Edgar Filing: OIL STATES INTERNATIONAL, INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2008


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

For the transition period from to

Commission file number: 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,

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	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

YES o NO þ

The Registrant had 49,791,150 shares of common stock outstanding and 2,913,792 shares of treasury stock as of October 27, 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 Nine Month Periods Ended September 30, 2008 and 2007		3
Consolidated Balance Sheets – September 30, 2008 (unaudited) and December 31, 2007		4
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 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 – 24

Item 3. Quantitative and Qualitative Disclosures About Market Risk		24

Item 4. Controls and Procedures		24

Part II — OTHER INFORMATION

Item 1. Legal Proceedings		25

Item 1A. Risk Factors		25

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities		25-26

Item 3. Defaults Upon Senior Securities		26

Item 4. Submission of Matters to a Vote of Security Holders		26

Item 5. Other Information		26

Item 6. Exhibits		26

(a) Index of Exhibits		26-27

Signature Page		28

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Amounts)


	THREE MONTHS ENDED						NINE MONTHS ENDED
	SEPTEMBER 30,						SEPTEMBER 30,
	2008			2007			2008			2007
Revenues	$	814,790		$	527,440		$	2,047,401		$	1,507,264

Costs and expenses:
Cost of sales		609,354			403,369			1,532,874			1,145,882
Selling, general and administrative expenses		37,494			30,884			105,577			86,433
Depreciation and amortization expense		27,325			18,788			75,741			49,320
Other operating income		(893	)		(374	)		(659	)		(516	)

		673,280			452,667			1,713,533			1,281,119

Operating income		141,510			74,773			333,868			226,145

Interest expense		(4,129	)		(4,217	)		(13,917	)		(12,798	)
Interest income		940			890			2,756			2,599
Equity in earnings of unconsolidated affiliates		431			753			3,167			2,043
Gain on sale of investment		3,452			—			6,160			12,774
Other income/(expense)		(555	)		243			(591	)		595

Income before income taxes		141,649			72,442			331,443			231,358
Income tax expense		(52,594	)		(21,964	)		(115,758	)		(76,186	)

Net income	$	89,055		$	50,478		$	215,685		$	155,172


Net income per share:
Basic	$	1.79		$	1.02		$	4.35		$	3.14
Diluted	$	1.70		$	0.97		$	4.15		$	3.05

Weighted average number of common shares outstanding:
Basic		49,811			49,661			49,622			49,423
Diluted		52,322			51,822			51,949			50,883

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands)


	SEPTEMBER 30,			DECEMBER 31,
	2008			2007
	(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents	$	55,621		$	30,592
Accounts receivable, net		502,807			450,153
Inventories, net		463,086			349,347
Prepaid expenses and other current assets		13,475			35,575

Total current assets		1,034,989			865,667

Property, plant, and equipment, net		723,626			586,910
Goodwill, net		399,151			391,644
Investments in unconsolidated affiliates		6,255			24,778
Other non-current assets		56,940			60,627

Total assets	$	2,220,961		$	1,929,626


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	179,941		$	4,718
Accounts payable and accrued liabilities		347,450			239,119
Income taxes		24,392			43
Deferred revenue		83,585			60,910
Other current liabilities		1,220			121

Total current liabilities		636,588			304,911

Long-term debt		236,574			487,102
Deferred income taxes		52,966			40,550
Other liabilities		14,293			12,236

Total liabilities		940,421			844,799

Stockholders’ equity:
Common stock		526			522
Additional paid-in capital		422,044			402,091
Retained earnings		906,398			690,713
Accumulated other comprehensive income		37,854			73,036
Treasury stock		(86,282	)		(81,535	)

Total stockholders’ equity		1,280,540			1,084,827

Total liabilities and stockholders’ equity	$	2,220,961		$	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)


	NINE MONTHS
	ENDED SEPTEMBER 30,
	2008			2007
Cash flows from operating activities:
Net income	$	215,685		$	155,172
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		75,741			49,320
Deferred income tax provision		12,543			5,053
Excess tax benefits from share-based payment arrangements		(3,367	)		(8,116	)
Equity in earnings of unconsolidated subsidiaries, net of dividends		(2,914	)		(2,043	)
Non-cash compensation charge		7,968			5,872
Gain on sale of investment		(6,160	)		(12,774	)
Gain on disposal of assets		(442	)		(1,454	)
Other, net		2,229			214
Changes in working capital		4,476			25,095

Net cash flows provided by operating activities		305,759			216,339

Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		(29,835	)		(102,159	)
Capital expenditures		(206,731	)		(172,068	)
Proceeds from sale of investment		27,381			29,354
Other, net		3,103			2,004

Net cash flows used in investing activities		(206,082	)		(242,869	)

Cash flows from financing activities:
Revolving credit borrowings (repayments)		(73,188	)		24,219
Debt repayments		(4,816	)		(6,918	)
Issuance of common stock		8,628			10,601
Purchase of treasury stock		(4,026	)		(12,211	)
Excess tax benefits from share-based payment arrangements		3,367			8,116
Other, net		(905	)		(431	)

Net cash flows provided by (used in) financing activities		(70,940	)		23,376

Effect of exchange rate changes on cash		(3,664	)		4,450

Net increase in cash and cash equivalents from continuing operations		25,073			1,296
Net cash used in discontinued operations – operating activities		(44	)		(491	)
Cash and cash equivalents, beginning of period		30,592			28,396


Cash and cash equivalents, end of period	$	55,621		$	29,201


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

Borrowings and assumption of liabilities for business and asset acquisitions and related intangibles		—			9,000

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 (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, 2007.

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 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 statements 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. The Company has chosen not to adopt the elective provisions of SFAS 159 for its existing financial instruments.

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 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 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. In addition to a reduction of debt balances and an increase to shareholders’ equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense of approximately $3 million, $5 million, $6 million and $6 million for 2005, 2006, 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense of approximately $7 million, $7 million, $8 million and $4 million for 2009, 2010, 2011 and 2012, respectively.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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


	SEPTEMBER 30,			DECEMBER 31,
	2008			2007
Accounts receivable, net:
Trade	$	396,770		$	353,716
Unbilled revenue		106,427			97,579
Other		2,366			2,487
Allowance for doubtful accounts		(2,756	)		(3,629	)

	$	502,807		$	450,153


	SEPTEMBER 30,			DECEMBER 31,
	2008			2007
Inventories, net:
Tubular goods	$	276,927		$	191,374
Other finished goods and purchased products		69,182			61,306
Work in process		55,647			56,479
Raw materials		68,982			47,737

Total inventories		470,738			356,896
Inventory reserves		(7,652	)		(7,549	)

	$	463,086		$	349,347


	ESTIMATED	SEPTEMBER 30,			DECEMBER 31,
	USEFUL LIFE	2008			2007
Property, plant and equipment, net:
Land		$	20,352		$	12,665
Buildings and leasehold improvements	2-50 years		136,643			107,954
Machinery and equipment	2-29 years		255,685			220,049
Accommodations assets	10-15 years		323,659			276,182
Rental tools	4-10 years		133,501			108,968
Office furniture and equipment	1-10 years		26,222			23,659
Vehicles	2-10 years		67,461			52,508
Construction in progress			70,954			43,046


Total property, plant and equipment			1,034,477			845,031
Less: Accumulated depreciation			(310,851	)		(258,121	)

		$	723,626		$	586,910


	SEPTEMBER 30,		DECEMBER 31,
	2008		2007
Accounts payable and accrued liabilities:
Trade accounts payable	$	282,426	$	186,357
Accrued compensation		31,520		27,156
Accrued insurance		6,866		7,386
Accrued taxes, other than income taxes		10,533		3,733
Reserves related to discontinued operations		2,795		2,839
Other		13,310		11,648

	$	347,450	$	239,119

4. EARNINGS PER SHARE

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


	THREE MONTHS ENDED				NINE MONTHS ENDED
	SEPTEMBER 30,				SEPTEMBER 30,
	2008		2007		2008		2007
Basic earnings per share:
Net income	$	89,055	$	50,478	$	215,685	$	155,172

Weighted average number of shares outstanding		49,811		49,661		49,622		49,423

Basic earnings per share	$	1.79	$	1.02	$	4.35	$	3.14

Diluted earnings per share:
Net income	$	89,055	$	50,478	$	215,685	$	155,172

Weighted average number of shares outstanding		49,811		49,661		49,622		49,423
Effect of dilutive securities:
Options on common stock		490		649		509		659
2 3/8% Convertible Senior Subordinated Notes		1,900		1,421		1,694		721
Restricted stock awards and other		121		91		124		80

Total shares and dilutive securities		52,322		51,822		51,949		50,883

Diluted earnings per share	$	1.70	$	0.97	$	4.15	$	3.05

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 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 nine month period ended September 30, 2008 are as follows (in thousands):


	Balance as of		Acquisitions		Foreign currency			Balance as of
	January 1,		and		translation and			September 30,
	2008		adjustments		other changes			2008
Offshore Products	$	75,813	$	11,027	$	(700	)	$	86,140
Tubular Services		62,863		—		—			62,863
Well Site Services		252,968		1,232		(4,052	)		250,148

Total	$	391,644	$	12,259	$	(4,752	)	$	399,151

6. DEBT

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


	September 30,			December 31,
	2008			2007
	(Unaudited)
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 3.9% for the nine month period ended September 30, 2008	$	142,300		$	214,800
Canadian revolving credit facility which matures on December 5, 2011, with available commitments up to $175 million and with an average interest rate of 4.5% for the nine month period ended September 30, 2008		83,970			89,060
23/8% 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 and 2009		4,500			9,000
Capital lease obligations and other debt		10,745			3,960

Total debt		416,515			491,820
Less: current maturities		(179,941	)		(4,718	)

Total long-term debt	$	236,574		$	487,102

As of September 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 September 30, 2008 measurement date. If a note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they would receive cash up to $1,000 for each 2 3/8% note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% notes of 31.496 multiplied by the Company's average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. Assuming all note holders presented their 2 3/8% Notes for conversion on October 1, 2008, the theoretical amount due all 2 3/8% note holders would be $132.2 million in cash. Subsequent to September 30, 2008, the Company's common stock has traded at a lower price range. Assuming a range of common stock average prices of $17.00 to $25.00, all 2 3/8% note holders would receive aggregate cash proceeds ranging from $93.7 million to $137.8 million. 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 September 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 in July 2012 of the 2 3/8% Notes and general market liquidity, among other factors. 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. In addition to a reduction of debt balances and an increase to stockholders’ equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of approximately $3 million, $5 million, $6 million and $6 million for 2005, 2006, 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense, net of amounts expected to be capitalized, of approximately $7 million, $7 million, $8 million and $4 million for 2009, 2010, 2011 and 2012, respectively.

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.

At September 30, 2008, the Company had approximately $55.6 million of cash and cash equivalents. In addition, at September 30, 2008, $257.7 million of the Company’s $500 million U.S. and Canadian revolving credit facility was available for future financing needs.

7. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING:

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


	THREE MONTHS					NINE MONTHS
	ENDED SEPTEMBER 30,					ENDED SEPTEMBER 30,
	2008			2007		2008			2007
Comprehensive income:
Net income	$	89,055		$	50,478	$	215,685		$	155,172
Other comprehensive income:
Cumulative translation adjustment		(26,722	)		18,538		(35,182	)		42,182
Unrealized gain on marketable securities, net of tax (see Note 11)		365			—		2,170			—
Reclassification adjustment, net of tax (see Note 11)		(2,170	)		—		(2,170	)		—

Total comprehensive income	$	60,528		$	69,016	$	180,503		$	197,354


Shares of common stock outstanding – January 1, 2008										49,392,106

Shares issued upon exercise of stock options and vesting of stock awards										496,382
Repurchase of shares- transferred to treasury										(100,000	)
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury										(17,338	)

Shares of common stock outstanding – September 30, 2008										49,771,150

8. STOCK BASED COMPENSATION

During the first nine months of 2008, we granted restricted stock awards totaling 271,235 shares valued at $11.6 million. A total of 195,450 of these awards vest in four equal annual installments, 58,750 of these awards vest in two annual installments, 16,672 awards vest after one year and the remaining 363 awards vested immediately. A total of 565,250 stock options were awarded in the first nine months of 2008 with an average exercise price of $37.19 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 nine month periods ended September 30, 2008 and September 30, 2007 totaled $8.0 million and $5.9 million, or $0.10 and $0.08 per diluted share after tax, respectively. Stock based compensation pre-tax expense recognized in the three month periods ended September 30, 2008 and September 30, 2007 totaled $2.8 million and $2.2 million, respectively, or $0.03 per diluted share after tax in both periods. At September 30, 2008, $22.3 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 nine months ended September 30, 2008 was $5.0 million.

9. INCOME TAXES

The Company’s income tax provision for the three and nine months ended September 30, 2008 totaled $52.6 million, or 37.1%, of pretax income and $115.8 million, or 34.9%, of pretax income, respectively, compared to $22.0 million, or 30.3%, of pretax income for the three months ended September 30, 2007 and $76.2 million, or 32.9%, of pretax income for the nine months ended September 30, 2007. The higher effective tax rate was primarily due to a greater proportion of U.S. income compared to lower taxed foreign income and the recognition of additional U.S. taxable income related to our Canadian operations.

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 nine months ended September 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 September 30, 2008
Well Site Services -
Accommodations	$	105,380	$	9,686	$	23,695		$	29,233	$	525,780
Rental tools		91,699		8,921		21,003			22,931		467,983
Drilling and other (1)		52,086		5,272		14,833			14,005		200,161

Total Well Site Services		249,165		23,879		59,531			66,169		1,193,924
Offshore Products		120,008		3,033		20,273			2,749		499,239
Tubular Services		445,617		340		68,261			1,022		513,520
Corporate and Eliminations		—		73		(6,555	)		1,085		14,278

Total	$	814,790	$	27,325	$	141,510		$	71,025	$	2,220,961


	Revenues from		Depreciation
	unaffiliated		and		Operating			Capital
	customers		amortization		income (loss)			expenditures		Total assets
Three months ended September 30, 2007
Well Site Services -
Accommodations	$	65,894	$	5,972	$	16,147		$	43,444	$	421,698
Rental tools		73,602		6,580		19,825			11,594		412,073
Drilling and other (1)		40,216		3,215		12,908			10,808		172,993

Total Well Site Services		179,712		15,767		48,880			65,846		1,006,764
Offshore Products		132,124		2,612		22,074			4,156		441,767
Tubular Services		215,604		351		9,529			1,455		379,462
Corporate and Eliminations		—		58		(5,710	)		56		33,798

Total	$	527,440	$	18,788	$	74,773		$	71,513	$	1,861,791


	Revenues from		Depreciation		Operating
	unaffiliated		and		income			Capital
	customers		amortization		(loss)			expenditures		Total assets
Nine months ended September 30, 2008
Well Site Services -
Accommodations	$	332,518	$	26,075	$	93,761		$	98,602	$	525,780
Rental tools		258,767		25,793		54,926			57,882		467,983
Drilling and other (1)		133,316		14,119		31,679			34,429		200,161

Total Well Site Services		724,601		65,987		180,366			190,913		1,193,924
Offshore Products		386,780		8,545		66,656			12,629		499,239
Tubular Services		936,020		1,004		106,533			1,941		513,520
Corporate and Eliminations		—		205		(19,687	)		1,248		14,278

Total	$	2,047,401	$	75,741	$	333,868		$	206,731	$	2,220,961


	Revenues from		Depreciation		Operating
	unaffiliated		and		income			Capital
	customers		amortization		(loss)			expenditures		Total assets
Nine months ended September 30, 2007
Well Site Services -
Accommodations	$	221,311	$	14,722	$	64,291		$	99,337	$	421,698
Rental tools		178,082		16,443		51,437			29,449		412,073
Drilling and other (1)		107,886		8,758		34,719			30,082		172,993
Total Well Site Services		—		—		—			—		—

Offshore Products		507,279		39,923		150,447			158,868		1,006,764
Tubular Services		386,601		8,237		63,889			10,565		441,767
Corporate and Eliminations		613,384		1,005		27,973			2,349		379,462
Total		—		155		(16,164	)		286		33,798

	$	1,507,264	$	49,320	$	226,145		$	172,068	$	1,861,791


(1)		We have classified our equity interest in Boots & Coots and the notes receivable acquired in the transaction in which we sold our workover services business to Boots & Coots as “Drilling and other.”

11. INVESTMENT IN BOOTS & COOTS

The Company sold an aggregate total of 11,512,137 shares of Boots & Coots International Well Control, Inc. (Boots & Coots) stock representing the remaining shares that it owned in a series of transactions during May, June and August of 2008. The sale of Boots & Coots stock resulted in net proceeds of $13.4 million and a net after tax gain of $2.2 million, or approximately $0.04 per diluted share, and net proceeds of $27.4 million and a net after tax gain of $4.0 million, or approximately $0.08 per diluted share, recorded in the three and nine months ended September 30, 2008, respectively. After June 30, 2008, our ownership interest in Boots & Coots was approximately 7%. As a result of this decreased ownership percentage, we reconsidered the method of accounting utilized for this investment and concluded that we should discontinue the use of the equity method of accounting since we no longer had the ability to significantly influence Boots & Coots. We, therefore, began to account for the remaining investment in Boots & Coots common stock (5.4 million shares at June 30, 2008) 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 sale of the remaining 5.4 million shares in August of 2008 resulted in the reclassification of the $2.2 million unrealized after tax gain from accumulated other comprehensive income into earnings for the three months ended September 30, 2008. The carrying value of the Company’s note receivable due from Boots & Coots (on September 2, 2010) is $21.2 million as of September 30, 2008 and is 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 during the nine months ended September 30, 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 oil and natural gas exploration and development activities. 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. Demand for our products and services by our customers is highly sensitive to current and expected future 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 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				Nine Months Ended
	September 30,		September 30,		September 30,		September 30,
	2008		2007		2008		2007
U.S. Land		1,909		1,716		1,806		1,682
U.S. Offshore		69		72		65		77

Total U.S		1,978		1,788		1,871		1,759
Canada (1)		432		348		369		340

Total North America		2,410		2,136		2,240		2,099


(1)		Canadian rig count typically increases during the peak winter drilling season (December through March).

The average North American rig count for the nine months ended September 30, 2008 increased by 141 rigs, or 6.7%, compared to the nine months ended September 30, 2007.

Our well site services segment results for the first nine months of 2008 benefited from capital spending, which aggregated $254 million in the twelve months ended September 30, 2008 in that segment and included $47 million invested in our drilling services business, $76 million in our rental tools business and $131 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 nine 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 nine months of 2008, the Canadian dollar was valued at an average exchange rate of U.S. $0.98 compared to U.S. $0.91 for the first nine months of 2007, an increase of 7.7%. The Canadian dollar to U.S. dollar exchange rate averaged $0.96 in the third quarter of both 2008 and 2007. Since September 30, 2008, the value of the Canadian dollar has weakened to an average exchange rate of $0.86 and hit a low of $0.77. Continued weakening of the Canadian dollar would negatively impact the translation of future earnings generated from our Canadian subsidiary.

The major U.S. mills increased OCTG prices in the first nine months of 2008 because of high product demand, overall tight supplies and also in response to raw material and other cost increases. With the tightness in OCTG supply coupled with mill price increases and surcharges, our tubular services margins increased significantly in the second and third quarters of 2008. However, steel prices are declining on a global basis and we would expect that declining steel prices could have an adverse impact on OCTG pricing and on our future margins.

The current global financial crisis, which has contributed, among other things, to significant reductions in available capital and liquidity from banks and other providers of credit, has raised concerns that the worldwide economy may enter into a prolonged recessionary period, which may be severe. Oil prices have been highly volatile recently, increasing to record levels in the second quarter of 2008 and then declining thereafter. Falling oil prices prompted the Organization of Petroleum Exporting Countries (OPEC) to announce in September 2008 that it would cut oil production quotas by one half million barrels per day in an attempt to stabilize falling oil prices and in October 2008 OPEC announced an additional 1.5 million barrel decrease in oil production quotas. U.S. inventory levels for natural gas have risen higher than expected during the 2008 summer injection season and are expected to approach full capacity at the end of the season as was the case in 2007. The uncertainty surrounding future economic activity levels and the tightening of credit availability may result in decreased activity levels for some or all of our businesses in future quarters. Spending cuts have been announced by some of our customers as a result of reduced oil and gas price expectations and U.S. North American active rig count forecasts have been reduced recently. In addition, exploration and production expenditures will be constrained to the extent exploration and production companies are limited in their access to the credit markets as a result of disruption in, or a more conservative lending stance by, the lending markets. There is significant uncertainty about future activity levels and the impact on our businesses.

We are currently assessing the effect that the global financial crisis might have 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 determine the effect on our Company. 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 continue to focus on industry inventory levels, future drilling and completion activity and OCTG prices.

Consolidated Results of Operations (in millions)


	THREE MONTHS ENDED												NINE MONTHS ENDED
	September 30,												September 30,
							Variance												Variance
							2008 vs. 2007												2008 vs. 2007
	2008			2007			$			%			2008			2007			$			%
Revenues
Well Site Services -
Accommodations	$	105.4		$	65.9		$	39.5			60	%	$	332.5		$	221.3		$	111.2			50	%
Rental Tools		91.7			73.6			18.1			25	%		258.8			178.1			80.7			45	%
Drilling and Other		52.1			40.2			11.9			30	%		133.3			107.9			25.4			24	%

Total Well Site Services		249.2			179.7			69.5			39	%		724.6			507.3			217.3			43	%
Offshore Products		120.0			132.1			(12.1	)		(9	%)		386.8			386.6			0.2			0	%
Tubular Services		445.6			215.6			230.0			107	%		936.0			613.4			322.6			53	%

Total	$	814.8		$	527.4		$	287.4			54	%	$	2,047.4		$	1,507.3		$	540.1			36	%


Cost of sales
Well Site Services -
Accommodations	$	65.3		$	37.2		$	28.1			76	%	$	193.4		$	125.5		$	67.9			54	%
Rental Tools		52.8			39.0			13.8			35	%		151.2			90.5			60.7			67	%
Drilling and Other		31.2			23.9			7.3			31	%		85.2			62.8			22.4			36	%

Total Well Site Services		149.3			100.1			49.2			49	%		429.8			278.8			151.0			54	%
Offshore Products		88.5			100.6			(12.1	)		(12	%)		286.6			291.5			(4.9	)		(2	%)
Tubular Services		371.6			202.7			168.9			83	%		816.5			575.6			240.9			42	%

Total	$	609.4		$	403.4		$	206.0			51	%	$	1,532.9		$	1,145.9		$	387.0			34	%


Gross margin
Well Site Services -
Accommodations	$	40.1		$	28.7		$	11.4			40	%	$	139.1		$	95.8		$	43.3			45	%
Rental Tools		38.9			34.6			4.3			12	%		107.6			87.6			20.0			23	%
Drilling and Other		20.9			16.3			4.6			28	%		48.1			45.1			3.0			7	%

Total Well Site Services		99.9			79.6			20.3			26	%		294.8			228.5			66.3			29	%
Offshore Products		31.5			31.5			0.0			0	%		100.2			95.1			5.1			5	%
Tubular Services		74.0			12.9			61.1			474	%		119.5			37.8			81.7			216	%

Total	$	205.4		$	124.0		$	81.4			66	%	$	514.5		$	361.4		$	153.1			42	%

Gross margin as a percent of revenues
Well Site Services -
Accommodations		38	%		44	%								42	%		43	%
Rental Tools		42	%		47	%								42	%		49	%
Drilling and Other		40	%		41	%								36	%		42	%
Total Well Site Services		40	%		44	%								41	%		45	%
Offshore Products		26	%		24	%								26	%		25	%
Tubular Services		17	%		6	%								13	%		6	%
Total		25	%		24	%								25	%		24	%

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

We reported net income for the quarter ended September 30, 2008 of $89.1 million, or $1.70 per diluted share. These results compare to $50.5 million, or $0.97 per diluted share, reported for the quarter ended September 30, 2007. Net income for the third quarter of 2008 included an after tax gain of $2.2 million, or approximately $0.04 per diluted share, on the sale of our remaining 5.38 million shares of Boots & Coots International Well Control, Inc. (Boots & Coots) common stock. See Note 11 to the Unaudited Consolidated Condensed Financial Statements in this quarterly report on Form 10-Q.

In September 2008, Hurricanes Ike and Gustav hit the Texas and Louisiana coasts. The negative impact of the storms to our operations included some minor facility damage, downtime in our offshore products manufacturing facilities and rental tool locations in the impacted coastal areas. We also experienced a reduction in rental tool demand during the period. The U.S. Minerals Management Service reported that the damage caused by the two storms to the energy infrastructure in the U.S. Gulf of Mexico and along the U. S. Gulf Coast was not as extensive as the damage caused by Hurricanes Katrina and Rita in 2005. However, repair activity resulting from these hurricanes should benefit our offshore products and U.S. Gulf accommodations businesses in future quarters.

Revenues. Consolidated revenues increased $287.4 million, or 54%, in the third quarter of 2008 compared to the third quarter of 2007.

Our well site services revenues increased $69.5 million, or 39%, in the third quarter of 2008 compared to the third quarter of 2007. Our accommodations business reported revenues in the third quarter of 2008 that were $39.5 million, or 60%, above the third quarter of 2007 primarily because of the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada and the accounting recognition of $13.8 million of deferred revenue, which was deferred due to contract terms that precluded revenue recognition, associated with a camp delivered to a customer in 2005. Our rental tool revenues increased $18.1 million, or 25%, primarily due to capital additions made since the third quarter of 2007, increased rebillable services from third-parties, contributions from an acquisition completed in August of 2007, geographic expansion of our rental tool operations and increased rental tool utilization. Our drilling and other revenues increased $11.9 million, or 30%, in the third quarter of 2008 compared to the third quarter of 2007 primarily as a result of three newly constructed rigs placed into service since the third quarter of 2007 and higher dayrates.

Our offshore products revenues decreased $12.1 million, or 9%, in the third quarter of 2008 compared to the third quarter of 2007 due to shipment delays and downtime at our manufacturing facilities in Houston, Texas and Houma, Louisiana related to Hurricanes Ike and Gustav.

Tubular services revenues increased $230.0 million, or 107%, in the third quarter of 2008 compared to the third quarter of 2007 as a result of a 33% increase in tons shipped and a 56% 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 $206.0 million, or 51%, in the third quarter of 2008 compared to the third quarter of 2007 primarily as a result of increases at well site services of $49.2 million, or 49%, and at tubular services of $168.9 million, or 83%. Our overall gross margin as a percent of revenues was relatively constant at 25% in the third quarter of 2008 compared to 24% in the third quarter of 2007.

Our well site services gross margin as a percent of revenue declined from 44% in the third quarter of 2007 to 40% in the third quarter of 2008. Our accommodations gross margin as a percent of revenues decreased from 44% in the third quarter of 2007 to 38% in the third quarter of 2008 primarily as a result of the recognition of previously deferred revenue and costs, due to contract terms which precluded revenue recognition, for a significant manufacturing project shipped and invoiced in 2005 with a relatively low gross margin. Our rental tools cost of sales increased $13.8 million, or 35%, in the third quarter of 2008 compared to the third quarter of 2007 primarily due to increased revenues, higher rebillable third-party expenses, increased wages, cost increases for fuel, parts and supplies and an acquisition completed in August of 2007. The rental tool gross margin as a percent of revenues

declined from 47% in the third quarter of 2007 to 42% in the third quarter of 2008 due to a higher proportion of lower margin rebill revenue and the impact of the above mentioned cost increases.

Our drilling and other services cost of sales increased $7.3 million, or 31%, in the third quarter of 2008 compared to the third quarter of 2007 primarily as a result of an increase in the number of rigs that we operate. Our drilling services gross margin as a percent of revenue was relatively constant at 40% in the third quarter of 2008 compared to 41% in the third quarter of 2007.

Our offshore products cost of sales decreased $12.1 million, or 12%, in the third quarter of 2008 compared to the third quarter of 2007 due to decreased revenues. Our offshore products gross margin as a percentage of revenues increased from 24% in the third quarter of 2007 to 26% in the third quarter of 2008 due primarily to increased profitability on bearings and connectors product revenues.

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 third quarter of 2007 to 17% in the third 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 $6.6 million, or 21%, in the third quarter of 2008 compared to the third quarter of 2007 due primarily to increased bonuses and commissions, acquisitions made in August of 2007 and February of 2008 and increased stock compensation expense. SG&A as a percentage of revenues decreased from 5.9% in the third quarter of 2007 to 4.6% during the same period in 2008 due primarily to the increase in our revenues.

Depreciation and Amortization. Depreciation and amortization expense increased $8.5 million, or 45%, in the third quarter of 2008 compared to the same period in 2007 due primarily to capital expenditures made during the previous twelve months.

Operating Income. Consolidated operating income increased $66.7 million, or 89%, in the third quarter of 2008 compared to the third quarter of 2007 primarily as a result of an increase in operating income of our tubular services segment of $58.7 million, or 616%.

Gain on Sale of Investment. We reported gains on the sales of investment of $3.5 million in the three months ended September 30, 2008 related to sales of our remaining shares of Boots & Coots common stock (See Note 11 to the Unaudited Consolidated Condensed Financial Statements in this quarterly report on Form 10-Q).

Interest Expense and Interest Income. Net interest expense decreased by $0.1 million, or 4%, in the third quarter of 2008 compared to the third quarter of 2007 due to lower interest rates under our revolving credit facility partially offset by higher debt levels. The weighted average interest rate on the Company’s revolving credit facility was 3.7% in the third quarter of 2008 compared to 6.1% in the third quarter of 2007.

Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is $0.3 million lower in the third quarter of 2008 than in the third quarter of 2007 primarily due to the discontinuance of the use of equity method of accounting for our investment in Boots & Coots.

Income Tax Expense. Our income tax provision for the third quarter of 2008 totaled $52.6 million, or 37.1% of pretax income, compared to $22.0 million, or 30.3% of pretax income, for the third quarter of 2007. Our tax rate was higher in the third quarter of 2008 than the comparable period in 2007 primarily due to greater proportionate U.S. income compared to our lower taxed Canadian and other foreign income and also due to recognition of additional U.S. taxable income related to our Canadian operations.

NINE MONTHS ENDED SEPTEMBER 30, 2008 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2007

We reported net income for the nine months ended September 30, 2008 of $215.7 million, or $4.15 per diluted share. These results compare to $155.2 million, or $3.05 per diluted share, reported for the nine months ended September 30, 2007. Net income for the first nine months of 2008 included an after tax gain of $4.0 million, or approximately $0.08 per diluted share, on the sale of 11.51 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 nine months 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 $540.1 million, or 36%, in the first nine months of 2008 compared to the first nine months of 2007.

Our well site services revenues increased $217.3 million, or 43%, in the first nine months of 2008 compared to the first nine months of 2007. Our accommodations business reported revenues in the first nine months of 2008 that were $111.2 million, or 50%, above the first nine months 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 $80.7 million, or 45%, in the first nine months of 2008 compared to the first nine months of 2007 primarily as a result of two acquisitions completed in the third quarter of 2007, capital additions made since the third quarter of 2007, geographic expansion of our rental tool operations and increased rental tool utilization. Our drilling and other revenues increased $25.4 million, or 24%, in the first nine months of 2008 compared to the first nine months of 2007 primarily as a result of four newly constructed rigs placed into service since the first nine months of 2007 and higher dayrates.

Our offshore products revenues were essentially flat at $386.8 million in the first nine months of 2008 compared to $386.6 million in the first nine months of 2007 despite the impact of Hurricanes Ike and Gustav.

Tubular services revenues increased $322.6 million, or 53%, in the first nine months of 2008 compared to the first nine months of 2007 as a result of a 26% increase in tons shipped and a 21% 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 $387.0 million, or 34%, in the first nine months of 2008 compared to the first nine months of 2007 primarily as a result of increased cost of sales at tubular services of $240.9 million, or 42%, and at well site services of $151.0 million, or 54%. Our overall gross margin as a percent of revenues was relatively constant at 25% in the first nine months of 2008 compared to 24% in the first nine months of 2007.

Our well site services gross margin as a percent of revenue declined from 45% in the first nine months of 2007 to 41% in the first nine months of 2008. Our accommodations gross margin as a percent of revenues was relatively constant at 42% in the first nine months of 2008 compared to 43% in the first nine months of 2007. Our rental tools cost of sales increased $60.7 million, or 67%, in the first nine months of 2008 compared to the first nine months of 2007 substantially due to the two acquisitions completed in the third quarter of 2007, increased revenues, higher rebillable third-party expenses, increased wages and cost increases for fuel, parts and supplies. The rental tool gross margin as a percent of revenues declined due to a higher proportion of lower margin rebill revenue and the impact of the above mentioned cost increases.

Our drilling services cost of sales increased $22.4 million, or 36%, in the first nine months of 2008 compared to the first nine months 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% in the first nine months of 2007 to 36% this year as a result of increased wages and cost increases for repairs, supplies and other rig operating expenses.

Our offshore products cost of sales were relatively flat in the first nine months of 2008 compared to the same period in 2007 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 and higher pricing charged by the OCTG suppliers. Our tubular services gross margin as a percentage of revenues increased from 6% in the first nine months of 2007 to 13% in the first nine months of 2008 due to these favorable market trends.

Selling, General and Administrative Expenses. SG&A increased $19.1 million, or 22.1%, in the first nine months of 2008 compared to the first nine months of 2007 due primarily to SG&A expense associated with acquisitions made in July and August of 2007 and February of 2008, increased bonuses and stock compensation expense and an increase in headcount. SG&A was 5.2% of revenues in the nine months ended September 30, 2008 compared to 5.7% of revenues in the nine months ended September 30, 2007.

Depreciation and Amortization. Depreciation and amortization expense increased $26.4 million, or 54%, in the first nine months 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 $107.7 million, or 48%, in the first nine months of 2008 compared to the first nine months of 2007 primarily as a result of increases at tubular services of $78.6 million, or 281%, and at well site services of $29.9 million, or 20%.

Gain on Sale of Investment. We reported gains on the sales of investment of $6.2 million and $12.8 million in the nine months ended September 30, 2008 and the nine months ended September 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 (See Note 11 to the Unaudited Consolidated Condensed Financial Statements in this quarterly report on Form 10-Q).

Interest Expense and Interest Income. Net interest expense increased by $1.0 million, or 9%, in the first nine months of 2008 compared to the first nine months of 2007 due to higher debt levels partially offset by lower interest rates. The weighted average interest rate on the Company’s revolving credit facility was 4.1% in the first nine months of 2008 compared to 6.1% in the first nine months of 2007.

Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is $1.1 million higher in the first nine months of 2008 than in the first nine months of 2007 primarily because of increased earnings from our investment in Boots & Coots, prior to the discontinuance of the equity method of accounting on June 30, 2008.

Income Tax Expense. Our income tax provision for the first nine months of 2008 totaled $115.8 million, or 34.9% of pretax income, compared to $76.2 million, or 32.9% of pretax income, for the first nine months of 2007. Our tax rate was higher in the first nine months of 2008 than the comparable period in 2007 primarily due to greater proportionate U.S. income compared to our lower taxed Canadian and other foreign income and also due to recognition of additional U.S. taxable income related to our Canadian operations.

Liquidity and Capital Resources

The recent and unprecedented disruption in the current credit markets has had a significant adverse impact on a number of financial institutions. At this point in time, the Company’s liquidity has not been materially impacted by the current credit environment. The Company is not currently a party to any interest rate swaps, currency hedges or derivative contracts of any type and has no exposure to commercial paper or auction rate securities markets. Management will continue to closely monitor the Company’s liquidity and the overall health of the credit markets. However, management cannot predict with any certainty the impact on the Company of any further disruption in the credit environment.

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. In the past, 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 $305.8 million was provided by operations during the first nine months of 2008 compared to cash totaling $216.3 million provided by operations during the first nine months of 2007. During the first nine months of 2008, operating cash flow benefited from higher earnings levels. During 2007, $25.1 million was provided by working capital changes primarily due to a $52.9 million reduction in tubular services inventories in 2007, partially offset by other working capital increases.

Cash was used in investing activities during the nine months ended September 30, 2008 and 2007 in the amount of $206.1 million and $242.9 million, respectively. Capital expenditures, including capitalized interest, totaled $206.7 million and $172.1 million during the nine months ended September 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 nine months ended September 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. This compares to $102.2 million spent in the nine months ended September 30, 2007 to acquire two rental tool businesses.

The cash consideration paid for all of our acquisitions in the period was funded utilizing our existing bank credit facility.

We currently expect to spend an additional $72 million for capital expenditures during the fourth quarter of 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. Although we are still evaluating the impact on the Company of the current credit crisis and decline in commodity prices, we expect that our capital expenditures in 2009 will be reduced apart from any opportunistic acquisitions or expansion projects. If there is a significant lessening in demand for our products and services as a result of extended declines in the actual and longer term expected price of oil and gas, we may see a further reduction in our own capital expenditures and lesser requirements for working capital, both of which could generate operating cash flow and liquidity compared to the prior period and offset reduced cash generated from operations excluding working capital changes. However, such an environment might also increase the availability of acquisitions which would draw on such liquidity.

Net cash of $70.9 million was used in financing activities during the nine months ended September 30, 2008, primarily as a result of debt repayments. A total of $23.4 million was used in financing activities during the nine months ended September 30, 2007, primarily as a result of revolving credit facility borrowings paid down in 2007 and proceeds from stock option exercises partially offset by treasury stock purchases and other debt repayments.

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 September 30, 2008, a total of $84.5 million of our stock (2,869,932 shares), including $3.9 million (100,000 shares) which were purchased during the three months ended September 30, 2008, had been repurchased under this program, leaving a total of up to approximately $65.5 million remaining available under the program to make share repurchases. We will continue to evaluate future share repurchases in the context of allocating capital among other corporate opportunities including capital expenditures and acquisitions and in the context of current conditions in the credit and capital markets.

On December 13, 2007, we entered into an Incremental Assumption Agreement (Agreement) with the lenders and other parties to our existing credit agreement dated as of October 30, 2003 (Credit Agreement) in order to exercise the accordion feature (Accordion) available under the Credit Agreement and extend maturity to December 5, 2011. 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. We currently have 11 lenders in our Credit Agreement with commitments ranging from $15 million to $102.5 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, the lack of or delay in funding by a significant member of our banking group could negatively affect our liquidity position.

As of September 30, 2008, we had $226.3 million outstanding under the Credit Facility and an additional $16.0 million of outstanding letters of credit, leaving $257.7 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 $8.6 million. As of September 30, 2008, we had $1.7 million outstanding under these other facilities and an additional $1.3 million of outstanding letters of credit leaving $5.7 million available to be drawn under these facilities. Our total debt represented 24.5% of the total of debt and stockholders’ equity at September 30, 2008 compared to 31.2% at December 31, 2007 and 29.1% at September 30, 2007.

As of September 30, 2008, we have classified the $175.0 million principal amount of our 2 3/8% Contingent Convertible Senior Notes (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 September 30, 2008 measurement date. If a note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they would receive cash up to $1,000 for each 2 3/8% note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% notes of 31.496 multiplied by the Company's average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. Assuming all note holders presented their 2 3/8% Notes for conversion on October 1, 2008, the theoretical amount due all 2 3/8% note holders would be $132.2 million in cash. Subsequent to September 30, 2008, the Company's common stock has traded at a lower price range. Assuming a range of common stock average prices of $17.00 to $25.00, all 2 3/8% note holders would receive aggregate cash proceeds ranging from $93.7 million to $137.8 million. 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 September 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 in July 2012 of the 2 3/8% Notes and general market liquidity, among other factors. 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. In addition to a reduction of debt balances and an increase to stockholders’ equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of approximately $3 million, $5 million, $6 million and $6 million for 2005, 2006, 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense, net of amounts expected to be capitalized, of approximately $7 million, $7 million, $8 million and $4 million for 2009, 2010, 2011 and 2012, respectively.

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. We currently believe we could repay all of our outstanding indebtedness by their respective maturity dates using operating cash flow, if required. 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, financial market conditions, general economic conditions and market perceptions of us and our industry. In addition, such additional debt service requirements could be based on higher interest paid and shorter maturities and could impose a significant burden on our results of operations and financial condition,

and the issuance of additional equity securities could result in significant dilution to stockholders.

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 an other than temporary 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 September 30, 2008, we had floating rate obligations totaling approximately $228.0 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. Since the beginning of the third quarter of 2008, we have experienced an increase of approximately 1.5% to 2.0% in short-term interest rates that impact the cost of our borrowing due to increases in LIBOR rates which have occurred despite reductions to the Federal Funds rate. If the floating interest rate were to increase by 1% from September 30, 2008 levels, our consolidated interest expense would increase by a total of approximately $2.3 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 September 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 September 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 except for the additional risk factor below:

Our Business is Subject to a Number of Economic Risks

As widely reported, financial markets in the United States, Europe and Asia have been experiencing extreme disruption in recent months, including, among other things, extreme volatility in security prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others. Governments have taken unprecedented actions intended to address extreme market conditions that include severely restricted credit and declines in real estate values. While, currently, these conditions have not impaired our ability to access credit markets and finance our operations, there can be no assurance that there will not be a further deterioration in financial markets and confidence in major economies. These economic developments affect businesses such as ours in a number of ways. Although our total revenues remained strong for the third quarter of 2008, the current tightening of credit in financial markets adversely affects the ability of customers and suppliers to obtain financing for significant operations and could result in a decrease in or cancellation of orders included in our backlogs, lower demand for our products and services or adversely affect the collectability of receivables. Additionally, the current tightening of credit in financial markets could negatively impact our growth and cost of capital. Our business is also adversely affected when energy demand is lowered due to decreases in the general level of economic activity, such as decreases in business and consumer spending and travel, which results in lower energy prices, and therefore, less oilfield activity and lower demand for our products and services. Strengthening of the rate of exchange for the U.S. Dollar against certain major currencies such as the Euro, the British Pound and the Canadian Dollar and other currencies could also adversely affects our results. We are unable to predict the likely duration and severity of the current disruption in financial markets and adverse economic conditions in the U.S. and other countries or their impact on our Company.

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
July 1, 2008 – July 31, 2008		—		—		2,769,932	$	69,357,141
August 1, 2008 – August 31, 2008		—		—		2,769,932	$	69,357,141
September 1, 2008 - September 30, 2008		100,000		38.97		2,869,932	$	65,459,901	⁽¹⁾
Total		100,000		38.97		2,869,932	$	65,459,901


(1)		On March 2, 2005, we announced a share repurchase program of up to $50,000,000 over a two year period. On August 25, 2006, we announced the authorization of an additional $50,000,000 and the extension of the program to August 31, 2008. On January 11, 2008, an additional $50 million was approved for the repurchase program and the duration of the program was extended to December 31, 2009.

ITEM 3. Defaults Upon Senior Securities

None

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

None

ITEM 5. Other Information

None

ITEM 6. Exhibits

(a) INDEX OF EXHIBITS


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

3.2	—	Second Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 21, 2008).

3.3	—	Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).

4.1	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (File No. 333-43400)).

4.2	—	Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).


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

4.4	—	Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Commission on June 23, 2005).

4.5	—	Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Commission on June 23, 2005).

4.6	—	Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 hereof) (incorporated by reference to Oil States’ Current Reports on Form 8-K filed with the Commission on June 23, 2005 and July 13, 2005).

10.11D	—	Incremental Assumption Agreement, dated as of December 13, 2007, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12D to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007).

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

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

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

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


*		Filed herewith

**		Management contracts or compensatory plans or arrangements

***		Furnished herewith.

SIGNATURES

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

OIL STATES INTERNATIONAL, INC.


Date: October 31, 2008	By	/s/ BRADLEY J. DODSON Bradley J. Dodson
		Vice President, Chief Financial Officer and
		Treasurer (Duly Authorized Officer and Principal
		Financial Officer)

Date: October 31, 2008	By	/s/ ROBERT W. HAMPTON Robert W. Hampton
		Senior Vice President — Accounting and
		Secretary (Duly Authorized Officer and
		Chief Accounting Officer)

Exhibit Index


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

3.2	—	Second Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 21, 2008).

3.3	—	Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).

4.1	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (File No. 333-43400)).

4.2	—	Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001).

4.3	—	First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the Commission on March 13, 2003).

4.4	—	Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Commission on June 23, 2005).

4.5	—	Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Commission on June 23, 2005).

4.6	—	Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 hereof) (incorporated by reference to Oil States’ Current Reports on Form 8-K filed with the Commission on June 23, 2005 and July 13, 2005).

10.11D	—	Incremental Assumption Agreement, dated as of December 13, 2007, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12D to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007).

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

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

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

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


*		Filed herewith

**		Management contracts or compensatory plans or arrangements

***		Furnished herewith.