
Property, plant, and equipment			694,082				586,910
Goodwill, net			401,652				391,644
Investments in unconsolidated affiliates			5,945				24,778
Other non-current assets			71,185				60,627
Total assets		$	2,097,384			$	1,929,626
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt		$	179,930			$	4,718
Accounts payable and accrued liabilities			276,805				239,119
Income taxes			978				43
Deferred revenue			62,874				60,910
Other current liabilities			1,595				121
Total current liabilities			522,182				304,911
Long-term debt			288,965				487,102
Deferred income taxes			54,151				40,550
Other liabilities			12,212				12,236
Total liabilities			877,510				844,799
Stockholders’ equity:
Common stock			526				522
Additional paid-in capital			417,926				402,091
Retained earnings			817,343				690,713
Accumulated other comprehensive income			66,381				73,036
Treasury stock			(82,302	)			(81,535	)
Total stockholders’ equity			1,219,874				1,084,827
Total liabilities and stockholders’ equity		$	2,097,384			$	1,929,626

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,
		2008				2007
Cash flows from operating activities:
Net income		$	126,630			$	104,694
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			48,417				30,532
Deferred income tax provision			7,451				2,989
Excess tax benefits from share-based payment arrangements			(3,108	)			(3,344	)
Equity in earnings of unconsolidated subsidiaries, net of dividends			(2,484	)			(1,290	)
Non-cash compensation charge			5,124				3,708
Gain on sale of investment			(2,708	)			(12,774	)
Gain on disposal of assets			(80	)			(825	)
Other, net			1,260				19
Changes in working capital			7,449				(2,292	)
Net cash flows provided by operating activities			187,951				121,417
Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired			(29,816	)			—
Capital expenditures			(135,706	)			(100,556	)
Proceeds from sale of investment			11,156				29,354
Other, net			894				906
Net cash flows used in investing activities			(153,472	)			(70,296	)
Cash flows from financing activities:
Revolving credit borrowings (repayments)			(28,738	)			(52,983	)
Debt repayments			(204	)			(5,504	)
Issuance of common stock			7,607				6,684
Purchase of treasury stock			(129	)			(12,211	)
Excess tax benefits from share-based payment arrangements			3,108				3,344
Other, net			(806	)			(421	)
Net cash flows provided by (used in) financing activities			(19,162	)			(61,091	)
Effect of exchange rate changes on cash			121				2,869
Net increase (decrease) in cash and cash equivalents from continuing operations			15,438				(7,101	)
Net cash used in discontinued operations — operating activities			(31	)			(174	)
Cash and cash equivalents, beginning of period			30,592				28,396
Cash and cash equivalents, end of period		$	45,999			$	21,121
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		$	175,000			$	175,000

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

     The accompanying unaudited consolidated financial statements of Oil States International, Inc. and its wholly-owned subsidiaries (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, 2007.

2. RECENT ACCOUNTING PRONOUNCEMENT

     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 defers 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 is permitted, provided the company has 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 statement of financial position, results of operations or cash flows. The Company does not have any material recurring fair value measurements.

     In February 2007, the FASB issued SFAS No. 159 (SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115.” SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. As of January 1, 2008, the Company did not elect the fair value option on eligible assets and liabilities.

     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 is effective for fiscal years beginning after December 15, 2008. Since SFAS 141R will be adopted prospectively, it is not possible to determine the effect, if any, on the Company’s results from operations or financial position.

     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 beginning after December 15, 2008. The adoption of SFAS 160 is not expected to have a material impact on our results from operations or financial position.

     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 will change 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 will be 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 effect of the new rules on our 2 3/8% Notes is that the equity component will be classified as part of stockholders’ equity on our balance sheet and the value of the equity component will be treated as an original issue discount for purposes of accounting for the debt component of the 2 3/8% Notes. Higher non-cash interest expense will result by recognizing the accretion of the discounted carrying value of the debt component of the 2 3/8% Notes as interest expense over the estimated life of the 2 3/8% Notes using an effective interest rate method of amortization. However, there will be no effect on our cash interest payments. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application. The Company is currently evaluating the impact of this FSP; however, the impact of this accounting change is expected to have a significant effect on previously reported and future non-cash interest expense associated with the 2 3/8% Notes.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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

		JUNE 30,				DECEMBER 31,
		2008				2007
Accounts receivable, net:
Trade		$	345,764			$	353,716
Unbilled revenue			92,838				97,579
Other			6,860				2,487
Allowance for doubtful accounts			(3,073	)			(3,629	)
		$	442,389			$	450,153

		JUNE 30,				DECEMBER 31,
		2008				2007
Inventories, net:
Tubular goods		$	227,182			$	191,374
Other finished goods and purchased products			69,834				61,306
Work in process			52,191				56,479
Raw materials			61,266				47,737
Total inventories			410,473				356,896
Inventory reserves			(7,758	)			(7,549	)
		$	402,715			$	349,347

		ESTIMATED				JUNE 30,				DECEMBER 31,
		USEFUL LIFE				2008				2007
Property, plant and equipment, net:
Land						$	20,605			$	12,665
Buildings and leasehold improvements		2-50 years					134,451				107,954
Machinery and equipment		2-29 years					259,367				220,049
Accommodations assets		10-15 years					314,975				276,182
Rental tools		4-10 years					127,815				108,968
Office furniture and equipment		1-10 years					25,157				23,659
Vehicles		2-10 years					64,321				52,508
Construction in progress							45,375				43,046
Total property, plant and equipment							992,066				845,031
Less: Accumulated depreciation							(297,984	)			(258,121	)
						$	694,082			$	586,910

		JUNE 30,				DECEMBER 31,
		2008				2007
Accounts payable and accrued liabilities:
Trade accounts payable		$	221,901			$	186,357
Accrued compensation			21,984				27,156
Accrued insurance			7,497				7,386
Accrued taxes, other than income taxes			8,282				3,733
Reserves related to discontinued operations			2,809				2,839
Other			14,332				11,648
		$	276,805			$	239,119

4. EARNINGS PER SHARE

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

		THREE MONTHS ENDED								SIX MONTHS ENDED
		JUNE 30,								JUNE 30,
		2008				2007				2008				2007
Basic earnings per share:
Net income		$	60,163			$	52,233			$	126,630			$	104,694
Weighted average number of shares outstanding			49,633				49,341				49,527				49,305
Basic earnings per share		$	1.21			$	1.06			$	2.56			$	2.12
Diluted earnings per share:
Net income		$	60,163			$	52,233			$	126,630			$	104,694
Weighted average number of shares outstanding			49,633				49,341				49,527				49,305
Effect of dilutive securities:
Options on common stock			614				673				519				664
2 3/8% Convertible Senior Subordinated Notes			2,238				741				1,591				370
Restricted stock awards and other			142				78				126				75
Total shares and dilutive securities			52,627				50,833				51,763				50,414
Diluted earnings per share		$	1.14			$	1.03			$	2.45			$	2.08

5. BUSINESS ACQUISITIONS AND GOODWILL

     In July and August 2007, the Company announced the expansion of its rental tools operations through two acquisitions.

     On July 1, 2007, we acquired the business of Wire Line Service, Ltd. (Well Testing) for cash consideration of $43.4 million, including transaction costs, funded from borrowings under the Company’s existing credit facility, plus a note payable to the former owner of $3.0 million that will mature on July 1, 2009. Well Testing provides well testing and flowback services through its locations in Texas and New Mexico. The operations of Well Testing have been included in the rental tools business within the well site services segment since the date of acquisition.

     On August 1, 2007, we acquired the business of Schooner Petroleum Services, Inc. (Schooner) for cash consideration of $59.7 million, net of cash acquired, including transactions costs, funded from borrowings under the Company’s existing credit facility, plus a note payable to the former owner of $6.0 million that will mature on August 1, 2009. Schooner, headquartered in Houston, Texas, primarily provides completion-related rental tools and services through eleven locations in Texas, Louisiana, Wyoming and Arkansas. The operations of Schooner have been included in the rental tools business within the well site services segment since the date of acquisition.

     In 2008, we made an acquisition in our accommodations business and in our offshore products segment.

     On February 1, 2008, we purchased all of the equity of Christina Lake Enterprises Ltd., the owners of an accommodations lodge (Christina Lake Lodge) in the Conklin area of Alberta, Canada. Christina Lake Lodge provides lodging and catering for up to 92 people in the southern area of the oil sands region and can be expanded to accommodate future growth. 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. The new waterfront facility expanded our ability to manufacture, assemble, test and load out larger subsea production and drilling rig equipment thereby expanding our capabilities. The consideration for the facility was approximately $22.9 million in cash, including transaction costs, funded from borrowings under the Company’s existing credit facility.

     Accounting for the Schooner, Christina Lake Lodge and waterfront facility acquisitions has not been finalized and is subject to adjustments during the purchase price allocation period, which is not expected to exceed a period of one year from the respective acquisition dates.

     Changes in the carrying amount of goodwill for the six month period ended June 30, 2008 are as follows (in thousands):

		Balance as of				Acquisitions				Foreign currency				Balance as of
		January 1,				and				translation and				June 30,
		2008				adjustments				other changes				2008
Offshore Products		$	75,813			$	11,027			$	16			$	86,856
Tubular Services			62,863				—				—				62,863
Well Site Services			252,968				690				(1,725	)			251,933
Total		$	391,644			$	11,717			$	(1,709	)		$	401,652

6. DEBT

     As of June 30, 2008 and December 31, 2007, long-term debt consisted of the following (in thousands):

		June 30,				December 31,
		2008				2007
		(Unaudited)
U.S. revolving credit facility, with available commitments up to $325 million and with an average interest rate of 4.1% for the six month period ended June 30, 2008		$	191,500			$	214,800
Canadian revolving credit facility, with available commitments up to $175 million and with an average interest rate of 4.6% for the six month period ended June 30, 2008			82,466				89,060
2 3/8% contingent convertible senior subordinated notes due 2025			175,000				175,000
Subordinated unsecured notes payable to sellers of businesses, interest of 6%, maturing in 2008 to 2009			9,000				9,000
Capital lease obligations and other debt			10,929				3,960
Total debt			468,895				491,820
Less: current maturities			(179,930	)			(4,718	)
Total long-term debt		$	288,965			$	487,102

     As of June 30, 2008, we have classified the $175.0 million principal amount of our 2 3/8% Notes as a current liability because certain contingent conversion thresholds based on the Company’s stock price were met at that date

and, as a result, note holders could present their notes for conversion during the quarter following the June 30, 2008 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 common stock during the prescribed measurement periods. As of June 30, 2008, the recent trading prices of the 2 3/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. The trading price for the 2 3/8% Notes is dependent on current market conditions, the length of time until the first put / call date of the 2 3/8% Notes and general market liquidity, among other factors. Based on recent trading patterns of the 2 3/8% Notes, we do not currently expect any significant amount of the 2 3/8% Notes to convert over the next twelve months. 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 will change 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 will be 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 effect of the new rules on our 2 3/8% Notes is that the equity component will be classified as part of stockholders’ equity on our balance sheet and the value of the equity component will be treated as an original issue discount for purposes of accounting for the debt component of the 2 3/8% Notes. Higher non-cash interest expense will result by recognizing the accretion of the discounted carrying value of the debt component of the 2 3/8% Notes as interest expense over the estimated life of the 2 3/8% Notes using an effective interest rate method of amortization. However, there will be no effect on our cash interest payments. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application. The Company is currently evaluating the impact of this FSP; however, the impact of this accounting change is expected to have a significant effect on previously reported and future non-cash interest expense associated with the 2 3/8% Notes.

     In the first quarter of 2008, we entered into a 21 year capital lease arrangement totaling $8.3 million for the use of a building by our offshore products segment. Annual payments under the capital lease agreement will total approximately $0.7 million.

7. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING:

     Comprehensive income for the three and six months ended June 30, 2008 and 2007 was as follows (in thousands):

		THREE MONTHS								SIX MONTHS
		ENDED JUNE 30,								ENDED JUNE 30,
		2008				2007				2008				2007
Comprehensive income:
Net income		$	60,163			$	52,233			$	126,630			$	104,694
Other comprehensive income:
Cumulative translation adjustment			4,037				20,582				(8,459	)			23,644
Unrealized gain on marketable securities (see Note 11)			1,804				—				1,804				—
Total comprehensive income		$	66,004			$	72,815			$	119,975			$	128,338

Shares of common stock outstanding — January 1, 2008			49,392,106
Shares issued upon exercise of stock options and vesting of stock awards			448,074
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury			(15,806	)
Shares of common stock outstanding — June 30, 2008			49,824,374

8. STOCK BASED COMPENSATION

     During the first six months of 2008, we granted restricted stock awards totaling 267,172 shares valued at $11.6 million. A total of 191,750 of these awards vest in four equal annual installments, 58,750 of these awards vest in two annual installments and the remaining 16,672 awards vest after one year. A total of 561,750 stock options were awarded in the first six months of 2008 with an average exercise price of $37.05 and a six year term that will vest in annual 25% increments over the next four years.

     Stock based compensation pre-tax expense recognized in the six month periods ended June 30, 2008 and June 30, 2007 totaled $5.1 million and $3.7 million, or $0.07 and $0.05 per diluted share after tax, respectively. Stock based compensation pre-tax expense recognized in the three month periods ended June 30, 2008 and June 30, 2007 totaled $2.6 million and $1.8 million, or $0.03 and $0.02 per diluted share after tax, respectively. At June 30, 2008, $25.0 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized. The total fair value of restricted stock awards that vested during the six months ended June 30, 2008 was $4.5 million.

9. INCOME TAXES

     The Company’s income tax provision for the three and six months ended June 30, 2008 totaled $30.9 million, or 33.9%, of pretax income and $63.2 million, or 33.3%, of pretax income, respectively, compared to $27.1 million, or 34.1%, of pretax income for the three months ended June 30, 2007 and $54.2 million, or 34.1%, of pretax income for the six months ended June 30, 2007. Our effective tax rate was lower in the six months ended June 30, 2008 compared to the Federal statutory rate of 35% primarily due to lower tax rates applicable to foreign income partially offset by state taxes.

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 our Canadian business related to the provision of work force accommodations, catering and logistics services are seasonal with significant activity occurring in the peak winter drilling season.

     Financial information by business segment for each of the three and six months ended June 30, 2008 and 2007 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, 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				23,177
Total		$	631,364			$	25,689			$	91,020			$	74,861			$	2,097,384

		Revenues from				Depreciation
		unaffiliated				and				Operating				Capital
		customers				amortization				income (loss)				expenditures				Total assets
Three months ended June 30, 2007
Well Site Services -
Accommodations		$	61,864			$	4,923			$	13,152			$	38,250			$	368,004
Rental tools			50,842				5,123				14,131				9,430				275,880
Drilling and other (1)			36,752				2,892				11,816				11,885				164,801
Total Well Site Services			149,458				12,938				39,099				59,565				808,685
Offshore Products			135,437				2,795				24,207				3,165				419,688
Tubular Services			214,413				331				10,710				760				388,286
Corporate and Eliminations			—				49				(5,535	)			165				27,247
Total		$	499,308			$	16,113			$	68,481			$	63,655			$	1,643,906

		Revenues from				Depreciation				Operating
		unaffiliated				and				income				Capital
		customers				amortization				(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				23,177
Total		$	1,232,611			$	48,417			$	192,358			$	135,706			$	2,097,384

		Revenues from				Depreciation				Operating
		unaffiliated				and				income				Capital
		customers				amortization				(loss)				expenditures				Total assets
Six months ended June 30, 2007
Well Site Services -
Accommodations		$	155,417			$	8,750			$	48,144			$	55,893			$	368,004
Rental tools			104,481				9,863				31,613				17,854				275,880
Drilling and other (1)			67,669				5,543				21,810				19,275				164,801
Total Well Site Services			327,567				24,156				101,567				93,022				808,685
Offshore Products			254,477				5,625				41,815				6,409				419,688
Tubular Services			397,780				654				18,444				894				388,286
Corporate and Eliminations			—				97				(10,454	)			231				27,247
Total		$	979,824			$	30,532			$	151,372			$	100,556			$	1,643,906

11. INVESTMENT IN BOOTS & COOTS

     The Company sold an aggregate total of 6,133,275 shares of Boots & Coots International Well Control, Inc. (Boots & Coots) stock that it owned in a series of transactions during May and June of 2008. The sale of Boots & Coots stock resulted in net proceeds of $14.0 million and a net after tax gain of $1.8 million, or approximately $0.03 per diluted share, recorded in the second quarter of 2008. After the sale of Boots & Coots shares by the Company, our ownership interest in Boots & Coots was reduced to approximately 7%. As a result of this decreased ownership percentage, we have reconsidered the method of accounting utilized for this investment in an unconsolidated affiliate and concluded that we should discontinue the use of the equity method of accounting since we no longer have the ability to significantly influence Boots & Coots. We have, therefore, begun to account for the remaining investment in Boots & Coots common stock (5.4 million shares) as an available for sale security as defined in Statement of Financial Accounting Standards (“SFAS”) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” effective June 30, 2008. In accordance with SFAS No. 115, the carrying value of the remaining shares owned by the Company was adjusted to fair value at June 30, 2008 through an unrealized after tax holding gain in the amount of $1.8 million recorded as other comprehensive income. The carrying value of the Company’s remaining investment in Boots & Coots common stock and a note receivable are $12.8 million and $21.2 million, respectively, as of June 30, 2008 and are included in other non-current assets on the balance sheet.

     In April 2007, the Company sold, pursuant to a registration statement filed by Boots & Coots, 14,950,000 shares of Boots & Coots stock that it owned for net proceeds of $29.4 million and, as a result, we recognized a net after tax gain of $8.4 million, or approximately $0.17 per diluted share in the second quarter of 2007.

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 Form 10-K Annual Report for the year ended December 31, 2007 filed with the Securities and Exchange Commission on February 22, 2008. 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 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 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 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 (for example, deepwater wells usually require higher priced seamless alloy tubulars) 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 Texas, New Mexico, 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 and well site services segments are 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,
		2008				2007				2008				2007
U.S. Land			1,797				1,680				1,755				1,665
U.S. Offshore			67				77				62				80
Total U.S.			1,864				1,757				1,817				1,745
Canada (1)			169				139				338				336
Total North America			2,033				1,896				2,155				2,081

     The average North American rig count for the six months ended June 30, 2008 increased by 74 Rigs, or 3.6%, compared to the six months ended June 30, 2007.

     Our well site services segment results for the first half of 2008 benefited from capital spending, which aggregated $253 million in the twelve months ended June 30, 2008 in that segment and included $44 million invested in our drilling services business for the construction of three new rigs and other capital additions, $64 million in our rental tools business and $145 million invested in our accommodations business, primarily in support of oil sands developments in Canada. In addition, well site services benefited from the acquisitions of two rental tool companies for aggregate consideration of $112 million in the third quarter of 2007 and, to a lesser degree, the acquisition of an accommodations lodge in the oil sands region of Canada for aggregate consideration of $6.9 million in the first quarter of 2008.

     During the first six months of 2008, the results generated by our Canadian workforce accommodations, catering and logistics operations benefited from the strengthening of the Canadian currency. In the first six months of 2008, the Canadian dollar was valued at an average exchange rate of U.S. $0.99 compared to U.S. $0.88 for the first six months of 2007, an increase of 12.5%. The Canadian dollar to U.S. dollar exchange rate averaged $0.99 in the second quarter of 2008 compared to $0.91 in the second quarter of 2007, an increase of 8.8%.

     Oil prices have been volatile recently, increasing to record levels and then declining subsequent to June 30, 2008. Oil prices do, however, remain at levels significantly above those in the prior year. In addition, natural gas prices have also increased significantly during the last year, but have declined subsequent to June 30, 2008. Higher energy prices increase current cash flow available to oil and gas companies and create additional incentives for expanded exploration and production related activities. However, high oil and gas prices could lead to slower economic growth and increased conservation efforts, thereby decreasing cash flows of oil and gas companies and lessening incentive to expend capital to find and develop oil and gas. Management estimates that approximately 55% to 60% of the Company’s revenues are dependent on North American natural gas drilling and completion activity with a significant amount of such revenues being derived from lower margin OCTG sales. As such, we estimate that our profitability is fairly evenly balanced between oil driven activity and natural gas driven activity. Our customers have increased their spending and commitments for deepwater offshore exploration and development which has benefited our offshore products segment. Our customers have also announced significant levels of expenditures for oil sands related projects in Canada, benefiting our well site services segment. We currently expect continued growth in activity for our accommodations business in the oil sands region as labor needs in the region continue to increase. We continue to focus on expansion opportunities and execution initiatives in these high growth markets supporting deepwater development and Canadian oil sands spending.

     The major U.S. mills increased OCTG prices in the first half of 2008 because of changes in OCTG demand and raw material and other cost increases. In addition, there is limited supply of certain categories of OCTG as a result of decreased OCTG inventory and increased demand. With the tightness in OCTG supply and recently announced mill price increases and surcharges, our tubular services margins have increased significantly in the second quarter of 2008 and, based on current activity levels, we expect our tubular services segment to generate continued strong margins and profits during the remainder of 2008.

     There can be no assurance that these trends will continue; and there is a risk that lower energy prices or the expectation of lower energy prices for sustained periods could negatively impact drilling and completion activity

and, correspondingly, reduce oil and gas expenditures. Such a decline would be adverse to our business. In addition, particularly 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.

Consolidated Results of Operations (in millions)

		THREE MONTHS ENDED																SIX MONTHS ENDED
		June 30,																June 30,
										Variance																Variance
										2008 vs. 2007																2008 vs. 2007
		2008				2007				$				%				2008				2007				$				%
Revenues
Well Site Services -
Accommodations		$	80.9			$	61.9			$	19.0				31	%		$	227.1			$	155.4			$	71.7				46	%
Rental Tools			84.6				50.8				33.8				67	%			167.1				104.5				62.6				60	%
Drilling and Other			44.4				36.8				7.6				21	%			81.2				67.6				13.6				20	%
Total Well Site Services			209.9				149.5				60.4				40	%			475.4				327.5				147.9				45	%
Offshore Products			139.9				135.4				4.5				3	%			266.8				254.5				12.3				5	%
Tubular Services			281.6				214.4				67.2				31	%			490.4				397.8				92.6				23	%
Total		$	631.4			$	499.3			$	132.1				26	%		$	1,232.6			$	979.8			$	252.8				26	%
Cost of sales
Well Site Services -
Accommodations		$	48.6			$	38.5			$	10.1				26	%		$	128.2			$	88.2			$	40.0				45	%
Rental Tools			50.3				26.1				24.2				93	%			98.4				51.5				46.9				91	%
Drilling and Other			27.9				21.5				6.4				30	%			53.9				39.0				14.9				38	%
Total Well Site Services			126.8				86.1				40.7				47	%			280.5				178.7				101.8				57	%
Offshore Products			102.7				99.9				2.8				3	%			198.1				190.9				7.2				4	%
Tubular Services			248.9				200.7				48.2				24	%			444.9				372.9				72.0				19	%
Total		$	478.4			$	386.7			$	91.7				24	%		$	923.5			$	742.5			$	181.0				24	%
Gross margin
Well Site Services -
Accommodations		$	32.3			$	23.4			$	8.9				38	%		$	98.9			$	67.2			$	31.7				47	%
Rental Tools			34.3				24.7				9.6				39	%			68.7				53.0				15.7				30	%
Drilling and Other			16.5				15.3				1.2				8	%			27.3				28.6				(1.3	)			(5	%)
Total Well Site Services			83.1				63.4				19.7				31	%			194.9				148.8				46.1				31	%
Offshore Products			37.2				35.5				1.7				5	%			68.7				63.6				5.1				8	%
Tubular Services			32.7				13.7				19.0				139	%			45.5				24.9				20.6				83	%
Total		$	153.0			$	112.6			$	40.4				36	%		$	309.1			$	237.3			$	71.8				30	%
Gross margin as a percent of revenues
Well Site Services -
Accommodations			40	%			38	%											44	%			43	%
Rental Tools			41	%			49	%											41	%			51	%
Drilling and Other			37	%			42	%											34	%			42	%
Total Well Site Services			40	%			42	%											41	%			45	%
Offshore Products			27	%			26	%											26	%			25	%
Tubular Services			12	%			6	%											9	%			6	%
Total			24	%			23	%											25	%			24	%

THREE MONTHS ENDED JUNE 30, 2008 COMPARED TO THREE MONTHS ENDED JUNE 30, 2007

     We reported net income for the quarter ended June 30, 2008 of $60.2 million, or $1.14 per diluted share. These results compare to $52.2 million, or $1.03 per diluted share, reported for the quarter ended June 30, 2007. Net income for the second quarter of 2008 included an after tax gain of $1.8 million, or approximately $0.03 per diluted share, on the sale of 6.13 million shares of Boots & Coots International Well Control, Inc. (Boots & Coots) common stock. Net income for the second quarter of 2007 included an after tax gain of $8.4 million, or $0.17 per diluted share, on the sale of 14.95 million shares of Boots & Coots common stock. See Note 11 to the Unaudited Consolidated Condensed Financial Statements in this quarterly report on Form 10-Q.

     Revenues. Consolidated revenues increased $132.1 million, or 26%, in the second quarter of 2008 compared to the second quarter of 2007.

     Our well site services revenues increased $60.4 million, or 40%, in the second quarter of 2008 compared to the second quarter of 2007. Our accommodations business reported revenues in the second quarter of 2008 that were $19.0 million, or 31%, above the second quarter of 2007 primarily because of the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada and the strengthening of the Canadian dollar versus the U.S. dollar. Our rental tool revenues increased $33.8 million, or 67%, substantially due to contributions from two acquisitions completed in the third quarter of 2007. Our drilling and other revenues increased $7.6 million, or 21%, in the second quarter of 2008 compared to the second quarter of 2007 primarily as a result of four newly constructed rigs placed into service since the second quarter of 2007.

     Our offshore products revenues increased $4.5 million, or 3%, in the second quarter of 2008 compared to the second quarter of 2007 due to increased activity in support of deepwater development activities and new build or refurbished rigs and vessels.

     Tubular services revenues increased $67.2 million, or 31%, in the second quarter of 2008 compared to the second quarter of 2007 as a result of a 22% increase in tons shipped and an 8% increase in average selling prices per ton due to a tight OCTG supply demand balance caused by higher drilling activity and lower overall industry inventory levels.

     Cost of Sales. Our consolidated cost of sales increased $91.7 million, or 24%, in the second quarter of 2008 compared to the second quarter of 2007 primarily as a result of increases at well site services of $40.7 million, or 47%, and at tubular services of $48.2 million, or 24%. Our overall gross margin as a percent of revenues was relatively constant at 24% in the second quarter of 2008 compared to 23% in the second quarter of 2007.

     Our well site services gross margin as a percent of revenue declined from 42% in the second quarter of 2007 to 40% in the second quarter of 2008. Accommodations cost of sales increased as a result of increased activity. Our accommodations gross margin as a percent of revenues increased from 38% last year to 40% this year primarily as a result of capacity additions and economies of scale in our major oil sands lodges. Our rental tools cost of sales increased $24.2 million, or 93%, in the second quarter of 2008 compared to the second quarter of 2007 substantially due to the two acquisitions completed in the third quarter of 2007. The rental tool gross margin as a percent of revenues declined due to the mix of lower margins typically earned in the rental tool businesses acquired in the third quarter of 2007 coupled with certain project delays which reduced utilization and fixed cost absorption.

     Our drilling services cost of sales increased $6.4 million, or 30%, in the second quarter of 2008 compared to the second quarter of 2007 primarily as a result of an increase in the number of rigs that we operate. However, our gross margin as a percent of revenue decreased from 42% last year to 37% this year as a result of increased wages paid to our employees and the impact of cost increases for repairs, supplies and other rig operating expenses.

     Our offshore products cost of sales increased approximately in line with the increase in offshore products revenues resulting in no significant change in the gross margin percentage for that segment.

     Tubular services cost of sales increased due to higher tonnage shipped and pricing from the OCTG suppliers. Our tubular services gross margin as a percentage of revenues increased from 6% in the second quarter of 2007 to

12% in the second quarter of 2008 due to industry increases in OCTG prices during the quarter coupled with limited supplies available.

     Selling, General and Administrative Expenses. SG&A increased $7.8 million, or 27.5%, in the second quarter of 2008 compared to the second quarter of 2007 due primarily to SG&A expense associated with two acquisitions made in the third quarter of 2007, increased salaries, wages and benefits and an increase in head count. SG&A was 5.7% of revenues in both the second quarter of 2008 and 2007.

     Depreciation and Amortization. Depreciation and amortization expense increased $9.6 million, or 59%, in the second quarter of 2008 compared to the same period in 2007 due primarily to capital expenditures made during the previous twelve months and to the two rental tool acquisitions closed in the third quarter of 2007.

     Operating Income. Consolidated operating income increased $22.5 million, or 33%, in the second quarter of 2008 compared to the second quarter of 2007 primarily as a result of an increase at tubular services of $18.0 million, or 168%.

     Gain on Sale of Investment. We reported gains on the sales of investment of $2.7 million and $12.8 million in the three months ended June 30, 2008 and the three months ended June 30, 2007, respectively. In both periods, the sales related to our investment in Boots & Coots common stock and the larger gain in 2007 was primarily attributable to the larger number of shares sold in 2007.

     Interest Expense and Interest Income. Net interest expense increased by $0.7 million, or 24%, in the second quarter of 2008 compared to the second quarter of 2007 due to higher debt levels. The weighted average interest rate on the Company’s revolving credit facility was 3.8% in the second quarter of 2008 compared to 6.2% in the second quarter of 2007.

     Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is $0.5 million higher in the second quarter of 2008 than in the second quarter of 2007.

     Income Tax Expense. Our income tax provision for the second quarter of 2008 totaled $30.9 million, or 33.9% of pretax income, compared to $27.1 million, or 34.1% of pretax income, for the second quarter of 2007. Our tax rate was lower in the second quarter of 2008 than the comparable period in 2007 primarily due to lower tax rates applicable to foreign income.

SIX MONTHS ENDED JUNE 30, 2008 COMPARED TO SIX MONTHS ENDED JUNE 30, 2007

     We reported net income for the six months ended June 30, 2008 of $126.6 million, or $2.45 per diluted share. These results compare to $104.7 million, or $2.08 per diluted share, reported for the six months ended June 30, 2007. Net income for the first half of 2008 included an after tax gain of $1.8 million, or approximately $0.03 per diluted share, on the sale of 6.13 million shares of Boots & Coots common stock (See Note 11 to the Unaudited Consolidated Condensed Financial Statements in this quarterly report on Form 10-Q.) Net income for the first half of 2007 included an after tax gain of $8.4 million, or $0.17 per diluted share, on the sale of 14.95 million shares of Boots & Coots common stock.

     Revenues. Consolidated revenues increased $252.8 million, or 26%, in the first half of 2008 compared to the first half of 2007.

     Our well site services revenues increased $147.9 million, or 45%, in the first half of 2008 compared to the first half of 2007. Our accommodations business reported revenues in the first half of 2008 that were $71.7 million, or 46%, above the first half of 2007 primarily because of the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada and the strengthening of the Canadian dollar versus the U.S. dollar. Our rental tool revenues increased $62.6 million, or 60%, substantially as a result of two acquisitions completed in the third quarter of 2007. Our drilling and other revenues increased $13.6 million, or 20%, in the first half of 2008 compared to the first half of 2007 primarily as a result of three newly constructed rigs placed into service since the first half of 2007.

     Our offshore products revenues increased $12.3 million, or 5%, in the first half of 2008 compared to the first half of 2007 due to increased activity in support of deepwater development activities and new build or refurbished rigs and vessels.

     Tubular services revenues increased $92.6 million, or 23%, in the first half of 2008 compared to the first half of 2007 as a result of a 23% increase in tons shipped. Our average OCTG selling prices for the first half of 2008 did not increase compared to the first half of 2007.

     Cost of Sales. Our consolidated cost of sales increased $181.0 million, or 24%, in the first half of 2008 compared to the first half of 2007 primarily as a result of increases at well site services of $101.8 million, or 57%, and at tubular services of $72.0 million, or 19%. Our overall gross margin as a percent of revenues was relatively constant at 25% in the first half of 2008 compared to 24% in the first half of 2007.

     Our well site services gross margin as a percent of revenue declined from 45% in the first half of 2007 to 41% in the first half of 2008. Accommodations cost of sales increased consistent with increased activity. Our accommodations gross margin as a percent of revenues increased from 43% last year to 44% this year primarily as a result of capacity additions and economies of scale in our major oil sands lodges. Our rental tools cost of sales increased $46.9 million, or 91%, in the first half of 2008 compared to the first half of 2007 substantially due to the two acquisitions completed in the third quarter of 2007. The rental tool gross margin as a percent of revenues declined due to the mix of lower margins typically earned in the rental tool businesses acquired in the third quarter of 2007 coupled with certain project delays which reduced utilization and fixed cost absorption.

     Our drilling services cost of sales increased $14.9 million, or 38%, in the first half of 2008 compared to the first half of 2007 as a result of an increase in the number of rigs that we operate; however, our gross margin as a percent of revenue decreased from 42% last year to 34% this year as a result of increased wages paid to our employees and the impact of cost increases for repairs, supplies and other rig operating expenses.

     Our offshore products cost of sales increased approximately in line with the increase in offshore products revenues resulting in no significant change in the gross margin percentage for that segment.

     Tubular services cost of sales increased as a result of higher tonnage shipped. Our tubular services gross margin as a percentage of revenues increased from 6% in the first half of 2007 to 9% in the first half of 2008 due to favorable market trends.

     Selling, General and Administrative Expenses. SG&A increased $12.5 million, or 22.6%, in the first half of 2008 compared to the first half of 2007 due primarily to SG&A expense associated with two acquisitions made in the third quarter of 2007, increased salaries, wages and benefits and an increase in headcount. SG&A was 5.5% of revenues in the six months ended June 30, 2008 compared to 5.7% of revenues in the six months ended June 30, 2007.

     Depreciation and Amortization. Depreciation and amortization expense increased $17.9 million, or 59%, in the first half of 2008 compared to the same period in 2007 due primarily to capital expenditures made during the previous twelve months and to the two rental tool acquisitions closed in the third quarter of 2007.

     Operating Income. Consolidated operating income increased $41.0 million, or 27%, in the first half of 2008 compared to the first half of 2007 primarily as a result of increases at well site services of $19.3 million, or 19%, and at tubular services of $19.8 million, or 108%.

     Gain on Sale of Investment. We reported gains on the sales of investment of $2.7 million and $12.8 million in the six months ended June 30, 2008 and the six months ended June 30, 2007, respectively. In both periods, the sales related to our investment in Boots & Coots common stock and the larger gain in 2007 was primarily attributable to the larger number of shares sold in 2007.

     Interest Expense and Interest Income. Net interest expense increased by $1.1 million, or 16%, in the first half of 2008 compared to the first half of 2007 due to higher debt levels. The weighted average interest rate on the Company’s revolving credit facility was 4.3% in the first half of 2008 compared to 6.1% in the first half of 2007.

     Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is $1.4 million higher in the first half of 2008 than in the first half of 2007.

     Income Tax Expense. Our income tax provision for the first half of 2008 totaled $63.2 million, or 33.3% of pretax income, compared to $54.2 million, or 34.1% of pretax income, for the first half of 2007. Our tax rate was lower in the first half of 2008 than the comparable period in 2007 primarily due to lower tax rates applicable to foreign income.

Liquidity and Capital Resources

     Our primary liquidity needs are to fund capital expenditures, such as expanding our accommodations facilities, expanding and upgrading our manufacturing facilities and equipment, adding drilling rigs and increasing and replacing rental tool assets, funding new product development and general working capital needs. In addition, capital is needed to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our bank facilities and proceeds from our $175 million convertible note offering in 2005.

     Cash totaling $188.0 million was provided by operations during the first half of 2008 compared to cash totaling $121.4 million provided by operations during the first half of 2007. During the first half of 2008, operating cash flow was increased by higher earnings levels and, to a lesser extent, positive working capital changes. During 2007, $2.3 million was utilized to fund working capital associated with our growth, especially in our offshore products segment. These increased working capital needs were partially offset by a reduction in tubular services inventories during the first half of 2007.

     Cash was used in investing activities during the six months ended June 30, 2008 and 2007 in the amount of $153.5 million and $70.3 million, respectively. Capital expenditures, including capitalized interest, totaled $135.7 million and $100.6 million during the six months ended June 30, 2008 and 2007, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment particularly for accommodations investments made in support of Canadian oil sands development.

     In the six months ended June 30, 2008, we spent cash of $29.8 million to acquire Christina Lake Lodge in Northern Alberta, Canada to expand our oil sands capacity in our well site services segment and to acquire a waterfront facility on the Houston ship channel for use in the offshore products segment.

     The cash consideration paid for all of our acquisitions in the period was funded utilizing our existing bank credit facility. Accounting for the acquisitions made since August 1, 2007 has not been finalized and is subject to adjustments during the purchase price allocation period, which is not expected to exceed a period of one year from the respective acquisition dates.

     We currently expect to spend a total of approximately $344 million for capital expenditures during 2008 to expand our Canadian oil sands related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. We expect to fund these capital expenditures with internally generated funds and proceeds from borrowings under our revolving credit facilities.

     Net cash of $19.2 million was used in financing activities during the six months ended June 30, 2008, primarily as a result of debt repayments. A total of $61.1 million was used in financing activities during the six months ended June 30, 2007, primarily as a result of debt repayments and treasury stock purchases, partially offset by proceeds from stock option exercises.

     During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, an additional $50 million was approved and the duration of the program was extended to August 31, 2008. On January 11, 2008, an additional $50.0 million was approved for the repurchase program and the duration of the program was again extended to December 31, 2009. Through June 30, 2008, a total of $80.6 million of our stock (2,769,932 shares), has been repurchased under this program, leaving a total of up to approximately $69.4 million remaining available under the program.

     On December 13, 2007, we entered into an Incremental Assumption Agreement (the “Agreement”) with the lenders and other parties to our existing credit agreement dated as of October 30, 2003 (the “Credit Agreement”) in order to exercise the accordion feature (the “Accordion”) available under the Credit Agreement. The Accordion increased the total commitments under the Credit Agreement from $400 million to $500 million. In connection with the execution of the Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $300,000,000 to U.S. $325,000,000, and the Total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $100,000,000 to U.S. $175,000,000.

     As of June 30, 2008, we had $274.0 million outstanding under the Credit Facility and an additional $17.2 million of outstanding letters of credit, leaving $208.8 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. and the U.K. that provide for an aggregate borrowing capacity of $9.0 million. As of June 30, 2008, we had $1.8 million outstanding under these other facilities and an additional $1.4 million of outstanding letters of credit leaving $5.8 million available to be drawn under these facilities. Our total debt represented 27.7% of the total of debt and stockholders’ equity at June 30, 2008 compared to 31.2% at December 31, 2007 and 26.1% at June 30, 2007.

     As of June 30, 2008, we have classified the $175.0 million principal amount of our 2 3/8% Notes as a current liability because certain contingent conversion thresholds based on the Company’s stock price were met at that date and, as a result, note holders could present their notes for conversion during the quarter following the June 30, 2008 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 common stock during the prescribed measurement periods. As of June 30, 2008, the recent trading prices of the 2 3/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. The trading price for the 2 3/8% Notes is dependent on current market conditions, the length of time until the first put / call date of the 2 3/8% Notes and general market liquidity, among other factors. Based on recent trading patterns of the 2 3/8% Notes, we do not currently expect any significant amount of the 2 3/8% Notes to convert over the next twelve months. 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 will change 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 will be 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 effect of the new rules on our 2 3/8% Notes is that the equity component will be classified as part of stockholders’ equity on our balance sheet and the value of the equity component will be treated as an original issue discount for purposes of accounting for the debt component of the 2 3/8% Notes. Higher non-cash interest expense will result by recognizing the accretion of the discounted carrying value of the debt component of the 2 3/8% Notes as interest expense over the estimated life of the 2 3/8% Notes using an effective interest rate method of amortization. However, there will be no effect on our cash interest payments. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application. The Company is currently evaluating the impact of this FSP; however, the impact of this accounting change is expected to have a significant effect on previously reported and future non-cash interest expense associated with the 2 3/8% Notes.

     We believe that cash 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. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to us at that time due to a variety of events, including, among others, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry. In addition, such additional debt service requirements 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.

Critical Accounting Policies

     In our selection of critical accounting policies, our objective is to properly reflect our financial position and results of operations in each reporting period in a manner that will be understood by those who utilize our financial statements. Often we must use our judgment about uncertainties.

     There are several critical accounting policies that we have put into practice that have an important effect on our reported financial results.

     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 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 litigation, taxes, interest, insurance claims, warranty claims, contract claims and discontinued operations.

     The assessment of impairment on long-lived assets, including goodwill, intangibles and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. The determination of the amount of impairment, which is other than a temporary decline in value, 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 an other than temporary 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 charges.

     We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the period in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.

     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.

     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. 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.

     Since the adoption of SFAS No. 123R, 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 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 “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 and consistent vesting terms, option prices and option lives. Utilizing the Black Scholes 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.

     In accounting for income taxes, we are required by the provisions of FASB Interpretation No. 48, 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.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

     Interest Rate Risk. We have long-term debt and revolving lines of credit that are subject to the risk of loss associated with movements in interest rates. As of June 30, 2008, we had floating rate obligations totaling approximately $275.8 million for amounts borrowed under our revolving credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rate were to increase by 1% from June 30, 2008 levels, our consolidated interest expense would increase by a total of approximately $2.8 million annually.

     Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in currencies other than the U.S. dollar, which is our functional currency or the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks, 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.

ITEM 4. Controls and Procedures

     Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2008 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act, including this Quarterly Report on Form 10-Q, is recorded, processed, summarized and reported within the time periods specified in the Commission rules and forms.

     Changes in Internal Control over Financial Reporting. During the three months ended June 30, 2008, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

     Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2007 (the 2007 Form 10-K) includes a detailed discussion of our risk factors. There have been no significant changes to our risk factors as set forth in our 2007 Form 10-K.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities

Unregistered Sales of Equity Securities and Use of Proceeds

     None

Purchases of Equity Securities by the Issuer and Affiliated Purchases

										Total Number of				Approximate
										Shares Purchased				Dollar Value of Shares
										as Part of the Share				Remaining to be Purchased
		Total Number of				Average Price				Repurchase				Under the Share Repurchase
Period		Shares Purchased				Paid per Share				Program				Program
April 1, 2008 -			—				—				2,769,932			$	69,357,141
April 30, 2008
May 1, 2008 -			—				—				2,769,932			$	69,357,141
May 31, 2008
June 1, 2008 -			—				—				2,769,932			$	69,357,141
June 30, 2008
Total			—				—				2,769,932			$	69,357,141

ITEM 3. Defaults Upon Senior Securities

     None

ITEM 4. Submission of Matters to a Vote of Security Holders

     The Company’s Annual Meeting of Stockholders was held on May 15, 2008 (1) to elect three Class I members of the Board of Directors to serve for three-year terms, (2) to ratify the appointment of Ernst & Young LLP as independent accountants for the year ended December 31, 2008 and (3) to approve the Oil States International, Inc. 2001 Equity Participation Plan, as amended and restated effective as of February 19, 2008.

     The Class I directors elected were Christopher T. Seaver, Douglas E. Swanson and Cindy B. Taylor. The number of affirmative votes and the number of votes withheld for the directors were:

Names		Number of Affirmative Votes				Number Withheld
Christopher T. Seaver			45,693,228				1,577,763
Douglas E. Swanson			45,683,564				1,587,427
Cindy B. Taylor			45,585,226				1,685,765

     Following the annual meeting, Stephen A. Wells, Martin Lambert, S. James Nelson, Mark G. Papa, Gary L. Rosenthal and William T. Van Kleef continued in their terms as directors.

     The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the ratification of the appointment of Ernst & Young LLP were:

Number of Affirmative Votes		Number of Negative Votes				Abstentions
47,087,710			162,269				21,012

     The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the proposal to approve the Oil States International, Inc. 2001 Equity Participation Plan were:

Number of Affirmative Votes		Number of Negative Votes				Abstentions
30,275,861			13,853,108				20,697