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, 2005~~March 31, 2006


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 number1-16337

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)		(I.R.S. Employer Identification No.)

Three Allen Center, 333 Clay Street, Suite 4620,		~~77002~~

Houston, Texas		~~(Zip Code)~~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.

YESþ NOo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, ~~(as defined~~or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule ~~12b – 2~~2b-2 of the Exchange ~~Act).~~Act.

~~YES~~Check one: Large Accelerated Filerþ NOAccelerated Filero Non-Accelerated Filero

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

YESo NOþ

The Registrant had ~~49,055,906~~49,523,086 shares of common stock outstanding as of ~~October 24, 2005.~~April 28, 2006.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In Thousands)


	SEPTEMBER 30,			DECEMBER 31,			MARCH 31,			DECEMBER 31,
	2005			2004			2006			2005
	(UNAUDITED)						(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents	$	17,329		$	19,740		$	11,999		$	15,298
Accounts receivable, net		250,867			198,297			302,296			274,070
Inventories, net		334,590			209,825			368,687			360,926
Prepaid expenses and other current assets		4,755			7,322			14,074			13,450

Total current assets		607,541			435,184			697,056			663,744

Property, plant, and equipment, net		290,319			227,343			305,866			310,452
Goodwill, net		340,784			258,046			330,431			339,703
Investments in unconsolidated affiliates								31,730			2,265
Other noncurrent assets		27,349			13,039			47,138			26,708

Total assets	$	1,265,993		$	933,612		$	1,412,221		$	1,342,872


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	179,886		$	159,265		$	197,129		$	214,504
Income taxes		10,084			5,821			27,482			7,023
Current portion of long-term debt		3,937			228			3,566			3,901
Deferred revenue		29,016			25,420			33,243			34,046
Other current liabilities		2,280			2,296			3,814			3,223

Total current liabilities		225,203			193,030			265,234			262,697

Long-term debt		403,038			173,887			406,007			402,109
Deferred income taxes		37,570			28,871			38,936			35,259
Other liabilities		8,713			7,800			8,392			8,823

Total liabilities		674,524			403,588			718,569			708,888

Stockholders’ equity:
Common stock		503			496			507			504
Additional paid-in capital		348,292			338,906			357,581			350,667
Retained earnings		248,628			168,180			342,909			289,993
Accumulated other comprehensive income		24,363			22,759			23,202			23,137
Treasury stock		(30,317	)		(317	)		(30,547	)		(30,317	)

Total stockholders’ equity		591,469			530,024			693,652			633,984

Total liabilities and stockholders’ equity	$	1,265,993		$	933,612		$	1,412,221		$	1,342,872

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)


	NINE MONTHS ENDED SEPTEMBER 30,						THREE MONTHS ENDED MARCH 31,
	2005			2004			2006			2005
Cash flows from operating activities:
Net income	$	80,448		$	43,825		$	52,916		$	25,289
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		33,697			26,477			12,886			10,228
Deferred income tax provision (benefit)		1,101			(2,453	)
Tax benefit of option exercises		2,919			—
Deferred income tax provision								2,788			1,752
Excess tax benefits from share-based payment arrangements								(1,791	)		—
Non-cash gain on sale of workover business								(11,494	)		—
Non-cash compensation charge								1,688			36
Other, net		1,645			1,237			83			2,158
Changes in working capital		(119,536	)		(4,294	)		(38,418	)		(45,595	)

Net cash flows provided by operating activities		274			64,792			18,658			(6,132	)

Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		(146,568	)		(79,455	)		(49	)		(22,606	)
Cash balances of workover business sold								(4,366	)		—
Capital expenditures		(49,445	)		(38,117	)		(26,542	)		(17,147	)
Proceeds from sale of equipment		2,034			3,072			792			501
Other, net		(554	)		(63	)		(30	)		(80	)

Net cash flows used in investing activities		(194,533	)		(114,563	)		(30,195	)		(39,332	)

Cash flows from financing activities:
Revolving credit borrowings		50,673			49,700			5,300			45,148
Contingent convertible notes issued		175,000			—
Bridge loan and other borrowings		25,000			102
Debt repayments		(25,469	)		(774	)		(1,854	)		(113	)
Issuance of common stock		6,112			3,491			3,297			3,165
Payment of financing costs		(6,460	)		(81	)
Purchase of treasury stock		(30,000	)		—
Excess tax benefits from share-based payment arrangements								1,791			—
Other, net		—			(139	)		(101	)		(707	)

Net cash flows provided by financing activities		194,856			52,299			8,433			47,493

Effect of exchange rate changes on cash		(2,455	)		2,192			(178	)		(439	)

Net increase (decrease) in cash and cash equivalents from continuing operations		(1,858	)		4,720			(3,282	)		1,590
Net cash used in discontinued operations		(553	)		(500	)
Net cash used in discontinued operations — operating activities								(17	)		(142	)
Cash and cash equivalents, beginning of period		19,740			19,318			15,298			19,740

Cash and cash equivalents, end of period	$	17,329		$	23,538		$	11,999		$	21,188


Non-cash financing activities: Borrowings for acquisitions	$	6,553		$	4,675
Non cash investing activities:
Receipt of stock and notes for hydraulic workover business in merger transaction, net of unrecognized gain of $9.6 million (See Note 10)							$	50,349		$	—

Non-cash financing activities:
Borrowings for acquisitions							$	—		$	750

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 the Company and its wholly-owned subsidiaries 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 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 year.

Preparation of financial statements in conformity with U.S. generally accepted accounting principles 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 consolidated condensed 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, ~~2004.~~2005.

2. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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


	SEPTEMBER 30,			DECEMBER 31,			MARCH 31,			DECEMBER 31,
	2005			2004			2006			2005
Accounts receivable, net:
Trade	$	212,586		$	177,784		$	266,363		$	236,936
Unbilled revenue		38,904			21,431			35,575			36,789
Other		1,881			605			2,207			2,514
Allowance for doubtful accounts		(2,504	)		(1,523	)		(1,849	)		(2,169	)

	$	250,867		$	198,297		$	302,296		$	274,070

4. EARNINGS PER SHARE (EPS)

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
2005 2004 2005 2004
(In thousands, except per share data)
Basic earnings per share:
Net income $ 30,308 $ 15,513 $ 80,448 $ 43,825

Weighted average number of shares outstanding 48,925 49,409 49,436 49,262

Basic earnings per share $ 0.62 $ 0.31 $ 1.63 $ 0.89

Diluted earnings per share:
Net income $ 30,308 $ 15,513 $ 80,448 $ 43,825

Weighted average number of shares outstanding 48,925 49,409 49,436 49,262
Effect of dilutive securities:
Options on common stock 1,095 621 936 596
Restricted stock 88 31 70 37

Total shares and diluted securities 50,108 50,061 50,442 49,895

Diluted earnings per share $ 0.60 $ 0.31 $ 1.59 $ 0.88

~~Our 2 3/8% contingent convertible notes were not convertible at any time during the periods presented and no shares have been added to our outstanding shares for these notes (See Note 6).~~


	THREE MONTHS ENDED
	MARCH 31,
	2006		2005
	(In thousands, except per share data)
Basic earnings per share:
Net income	$	52,916	$	25,289


Weighted average number of shares outstanding		49,208		49,669


Basic earnings per share	$	1.08	$	0.51


Diluted earnings per share:
Net income	$	52,916	$	25,289


Weighted average number of shares outstanding		49,208		49,669
Effect of dilutive securities:
Options on common stock		1,028		849
2 3/8% Contingent Convertible Notes		724		—
Restricted stock awards and other		62		42


Total shares and dilutive securities		51,022		50,560


Diluted earnings per share	$	1.04	$	0.50

5.4. ACQUISITIONS AND GOODWILL

On February 1, 2005, the Company completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for ~~cash~~total consideration of ~~$21.3~~$22.1 million, including transaction costs, plus a note payable to the former owners of $0.8 million. At the date of acquisition, Elenburg ~~owns~~owned and ~~operates~~operated 7 rigs which ~~provide~~provided shallow land drilling services in Montana, Wyoming, Colorado, and Utah. The Elenburg acquisition allowed the Company to expand its drilling business into different geographic areas. The operations of Elenburg have been included in the drilling services business within the well site services segment.

Effective May 1, 2005 and June 1, 2005 the Company acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, Stinger) for ~~cash~~total consideration of ~~$78.0~~$96.1 million, ~~net of cash acquired and~~ including transaction costs ~~plus~~and a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 2329 locations in the United States, Canada, Central and ~~Canada.~~ South America.

Stinger’s patented equipment is utilized during pressure pumping operations and isolates the customers’ blow-out preventers or wellheads from the pressure and abrasion experienced during the fracturing process of an oil or gas well. In June 2005, the Company completed the acquisition of Stinger’s international operations for additional cash consideration of $6.2 million, net of cash acquired and including transaction costs. The Stinger international operations are conducted primarily in Central and South America. The Stinger acquisition expanded the Company’s rental tool and services capabilities, especially in the pressure pumping market. The operations of Stinger have been included in the rental tools business within the well site services segment.

On June 2, 2005, the Company purchased Phillips Casing and Tubing, L.P. (Phillips) for ~~cash~~total consideration of ~~$31.1~~$31.2 million ~~net of cash acquired and~~ including transaction costs. Phillips distributes oil country tubular goods (OCTG), primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas. The operations of Phillips have been combined with our tubular services segment.

On June 6, 2005, the Company acquired Noble Structures, Inc. (Noble) for ~~cash~~total consideration of ~~$7.9~~$8.7 million, ~~plus~~including transaction costs and a note payable of $0.8 million. The acquisition expanded the Company’s accommodation manufacturing capabilities in Canada in order to meet increased demand for remote site facilities, principally in the oil sands region. The operations of Noble have been combined with our accommodations business within well site services.

~~The cash consideration paid for all of the Company’s acquisitions in the period was initially funded utilizing its existing bank credit facility and a $25 million bridge loan (See Note 6).~~ Accounting for ~~the~~certain acquisitions made ~~in the~~

~~period~~since March 31, 2005 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. ~~The Elenburg, Stinger and Noble acquisitions are included in the Well Site Services segment and the Phillips acquisition is included in the Tubular Services segment.~~

Changes in the carrying amount of goodwill for the ~~nine~~three month period ended ~~September 30, 2005~~March 31, 2006 are as follows (in thousands):

Balance as of Foreign currency Balance as of
January 1, Goodwill translation and September 30,
2005 acquired other changes 2005
Offshore Products $ 75,582 $ 2 $ (518 ) $ 75,066
Tubular Services 51,604 10,239 — 61,843
Drilling services 9,397 14,469 — 23,866
Workover services 9,340 — — 9,340
Rental tools 61,921 56,006 1,257 119,184
Accommodations 50,202 415 868 51,485

Total Wellsite Services 130,860 70,890 2,125 203,875

Total $ 258,046 $ 81,131 $ 1,607 $ 340,784


						Foreign currency			Balance as of
	Balance as of		Goodwill			translation and			March 31,
	January 1, 2006		acquired			other changes			2006
Offshore Products	$	74,922	$	—		$	53		$	74,975
Tubular Services		62,015		173			—			62,188
Wellsite Services		202,766		(55	)		(9,443	) (1)		193,268

Total	$	339,703	$	118		$	(9,390	)	$	330,431


(1)		Effective March 1, 2006, the Company sold its workover services business — See Note 10. A total of $9,340 of goodwill was associated with the workover services business sold.

6.5. DEBT

As of ~~September 30, 2005~~March 31, 2006 and December 31, ~~2004,~~2005, long-term debt consisted of the following (in thousands):

September 30, December 31,
2005 2004
(Unaudited)
US revolving credit facility, with available commitments up to $280 million and with an average interest rate of 4.9% for the three months period ended September 30, 2005 $ 187,100 $ 172,600
Canadian revolving credit facility, with available commitments up to $45 million and with an average interest rate of 4.1% for the three month period ended September 30, 2005 36,173 —
2 3/8% contingent convertible senior notes due 2025 175,000 —
Subordinated unsecured notes payable to sellers of businesses, interest ranging from 5% to 6%, maturing in 2006 and 2007 8,109 1,010
Obligations under capital leases 593 505

Total debt 406,975 174,115
Less: current maturities 3,937 228

Total long-term debt $ 403,038 $ 173,887

On June 15, 2005, the Company sold $125 million aggregate principal amount of 2 3/8% contingent convertible senior notes due 2025 through a placement to qualified institutional buyers pursuant to the SEC’s Rule 144A. The Company granted the initial purchaser of the notes a 30-day option to purchase up to an additional $50 million aggregate principal amount of the notes. This option was exercised in July 2005 and an additional $50 million of the notes were sold at that time.

The notes are senior unsecured obligations of the Company and bear interest at a rate of 2 3/8% per annum. The notes mature on July 1, 2025, and may not be redeemed by the Company prior to July 6, 2012. Holders of the notes may require the Company to repurchase some or all of the notes on July 1, 2012, 2015, and 2020. The notes provide for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were not included in the calculation of diluted earnings per share because the terms of the notes require that the Company’s stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price for at least 20 trading days in a defined period before the notes are convertible. As a result, there would be no conversion allowed under the terms of the notes at September 30, 2005.

The Company utilized $30 million of the net proceeds of the offering on June 15, 2005 to repurchase 1,183,432 shares of its common stock and the remaining portion of the net proceeds to repay a $25.0 million bridge loan and to repay approximately $66.0 million of borrowings under its senior secured credit facility. Net proceeds of the


	March 31,			December 31,
	2006			2005
	(Unaudited)
US revolving credit facility, with available commitments up to $280 million and with an average interest rate of 6.0% for the three month period ended March 31, 2006	$	184,900		$	179,600
Canadian revolving credit facility, with available commitments up to $45 million and with an average interest rate of 5.1% for the three month period ended March 31, 2006		41,984			42,885
2 3/8% contingent convertible senior notes due 2025		175,000			175,000
Subordinated unsecured notes payable to sellers of businesses, interest ranging from 5% to 6%, maturing in 2006 and 2007		6,232			7,493
Capital lease obligations and other notes payable in monthly installments of principal and interest at various interest rates		1,457			1,032

Total debt		409,573			406,010
Less: current maturities		(3,566	)		(3,901	)

Total long-term debt	$	406,007		$	402,109

The table below summarizes stock option activity pursuant to our plans for the three months ended March 31, 2006:


						Weighted-
				Weighted-		Average		Aggregate
				Average		Contractual		Intrinsic Value
	Options			Exercise Price		Life (Years)		(Thousands)
Outstanding at beginning of period		2,694,061		$	13.65
Granted		495,000		$	34.86
Exercised		(293,325	)	$	11.24
Cancelled		(52,500	)	$	16.15

Outstanding at end of period		2,843,236		$	17.55		5.4	$	54,878


Exercisable at end of period		1,317,304		$	11.56		5.5	$	33,321

On February ~~2001, all option grants have been priced at~~15, 2006, we issued stock options for 495,000 shares of our common stock with an exercise price of $34.86 per share. The exercise price is the closing price ~~on the day~~ of grant, vest 25% per year and have a life ranging from six to ten years. Because the exercise price of options granted under the Equity Participation Plan have been equal to the market price of the Company’sour common stock on the date of grant. The options vest in four equal installments on the first, second, third and fourth anniversaries of the date of grant, ~~no compensation expense related to stock options~~and have ~~been recorded. Had compensation expense for its Equity Participation Plan been determined consistent with SFAS No. 123 utilizing the~~a term of six years. The weighted-average fair value ~~method,~~of options granted during the ~~Company’s net income and earnings~~first quarter of 2006 was determined to be $12.77 per share based on the following assumptions.


Risk-free interest rate	4.5	%

Dividend yield	0	%

Expected market price volatility of our common stock	37	%

Expected life of options (years)	4.25

The total intrinsic value of options exercised during the three months ended March 31, 2006 was $7.1 million. Cash received from option exercises during the three months ended March 31, 2006 totaled $3.3 million.

The following tables summarize the range of exercise prices and the weighted average remaining contractual life of the options outstanding and the range of exercise prices for the ~~three and nine months ended September 30, 2005 and 2004, would have been as follows (in thousands, except per share amounts):~~options exercisable at March 31, 2006:


Options Outstanding
				Weighted
Range of				Average Remaining		Weighted Average
Exercise Prices		Outstanding		Contractual Life		Exercise Price
$	6.27 — $9.00		583,683		5.3	$	8.44
$	10.51		8,750		6.4	$	10.51
$	11.49		475,185		6.9	$	11.49
$	11.65 — $13.00		70,000		6.7	$	12.28
$	13.70		554,525		3.9	$	13.70
$	14.31 — $34.86		1,151,093		5.4	$	26.89

			2,843,236

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
2005 2004 2005 2004
Net income as reported $ 30,308 $ 15,513 $ 80,448 $ 43,825
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects (634 ) (604 ) (1,882 ) (1,985 )

Pro forma net income $ 29,674 $ 14,909 $ 78,566 $ 41,840

Net income per share as reported:
Basic $ 0.62 $ 0.31 $ 1.63 $ 0.89
Diluted 0.60 0.31 1.59 0.88
Pro forma net income per share as if fair value method had been applied to all awards:
Basic $ 0.61 $ 0.30 $ 1.59 $ 0.85
Diluted 0.59 0.30 1.56 0.84


		Options Exercisable
Range of				Weighted Average
Exercise Prices		Exercisable		Exercise Price
$	6.27 — $9.00		583,683	$	8.44
$	10.51		5,313	$	10.51
$	11.49		312,873	$	11.49
$	11.65 — $13.00		42,500	$	12.17
$	13.70		222,775	$	13.70
$	14.31 — $34.86		150,160	$	20.47

			1,317,304

During the first quarter of 2006, we granted 39,750 restricted stock awards valued at a total of $1.4 million. A total of 24,250 of these awards vest in four equal annual installments, 2,000 of these awards vest in two equal annual installments and the remaining 13,500 awards vest after one year.

Impact of Adoption of SFAS 123R.Stock based compensation expense recognized under SFAS 123R in the three months ended March 31, 2006 totaled $1.7 million, or $0.02 per basic and diluted share. For the three months ended March 31, 2005, our stock compensation expense related primarily to restricted stock awards and totaled $36,000. At March 31, 2006, $13.3 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.

The following table illustrates the pro forma effect on net income and income per share for the three months ended March 31, 2005 had we applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (in thousands except per share amounts):


	Three months ended
	March 31, 2005
Net income, as reported	$	25,289
Deduct total stock-based employee compensation expense determined under SFAS 123, net of tax		(600	)

Pro forma net income	$	24,689

Net income per share as reported:
Basic	$	0.51
Diluted	$	0.50
Pro Forma net income per share as if fair value method had been applied to all awards:
Basic	$	0.50
Diluted	$	0.49

On November 10, 2005, the FASB issued FASB Staff Position No. FAS 123(R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.” We have elected to adopt the alternative transition method provided for in this FASB Staff Position for calculating the tax effects of share-based compensation pursuant to FAS 123R. The alternative transition method includes a simplified method to establish the beginning balance of the additional paid-in capital pool related to the tax effects of employee share-based compensation, which is available to absorb tax deficiencies recognized subsequent to the adoption of FAS 123R.

9.8. INCOME TAXES

Our primary deferred tax asset, which totaled approximately $12.5 million at December 31, 2004, is related to $35.8 million in available federal net operating loss carryforwards, or NOLs, as of that date. A valuation allowance of approximately $5.1 million was provided against the deferred tax asset associated with our NOLs at December 31, 2004. The NOLs will expire in varying amounts during the years 2010 through 2020 if they are not first used to offset taxable income generated by the Company. The Company’s ability to utilize a significant portion of the NOLs is currently limited under Section 382 of the Internal Revenue Code (Code) due to a change of control that occurred during 1995. A successive change in control was triggered in 2003 pursuant to Section 382 of the Code; however it did not significantly change the Company’s NOL utilization expectations.

The Company’s income tax provision for the three months ended ~~September 30, 2005~~March 31, 2006 totaled ~~$17.7~~$34.2 million, or ~~36.9%~~39.3%, of pretax income compared to ~~$11.0~~$14.8 million, or ~~41.4%~~36.9% of pretax income, for the three months ended ~~September 30, 2004. Our~~March 31, 2005. The effective ~~tax~~ rate was higher in the ~~third~~ quarter ~~of 2004~~ended March 31, 2006 because of a ~~change in the estimated 2004 annual~~higher effective tax rate ~~during that quarter.~~applicable to the gain recognized on the sale of our workover services business.

The ~~Company’s~~Company has not provided United States income taxes and foreign withholding taxes on a cumulative total of approximately $213.0 million of undistributed earnings of certain non-United States subsidiaries assumed to be

indefinitely invested outside the United States. Should the Company decide to repatriate such foreign earnings, the Company would have to adjust the income tax provision for the nine months ended September 30, 2005 totaled $47.0 million, or 36.9% of pretax income, compared to $20.5 million, or 31.9% of pretax income, for the nine months ended September 30, 2004. Our effective tax rate was lower in the ~~first nine months of 2004 as a result of~~period management determined that the ~~recognition of a $5.4 million income tax benefit in~~earnings will no longer be indefinitely invested outside the ~~first quarter related to the partial reversal of the valuation allowance applied against NOLs which were recorded as of the prior year end.~~

Based upon the loss limitation provisions of Section 382 of the Code, we expect to utilize approximately $8 million of our NOLs to offset taxable income generated by the Company during the tax year ended December 31, 2005.United States.

~~10.~~9. 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: Offshore Products, Tubular Services, and Well Site 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 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. We sold our workover services business, effective March 1, 2006, in exchange for an equity interest in Boots & Coots International Well Control Inc. (AMEX:WEL) and a note receivable — See Note 10.

Financial information by industry segment for each of the three ~~and nine~~ month periods ended ~~September 30,~~March 31, 2006 and 2005 ~~and 2004~~ is summarized in the following table (in thousands):


	Revenues from		Depreciation		Operating							Revenues from		Depreciation		Operating
	unaffiliated		and		income			Capital				unaffiliated		and		income			Capital
	customers		amortization		(loss)			expenditures		Total assets		customers		amortization		(loss)			expenditures		Total assets
Three months ended September 30, 2005
Three months ended March 31, 2006
Well Site Services -
Accommodations												$	104,589	$	3,578	$	25,359		$	11,536	$	296,005
Rental tools													49,588		4,005		16,893			5,542		253,423
Drilling services													28,018		1,679		11,781			6,332		82,679
Workover services (1)													8,544		725		1,789			263		50,921

Total Well Site Services													190,739		9,987		55,822			23,673		683,028
Offshore Products	$	64,345	$	2,453	$	5,885		$	1,211	$	282,145		78,272		2,609		10,065			2,560		305,159
Tubular Services		188,258		274		19,801			66		373,668		227,220		263		17,818			286		404,077
Well Site Services —
Drilling services		24,005		1,489		7,282			3,779		76,987
Workover services		10,349		1,006		1,108			782		51,715
Rental tools		40,010		3,702		10,861			5,122		237,309
Accommodations		67,173		3,319		9,479			4,459		231,428

Total Well Site Services		141,537		9,516		28,730			14,142		597,439
Corporate and Eliminations		—		10		(3,150	)		159		12,741		—		27		(4,502	)		23		19,957

Total	$	394,140	$	12,253	$	51,266		$	15,578	$	1,265,993	$	496,231	$	12,886	$	79,203		$	26,542	$	1,412,221


Three months ended September 30, 2004
Three months ended March 31, 2005
Well Site Services -
Accommodations												$	83,194	$	2,810	$	17,092		$	5,240	$	231,776
Rental tools													19,057		2,655		3,263			4,470		125,686
Drilling services													16,854		1,201		4,173			3,467		67,182
Workover services													8,490		936		74			532		47,187

Total Well Site Services													127,595		7,602		24,602			13,709		471,831
Offshore Products	$	55,268	$	2,310	$	2,678		$	1,315	$	270,485		66,491		2,432		5,268			3,241		287,131
Tubular Services		116,872		183		14,123			93		209,128		137,860		172		15,145			71		233,803
Well Site Services —
Drilling services		12,751		822		3,522			1,406		33,376
Workover services		8,143		970		41			522		47,669
Rental tools		16,165		2,484		2,348			3,875		120,259
Accommodations		42,339		2,379		7,468			10,070		179,867

Total Well Site Services		79,398		6,655		13,379			15,873		381,171
Corporate and Eliminations		—		13		(2,269	)		—		8,754		—		22		(2,801	)		126		8,400

Total	$	251,538	$	9,161	$	27,911		$	17,281	$	869,538	$	331,946	$	10,228	$	42,214		$	17,147	$	1,001,165

10. WORKOVER SERVICES BUSINESS TRANSACTION

Effective March 1, 2006 we completed a transaction to combine our workover services business with Boots & Coots International Well Control, Inc. (Amex: WEL) (Boots & Coots) in exchange for 26.5 million shares of Boots & Coots common stock valued at $1.45 per share at closing and senior subordinated promissory notes totaling $21.6 million.

As a result of the closing of the transaction, Oil States owns 45.6% of Boots & Coots. The senior subordinated promissory notes received in the transaction bear a fixed annual interest rate of 10% and mature four and one half years from the closing of the transaction. In connection with this transaction, we also entered into a Registration Rights Agreement requiring Boots & Coots to file a shelf registration statement within 30 days for all of the Boots & Coots shares we received in the transaction and also allowing us certain “piggyback” registration rights for these shares. The transaction terms also allowed us to nominate two additional members to Boots & Coots’ existing five-member Board of Directors and provided us the right to nominate an additional member to the Boots & Coots Board of Directors.

The transaction resulted in a non-cash pretax gain of $21.1 million of which $9.6 million has not been recognized in accordance with the guidance in Emerging Issues Task Force Issue No. 01-2 covering gain recognition involving non-cash transactions and retained equity interests. After the gain adjustment and income taxes, the transaction had a $5.9 million, or $0.12 per diluted share, impact on net income and earnings per share, respectively. We will account for our investment in Boots & Coots utilizing the equity method of accounting. Differences between Boots & Coots total book equity after the transaction, net to the Company’s interest, and the carrying value of our investment in Boots & Coots are principally attributable to the reversal of a portion of the gain on the sale of the workover services business and to goodwill.

11. COMMITMENTS AND CONTINGENCIES

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 that purchased 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.

On February 18, 2005, ~~the Company~~we announced that itwe had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of ~~its~~our subsidiaries (the “Subsidiary”) to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in ~~its~~our previously reported fourth quarter 2004 results. ~~The Company~~We and independent counsel retained by ~~the Company’s~~our audit committee conducted separate investigations consisting of interviews and ana thorough examination of the facts and circumstances in this matter. ~~The Company~~We voluntarily reported the results of ~~its~~our investigation to the Securities and Exchange Commission (the “SEC”) and ~~has~~ fully cooperated with ~~additional~~ requests for information received from the SEC. ~~The Company understands that the SEC has recently completed its informal investigation of this matter.~~ On October 31, 2005, ~~the Company’s~~our counsel received a “Wells Notice” from the staff of the SEC indicating that the staff ~~has~~ made a preliminary decision to recommend that the SEC bring a civil action against the Company alleging violations of provisions of the Securities and Exchange Act of 1934 relating to the maintenance of books, records and internal accounting controls and procedures as set forth in Sections 13(b)(2)(A) and (B) of the Act. The ~~alleged violations related to this over billings matter. A “Wells Notice” is not~~Company reached a ~~formal allegation or proof of wrongdoing. Recipients of “Wells Notices” have the opportunity to respond to~~settlement agreement with the SEC ~~staff before the staff makes a formal recommendation~~ on ~~whether any action should be brought~~April 27, 2006. The Company consented to an Order by the ~~SEC. The~~SEC (Order), without admitting or denying the findings in the Order, that required the Company ~~is engaged in discussions with the staff~~to cease and desist from committing or causing violations of the ~~SEC regarding~~“books and records” and “internal control provisions” of the ~~“Wells Notice”~~laws of the Securities and ~~is currently evaluating its planned response~~Exchange Act of 1934. The settlement did not require the Company to ~~this matter.~~pay a monetary penalty.

This quarterly report onForm 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 1. Business” including the risk factors discussed therein 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 ourForm 10-K Annual Report for the year ended December 31, ~~2004~~2005 filed with the Securities and Exchange Commission on March 2, ~~2005~~2006 and Item 2., which follows. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future.

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.

~~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. There have been no changes in these policies since the filing of our Annual Report on Form 10-K for the year ended December 31, 2004.

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, fines, penalties, interest, warranty claims, contract claims and discontinued operations.

The determination of impairment on long-lived assets, including goodwill, is conducted when indicators of impairment are present. If such indicators were present, the determination of the amount of impairment would be based on 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, 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. We record a valuation allowance

to reduce our deferred tax assets to the amount that is more likely than not to be realized. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, in the event we were to determine that we would be able to realize our deferred tax assets in the future in excess of our net recorded amount, an adjustment to the deferred tax asset would increase income in the period such determination was made. Likewise, should we determine that we would not likely be able to realize all or part of our net deferred tax asset in the future, an adjustment to the deferred tax asset would be charged to expense in the period such determination was made. See also “Note 9 – Income Taxes” and “Tax Matters” herein.

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.

Overview

We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices than our offshore products segment. 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, repairs and upgrades of existing drilling rigs and construction of new drilling rigs. In this segment, we are particularly influenced by deepwater drilling and production activities, which are driven largely by our customers’ outlook for longer-term future oil prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales of tubular products and services depend upon the overall level of drilling activity, the types of wells being drilled and the level of oil country tubular goods (OCTG) pricing. Historically, tubular services gross margins expand during periods of rising OCTG prices and contract during periods of decreasing OCTG prices. In our well site services business segment, we provide shallow land drilling services, ~~hydraulic well control services,~~ work force accommodations, catering and logistics 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 workover services are conducted in the U.S., South America, Africa, and the Middle East and are dependent upon the level of workover activity in those areas.~~ Our rental tools and services depend primarily upon the level of drilling and workover activity in the U.S., Canada and Central and South America. Our accommodations segment is conducted primarily in Canada and its activity levels have historically been driven by oil and gas drilling and mining activities. In the past year, we have seen increased demand in our work force accommodation business as a result of oil sands development activities in Northern Alberta, Canada. ~~We also support remote accommodations needs primarily~~Effective March 1, 2006, we completed a transaction to combine our workover services business with Boots & Coots (Amex: WEL) (Boots & Coots) and we now own a 45.6% equity interest in Boots & Coots. See Note 10 to the ~~U.S. and Canada.~~Unaudited Condensed Consolidated Financial Statements.

We have a diversified product and service offering which has exposure throughout the oil and gas cycle. Demand for our tubular services and well site services segments are highly correlated to changes in the 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, as of and for the periods indicated.

1514

~~On May 11, 2004, our tubular services segment purchased the OCTG distribution business of Hunting Energy Services, L.P. (Hunting) for $47.2 million, including purchase price adjustments.~~ On June 2, 2005 we acquired all of the outstanding stock of Phillips Casing and Tubing, Inc. (Phillips) for total consideration of ~~$31.1~~$31.2 million. ~~Both of these acquisitions~~This acquisition resulted in increased OCTG inventory and revenues from the date of acquisition. Our tubular services segment shipped ~~286,700~~126,700 tons of OCTG in the first ~~nine~~three months of ~~2005 (104,100 tons in the third quarter of 2005)~~2006 compared to ~~242,100~~82,000 tons in the first ~~nine~~three months of ~~2004 (90,200 tons in the third quarter of 2004).~~2005. Our tubular services segment benefited in the ~~past nine months~~quarter from a ~~16.7% year over year~~22.1% year-over-year increase in average U.S. land drilling ~~activity,~~activity. Our OCTG business is particularly leveraged to gas drilling in high pressure, tight formations given the ~~acquisition~~higher volume and quality of tubulars used in the ~~Hunting and Phillips~~drilling completion of such wells. OCTG ~~distribution businesses and increased~~prices have remained fairly constant during the first three months of 2006 compared to the year 2005 when we experienced several price increases for our OCTG ~~prices.~~inventory. Our tubular services gross margins have ~~been at~~declined compared to historically high levels reached in ~~2005 and are expected to continue at relatively strong levels throughout~~ 2005. ~~The tubular~~Tubular services gross margin as a percent of revenues decreased to ~~12.3%~~9.3% in the ~~third~~first quarter of ~~2005 compared to~~2006 from a gross margin percent of ~~14.4%~~13.0% in the ~~third~~

Our offshore products segment reported a much improved first ~~nine months~~quarter of ~~2005~~2006 compared to the first ~~nine months~~quarter of ~~2004~~2005 as a result of increased activity and greater fixed cost absorption. Our offshore products backlog totaled ~~$119.4~~$220.8 million at ~~September 30, 2005, $97.5~~March 31, 2006, $110.7 million at December 31, ~~2004~~2005 and ~~$87.3~~$99.8 million at ~~September 30, 2004.~~March 31, 2005. We believe that the deepwater offshore construction and development business is characterized by lengthy projects and a long “lead-time” order cycle. While ~~change~~changes in backlog levels from one quarter to the next ~~does~~do not necessarily evidence a long-term trend, we believe activity levels in our offshore products segment will increase in future quarters, given the significant growth in our backlog, when compared to year end ~~2004~~2005 levels.

~~The Company’s~~Our income tax provision for the first ~~nine months~~quarter of ~~2005~~2006 totaled ~~$47.0~~$34.2 million, or 39.3% of pretax income compared to $14.8 million, or 36.9% of pretax ~~income.~~income, for the first quarter of 2005. Our effective tax rate increased in the first ~~nine~~three months of ~~2005~~2006 compared to the first ~~nine~~three months of ~~2004. Our first nine months~~2005 as a result of ~~2004 reflected an effective~~a higher tax rate applicable to the gain recognized on the sale of 31.9% due to greater NOL benefits recognized in the first quarter of 2004 when a $5.4 million income tax benefit was recognized upon a partial reversal of valuation allowances applied against net operating loss carryforwards. In the third quarter of 2005, our ~~income tax provision totaled $17.7 million, 36.9% of pretax income compared to $11.0 million, or 41.4% of pretax income in the third quarter of 2004.~~workover services business. See Note 10.

Management believes that fundamental oil and gas supply and demand factors will continue to support a high level of drilling activity in North America which should continue to positively impact the Company, particularly ~~its~~our tubular services and well site service segments. We also believe that oil and gas producers have increased their view of longer term oil and gas prices based on current supply and demand fundamentals, even though such long term price expectations are still at levels below current prices. As a result, our customers ~~could increase~~have increased their spending onand commitments for deepwater offshore exploration and development which ~~should benefit~~has benefited our offshore products segment. However, there can be no assurance that these ~~expectations~~trends will ~~be realized~~continue and there is a risk that continued energy prices at current levels could negatively impact worldwide economic growth and, correspondingly, reduce the demand for energy causing oil and gas expenditures to decline which would be adverse to our business. In addition, particularly in our well site services segment, we must continue to monitor industry capacity additions and evaluate our expected returns, project risks and expected cash flows and evaluate such capacity additions in light of their impact on the competitive marketplace.

1716

Results of Operations (in millions, except margin percentages)


	THREE MONTHS ENDED						NINE MONTHS ENDED						THREE MONTHS ENDED
	SEPTEMBER 30,						SEPTEMBER 30,						MARCH 31,
	2005			2004			2005			2004			2006			2005
Revenues
Offshore Products	$	64.3		$	55.2		$	194.7		$	146.1
Tubular Services		188.3			116.9			493.9			283.4
Well Site Services —
Well Site Services -
Accommodations		67.2			42.3			215.4			139.5		$	104.6		$	83.2
Rental tools		40.0			16.2			90.3			48.7			49.6			19.1
Drilling services		24.0			12.8			60.6			34.5			28.0			16.8
Workover services		10.3			8.1			29.7			25.7			8.5			8.5

Total Well Site Services		141.5			79.4			396.0			248.4			190.7			127.6
Offshore Products														78.3			66.5
Tubular Services														227.2			137.8

Total	$	394.1		$	251.5		$	1,084.6		$	677.9		$	496.2		$	331.9


Gross Margin
Offshore Products	$	14.3		$	10.7		$	42.6		$	27.8
Tubular Services		23.2			16.8			62.5			35.7
Well Site Services —
Well Site Services -
Accommodations		16.4			12.9			51.9			40.8		$	33.3		$	23.0
Rental tools		19.6			7.2			44.0			21.5			26.5			8.7
Drilling services		9.3			4.6			21.4			11.0			14.0			5.8
Workover services		3.1			1.8			8.5			6.3			3.2			1.7

Total Well Site Services		48.4			26.5			125.8			79.6			77.0			39.2
Offshore Products														19.9			14.1
Tubular Services														21.1			18.0

Total	$	85.9		$	54.0		$	230.9		$	143.1		$	118.0		$	71.3


Gross Margin as a Percent of Revenues
Well Site Services -
Accommodations														31.8	%		27.6	%
Rental tools														53.4	%		45.5	%
Drilling services														50.0	%		34.5	%
Workover services														37.6	%		20.0	%
Total Well Site Services														40.4	%		30.7	%
Offshore Products		22.2	%		19.4	%		21.9	%		19.0	%		25.4	%		21.2	%
Tubular Services		12.3	%		14.4	%		12.7	%		12.6	%		9.3	%		13.1	%
Well Site Services —
Total														23.8	%		21.5	%

Operating Income (Loss)
Well Site Services -
Accommodations		24.4	%		30.5	%		24.1	%		29.2	%	$	25.3		$	17.1
Rental tools		49.0	%		44.4	%		48.7	%		44.1	%		16.9			3.2
Drilling services		38.8	%		35.9	%		35.3	%		31.9	%		11.8			4.2
Workover services		30.1	%		22.2	%		28.6	%		24.5	%		1.8			0.1

Total Well Site Services		34.2	%		33.4	%		31.8	%		32.0	%		55.8			24.6

Total		21.8	%		21.5	%		21.3	%		21.1	%


Operating Income (Loss)
Offshore Products	$	5.9		$	2.7		$	16.6		$	4.7			10.1			5.3
Tubular Services		19.8			14.1			53.1			28.5			17.8			15.1
Well Site Services —
Accommodations		9.5			7.5			32.8			25.1
Rental tools		10.9			2.3			22.5			6.9
Drilling services		7.3			3.5			16.0			8.0
Workover services		1.1			0.1			3.2			1.1

Total Well Site Services		28.8			13.4			74.5			41.1

Corporate / Other		(3.2	)		(2.3	)		(8.7	)		(5.6	)		(4.5	)		(2.8	)

Total	$	51.3		$	27.9		$	135.5		$	68.7		$	79.2		$	42.2

respectively, in the ~~three months~~quarter ended ~~September 30, 2005~~March 31, 2006 compared to the ~~three months~~quarter ended ~~September 30, 2004~~March 31, 2005 due to increased industry demand, higher OCTG prices and contributions from the Phillips acquisition that closed in June 2005. Our average OCTG selling prices increased ~~39.6%~~6.6% from the ~~third~~first quarter of ~~2004~~2005 to the ~~third~~first quarter of ~~2005.~~2006. Well site services revenues increased ~~$62.1~~$63.1 million, or ~~78.2%~~49.5%, to ~~$141.5~~$190.7 million during the current quarter compared to ~~$79.4~~$127.6 million during the quarter ended ~~September 30, 2004.~~March 31, 2005. Our drilling services revenues increased $11.2 million, or ~~87.5%~~66.7%, because of contributions from the Elenburg acquisition which added 7 rigs in February 2005, higher dayrates earned and ~~additional~~3 newly built rigs added to the ~~fleet. In our~~fleet since March 31, 2005. Our workover services operations were sold effective March 1, 2006. Workover services revenues were flat when comparing the two months ended February 28, 2006 to the full quarter ended March 31, 2005 primarily as a result of higher activity in ~~all areas of our operations, especially~~Venezuela in ~~the U.S. Gulf and Venezuela, were higher in 2005 than 2004 resulting in a $2.2 million increase in revenues.~~2006. The rental tools business generated revenues in the ~~third~~first quarter of ~~2005~~2006 of ~~$40.0~~$49.6 million, which were ~~$23.8~~$30.5 million, or ~~146.9%~~159.7%, higher than the ~~third~~first quarter of ~~2004~~2005 due to the acquisition of Stinger, capital expenditures made since last year, improving U.S. drilling and workover activity and price increases. The Stinger acquisition ~~was responsible for $20.6 million of~~contributed materially to the ~~$23.8 million~~ increase in revenues generated from ~~the Company’s~~our rental tools business line. Accommodations revenues in the ~~third~~first quarter of ~~2005~~2006 were ~~$24.9~~$21.4 million, or ~~58.9%~~25.7%, higher than accommodations revenues reported in the ~~third~~first quarter of ~~2004~~2005 primarily because of increased drilling activity during the winter season and increased activity in support of the oil sands region of Canada.

Gross Margin.Our gross margins, which we calculate before a deduction for depreciation expense, increased ~~$31.9~~$46.7 million, or ~~59.1%~~65.5%, from ~~$54.0~~$71.3 million in the quarter ended ~~September 30, 2004~~March 31, 2005 to ~~$85.9~~$118.0 million in the quarter ended ~~September 30, 2005.~~March 31, 2006. Overall margins as a percentage of revenue ~~remained relatively constant at~~improved from 21.5% for the first quarter of 2005 to 23.8% of revenues in the ~~third~~first quarter of ~~2004 compared~~2006 due to ~~21.8%~~improving gross margins in ~~the third quarter~~all of ~~2005.~~our well site services businesses and our offshore products segment, partially offset by a decline in tubular services gross margins.

Total gross margins at offshore products were ~~$14.3~~$19.9 million in the ~~third~~first quarter of ~~2005~~2006 compared to ~~$10.7~~$14.1 million in the same period of the prior year representing an increase of ~~33.6%~~41.1%. Offshore products gross margin percentage improved from ~~19.4%~~21.2% in the ~~third~~first quarter of ~~2004~~2005 to ~~22.2%~~25.4% in the ~~third~~first quarter of this year due to higher activity which resulted in greater overhead absorption, ~~cost savings~~higher margins on hurricane repair equipment and ~~efficiencies resulting from manufacturing facility consolidations that occurred in 2004 and that have benefited 2005 and the absence of a $1.0 million warranty charge recorded~~also to increased connector products sold in the ~~third quarter of 2004.~~current quarter.

Tubular services gross margins increased by ~~$6.4~~$3.1 million, or ~~38.1%~~17.2%, in the three months ended ~~September 30, 2005~~March 31, 2006 compared to the three months ended ~~September 30, 2004~~March 31, 2005 as a result of ~~OCTG price increases and~~ increased U.S. oil and gas land drilling activity which strengthened demand for our tubular products and services. Our tubular services segment gross margin as a percent of revenues decreased to ~~12.3%~~9.3% in the ~~third~~first quarter of ~~2005 when~~2006 compared to ~~14.4%~~13.1% in the ~~third~~first quarter of ~~2004~~2005 because of less frequent and smaller OCTG price increases, ~~in the third quarter of 2005 than in the same period in 2004~~higher industry inventory levels and because of a higher mix of lower margin carbon grade OCTG products sold in support of increased land drilling in the ~~third~~first quarter of ~~2005.~~2006 coupled with the lingering effects of the hurricanes on Gulf of Mexico drilling activity which resulted in reduced demand for higher margin seamless alloy tubulars. Our acquisition of Phillips increased our participation in the carbon grade OCTG market segment.

Well site services gross margins increased by ~~$21.9~~$37.8 million, or ~~82.6%~~96.4%, during the quarter ended ~~September 30, 2005~~March 31, 2006 compared to the quarter ended ~~September 30, 2004.~~March 31, 2005. Drilling services gross margins in the ~~third~~first quarter of 2006 totaled $14.0 million compared to $5.8 million in the first quarter of 2005, ~~totaled $9.3 million compared to $4.6 million in the third quarter of 2004,~~ an increase of ~~$4.7~~$8.2 million, or ~~102.2%~~141.4%. The drilling services gross margin percentage improved to ~~38.8%~~50.0% of revenues in the ~~third~~first quarter of ~~2005~~2006 from ~~35.9%~~34.5% of revenues in the ~~third~~first quarter of ~~2004~~2005 due primarily to higher dayrates in ~~2005~~2006 and ~~higher costs in the prior year due~~a move from billing on a footage rate basis to ~~several problem jobs.~~billing on a dayrate basis for most of our drilling rigs. Rental tools gross margins totaled ~~$19.6~~$26.5 million in the ~~third~~first quarter of 2006 compared to $8.7 million in the first quarter of 2005, ~~compared to $7.2 million in the third quarter of 2004,~~ an increase of ~~$12.4~~$17.8 million, or ~~172.2%~~204.6%. Rental tools gross margin percentage increased from ~~44.4%~~45.5% for the ~~third~~first quarter of ~~2004~~2005 to ~~49.0%~~53.4% in the ~~third~~first quarter of ~~2005.~~2006. The improvement in gross margins and gross margin as a percentage of revenues resulted primarily from the positive impact of the Stinger acquisition ~~which generated $11.7 million of the $12.4 million increase in rental tools gross margins.~~and pricing improvements realized. Workover gross margins improved to ~~$3.1~~$3.2 million in the two months ended February 28, 2006 compared to $1.7 million in the three months ended ~~September 30,~~March 31, 2005, an improvement despite the Company being sold effective March 1, 2006. Accommodations gross margins in the first quarter of 2006 totaled $33.3 million compared to ~~$1.8~~$23.0 million in the ~~three months ended September 30, 2004,~~first quarter of 2005, an ~~improvement~~increase of ~~$1.3~~$10.3 million, or ~~72.2%~~44.8%. The ~~workover~~ gross margin percentage increased to ~~30.1% of revenues~~31.8% in the ~~third~~first quarter of 2005 compared to 22.2% in the third quarter of 2004 due to a greater mix of activity involving lower cost workover activity and slightly higher dayrates. Accommodations gross margins in the third quarter of 2005 totaled $16.4 million compared to $12.9 million in the third quarter of 2004, an increase of $3.5 million, or 27.1%. The gross margin percentage declined to 24.4% in the third quarter of 20052006 compared to a ~~30.5%~~27.6% gross margin percentage for the ~~third~~first quarter of ~~2004~~2005 due to the ~~higher relative mix~~benefits of ~~lower margin manufacturing revenues.~~

1918

price and utilization increases for our accommodations equipment, partially offset by losses on an accommodations installation project.

Selling, General and Administrative Expenses.Selling, general and administrative expenses (SG&A) increased ~~$5.9~~$6.3 million, or ~~36.0%~~33.5%, in the ~~third~~first quarter of ~~2005~~2006 compared to the same period in ~~2004.~~2005. During the three months ended ~~September 30, 2005,~~March 31, 2006, SG&A totaled ~~$22.4~~$25.4 million, or ~~5.7%~~5.1% of revenues, compared to SG&A of ~~$16.5~~$19.1 million, or ~~6.6%~~5.7% of revenues, for the three months ended ~~September 30, 2004.~~March 31, 2005. Increased SG&A expense associated with acquisitions completed since the ~~third~~first quarter of ~~2004, ad valorem taxes for~~2005, increased ~~levels~~stock compensation expense due to the implementation of ~~OCTG inventory,~~SFAS No. 123R which required the expensing of stock options beginning January 1, 2006 and increased incentive compensation accruals ~~and higher professional fees associated with Sarbanes-Oxley compliance~~ were the primary factors causing increased SG&A in ~~2005~~2006 compared to ~~2004.~~2005.

Depreciation and Amortization.Depreciation and amortization expense increased ~~$3.1~~$2.7 million, or ~~33.8%~~26.0%, in the ~~third~~first quarter ~~2005~~2006 compared to the ~~third~~first quarter ~~2004~~2005 due primarily to acquisitions of businesses and capital expenditures made in the past year.

Operating Income.Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating (income) expense. Our operating income increased ~~$23.4~~$37.0 million, or ~~83.9%~~87.7%, to ~~$51.3~~$79.2 million for the ~~three months~~quarter ended ~~September 30, 2005~~March 31, 2006 from ~~$27.9~~$42.2 million for the ~~three months~~quarter ended ~~September 30, 2004.~~March 31, 2005. Offshore products operating income increased ~~$3.2~~$4.8 million, tubular services operating income increased ~~$5.7~~$2.7 million and well site services operating income increased ~~$15.4~~$31.2 million. These increases were partially offset by higher corporate costs of ~~$0.9~~$1.7 million.

Interest Expense. Interest expense increased ~~$1.9~~$2.5 million, or ~~93.5%~~107.3%, for the quarter ended ~~September 30, 2005~~March 31, 2006 compared to the quarter ended ~~September 30, 2004.~~March 31, 2005. Interest expense increased due to higher debt levels resulting from acquisitions completed since the ~~third~~first quarter of ~~2004~~2005 and capital expenditures, combined with higher interest ~~rates.~~rates for our bank credit facility.

Income Tax Expense. Income tax expense totaled ~~$17.7~~$34.2 million, or 39.3% of pretax income, during the quarter ended March 31, 2006 compared to $14.8 million, or 36.9% of pretax income, during the quarter ended ~~September 30, 2005 compared to $11.0 million, or 41.4% of pretax income, during the quarter ended September 30, 2004.~~March 31, 2005. Our effective tax rate was higher in the ~~third~~first quarter of ~~2004~~2006 because of a ~~change in the estimated 2004 annual~~higher effective tax rate ~~during that quarter. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Tax Matters” discussion below.~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004~~

~~Revenues.~~Total revenues increased $406.7 million, or 60.0%, to $1,084.6 million during the nine months ended September 30, 2005 compared to revenues of $677.9 million during the nine months ended September 30, 2004. Offshore products revenues increased $48.6 million, or 33.3%, due to higher activity levels supporting offshore production facility construction. Tubular services revenues and tons shipped increased $210.5 million, or 74.3%, and 44,600 tons, or 18.4%, respectively, in the nine months ended September 30, 2005 comparedapplicable to the ~~nine months ended September 30, 2004 due to increased industry demand, higher OCTG prices,~~gain recognized on the Hunting acquisition completed in May 2004 and the Phillips acquisition that closed in June 2005. Our average OCTG selling prices increased 47.1% from the first nine months of 2004 to the first nine months of 2005. Well Site services revenues increased $147.6 million, or 59.4%, to $396.0 million during the first nine months of 2005 compared to $248.4 million during the first nine months of 2004. Our drilling revenues increased $26.1 million, or 75.7%, because of contributions from the Elenburg acquisition, which added 7 rigs in February 2005, higher dayrates earned and additional rigs added to the fleet. The Elenburg acquisition was responsible for $16.6 million of the $26.1 million increase in revenues generated from the Company’s drilling operations. Our hydraulic workover revenues increased by $4.0 million, or 15.6%, in the first nine months of 2005 compared to the same period in 2004 because of higher activity in allsale of our operating areas, especially the U.S. Gulf and Venezuela. Rental tools generated revenues in the nine months ended September 30, 2005 of $90.3 million, which were $41.6 million, or 85.4%, higher than the nine months ended September 30, 2004 due to the acquisition of Stinger, capital expenditures made since last year, improving U.S. drilling activity and modest price increases. The Stinger acquisition accounted for $31.6 million of the $41.6 million revenue increase generated by the Company’s rental tools business line. Accommodations revenues in the nine months ended September 30, 2005 were $215.4 million, an increase of $75.9 million, or 54.4%, over the accommodations revenues reported in the nine months ended September 30, 2004 primarily because of increased activity in support of the oil sands region of Canada.

~~Gross Margin.~~Our gross margins, which we calculate before a deduction for depreciation expense, increased $87.8 million, or 61.4%, from $143.1 million in the nine months ended September 30, 2004 to $230.9 million in the nine months ended September 30, 2005. Our overall gross margin as a percent of revenues was 21.3% in the first nine months of 2005 compared to 21.1% in the first nine months of 2004. Gross margin percentages increased in all businesses except accommodations where a greater percentage of revenues was generated by manufacturing activities which generally earn a lower margin than accommodations rental and service activities.

Total gross margins at offshore products were $42.6 million in the first nine months of 2005 compared to $27.8 million in the same period of the prior year, representing an increase of 53.2%. Offshore products gross margin percentage improved from 19.0% in the first nine months of 2004 to 21.9% in the first nine months of 2005 due to higher activity, which resulted in greater overhead absorption, cost savings and efficiencies resulting from manufacturing facility consolidations that occurred in 2004 and that have benefited 2005 and the absence of a $1.0 million warranty charge recorded in the third quarter of 2004.

~~Tubular~~workover services gross margins increased $26.8 million, or 75.1%, in the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 as a result of price increases and increased oil and gas drilling activity which strengthened demand for our tubular products and services. Our tubular services segment gross margin as a percent of revenues remained relatively constant at 12.6% in the first nine months of 2004 compared to 12.7% in the first nine months of 2005.

Well Site services gross margins increased by $46.2 million, or 58.0%, during the first nine months of 2005 compared to the first nine months of 2004. Drilling gross margins in the nine months ended September 30, 2005 totaled $21.4 million compared to $11.0 million in the nine months ended September 30, 2004, an increase of $10.4 million, or 94.5%. Of the $10.4 million increase in drilling gross margins, $6.0 million was generated by the Elenburg acquisition. Our drilling services gross margin percentage improved to 35.3% of revenues in the first nine months of 2005 from 31.9% of revenues in the first nine months of 2004 due primarily to higher dayrates. Workover gross margins improved by $2.2 million, or 34.9%, in the first nine months of 2005 compared to the same period of the prior year because of higher activity in the U.S. Gulf and Venezuela. The workover gross margin percentage increased to 28.6% of revenues in the first nine months of 2005 compared to 24.5% in the first nine months of 2004 due primarily to higher utilization. Rental tools gross margins totaled $44.0 million in the nine months ended September 30, 2005 compared to $21.5 million in the nine months ended September 30, 2004, an increase of $22.5 million, or 104.7%. Rental tools gross margin percentage increased from 44.1% for the first nine months of 2004 to 48.7% in the first nine months of 2005. The improvement resulted from higher utilization of tools, modestly higher rental rates and the positive impact of the Stinger acquisition. Of the $22.5 million increase in rental tools gross margins, $17.4 million was generated by Stinger since its acquisition in May of 2005. Accommodations gross margins in the nine months ended September 30, 2005 totaled $51.9 million compared to $40.8 million in the nine months ended September 30, 2004, an increase of $11.1 million, or 27.2%. The gross margin percentage declined to 24.1% in the first nine months of 2005 compared to the 29.2% gross margin percentage for the first nine months of 2004 due to a higher relative mix of lower margin manufacturing revenues.

~~Selling, General and Administrative Expenses.~~Selling, general and administrative expenses (SG&A) increased $15.1 million, or 32.1%, in the first nine months of 2005 compared to the same period in 2004. During the nine months ended September 30, 2005, SG&A totaled $62.2 million, or 5.7% of revenues, compared to SG&A of $47.1 million, or 6.9% of revenues, for the nine months ended September 30, 2004. Increased SG&A expense associated with acquisitions completed since September 2004, higher ad valorem taxes for increased levels of OCTG inventory, increased incentive compensation accruals, and higher professional fees associated with Sarbanes-Oxley compliance were the primary factors causing the increased SG&A in 2005 compared to 2004.

~~Depreciation and Amortization.~~Depreciation and amortization expense increased $7.2 million, or 27.3%, in the first nine months of 2005 compared to the first nine months of 2004 due primarily to acquisitions of businesses and capital expenditures made in the past year.

~~Operating Income.~~Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating (income) expense. Our operating income increased $66.8 million, or 97.2%, to $135.5 million for the nine months ended September 30,

2005 from $68.7 million for the nine months ended September 30, 2004. Offshore products operating income increased $11.9 million, tubular services operating income increased $24.6 million and well site services operating income increased $33.4 million. These increases were partially offset by higher corporate costs of $3.1 million.

~~Interest Expense.~~Interest expense increased $3.9 million, or 70.5%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Interest expense increased due to higher debt levels resulting from acquisitions completed since September 30, 2004 and capital expenditures, combined with higher interest rates.

~~Income Tax Expense.~~Income tax expense totaled $47.0 million, or 36.9% of pretax income, during the nine months ended September 30, 2005 compared to $20.5 million, or 31.9% of pretax income, during the nine months ended September 30, 2004. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Tax Matters” discussion below.business.

Liquidity and Capital Resources

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

Cash totaling ~~$0.3~~$18.7 million was provided by operations during the ~~nine months~~quarter ended ~~September 30, 2005~~March 31, 2006 compared to cash used in operating activities totaling ~~$64.8~~$6.1 million ~~provided by operations~~ in the ~~nine months~~quarter ended ~~September 30, 2004.~~March 31, 2005. During the first ~~nine months~~quarter of ~~2005, $119.5~~2006, $38.0 million was used to fund working capital. ~~Significantly~~Receivables increased ~~working capital was invested~~seasonally in ~~tubular services inventory due to~~our Canadian accommodations business and inventories increased ~~volumes~~in our accommodations and ~~prices paid. Additionally, trade receivables increased as a result of higher revenues and temporary disruptions of collections caused by U.S. Gulf hurricane activity in the third quarter.~~offshore products segments.

Cash was used in investing activities during the ~~nine months~~quarters ended ~~September 30,~~March 31, 2006 and 2005 ~~and 2004~~ in the amount of ~~$194.5~~$30.2 million and ~~$114.6~~$39.3 million, respectively. Capital expenditures totaled ~~$49.4~~$26.5 million and ~~$38.1~~$17.1 million during the ~~nine months~~quarters ended ~~September 30,~~March 31, 2006 and 2005, ~~and 2004,~~ respectively. Capital expenditures in both ~~years~~periods consisted principally of ~~purchases~~the purchase of assets for our well site services segment. ~~In addition, we~~We completed ~~various~~ acquisitions for net cash consideration totaling ~~$146.6~~$22.6 million ~~and $79.5 million net of cash acquired,~~ during the first ~~nine months~~quarter of ~~2005 and 2004, respectively.~~

On February 1, 2005, the Company completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for cash consideration of $21.3 million, including transaction costs, plus a note payable to the former owners of $0.8 million. Elenburg owned and operated 7 rigs which provide shallow land drilling services in Montana, Wyoming, Colorado, and Utah.

Effective May 1, 2005 the Company acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, Stinger) for cash consideration of $78.0 million, net of cash acquired and including transaction costs, plus a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 23 locations in the United States and Canada. Stinger’s patented equipment is utilized during pressure pumping operations and isolates the customers’ blow-out preventers or wellheads from the pressure and abrasion experienced during the fracturing process of an oil or gas well. In June 2005, the Company completed the acquisition of Stinger’s international operations for additional cash consideration of $6.2 million, net of cash acquired and including transaction costs. The Stinger international operations are conducted primarily in Central and South America. The Stinger acquisition expanded the Company’s rental tool and services capabilities, especially in the pressure pumping market.

On June 2, 2005, the Company purchased Phillips Casing and Tubing, L.P. (Phillips) for cash consideration of $31.1 million, net of cash acquired and including transaction costs. Phillips distributes oil country tubular goods

expect to fund these capital expenditures with internally generated funds and proceeds from borrowings under our revolving credit facilities.

Net cash of ~~$194.9~~$8.4 million ~~was~~and $47.5 million were provided by financing activities during the ~~nine months~~quarters ended ~~September 30,~~March 31, 2006 and 2005, respectively, primarily as a result of ~~revolving credit~~ borrowings and the issuance of $175 million aggregate principal amount of 2 3/8% contingent convertible senior notes due in 2025 (2 3/8% notes) in the second and third quarters of 2005. Net proceeds from the 2 3/8% notes were utilized to repurchase $30 million of the Company’s common stock, which was classified as treasury stock at September 30, 2005, to repay an outstanding bridge loan of $25 million and to repay indebtedness of $114.5 millionmade under our revolving credit facility. During the first quarter of 2005, ~~the Company’s~~our Board of Directors authorized the repurchase of up to $50 million of ~~the Company’s~~our common stock, par value $.01 per share, over a two year period. Through ~~September 30, 2005,~~March 31, 2006, a total of $30 million of ~~the Company’s~~our stock ~~acquired with a portion of the proceeds from the issuance of the 2 3/8% notes,~~(1,183,432 shares), has been repurchased under this program. No shares of ~~the Company’s~~our stock were repurchased during the three months ended ~~September 30, 2005 and~~March 31, 2006 leaving a total of up to $20 million ~~remains~~ available under the program.

Our primary bank credit facility (the Credit Facility), which matures in January 2010, provides for $325 million of revolving credit. The credit agreement, which governs our Credit Facility (the Credit Agreement), contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to either LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on ~~the Company’s~~our leverage ratio, on the unused commitments under the Credit Agreement. During the first ~~nine months~~quarter of ~~2005,~~2006, our applicable margin over LIBOR ~~ranged from 1% to 2% and it~~ was 1.25% ~~as of September 30, 2005.~~. Our weighted average interest rate paid under the Credit Agreement was ~~4.7%~~5.8% during the ~~three months~~quarter ended ~~September 30, 2005~~March 31, 2006 and ~~4.4%~~4.2% for the ~~nine months~~quarter ended ~~September 30,~~March 31, 2005.

As of ~~September 30, 2005,~~March 31, 2006, we had ~~$223.3~~$226.9 million outstanding under the Credit Facility and an additional ~~$11.3~~$10.9 million of outstanding letters of credit, leaving ~~$90.4~~$87.2 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~~$8.5 million. We had no borrowings outstanding under these other facilities as of ~~September 30, 2005.~~March 31, 2006. Our total debt represented ~~40.8%~~37.1% of our total capitalization at ~~September 30, 2005.~~March 31, 2006.

We believe that cash from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. However, there is no assurance that we will be able to raise additional funds or be able to raise such funds on favorable terms.

Tax Matters

Our primary deferred tax asset, which totaled approximately $12.5 million at December 31, 2004, is related to $35.8 million in available federal net operating loss carryforwards, or NOLs, as of that date. A valuation allowance of approximately $5.1 million was provided against the deferred tax asset associated with our NOLs at December 31, 2004. The NOLs will expire in varying amounts during the years 2010 through 2020 if they are not first used to offset taxable income generated by the Company. The Company’s ability to utilize a significant portion of the NOLs is currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. A successive change in control was triggered in 2003 pursuant to Section 382; however it did not significantly change the Company’s NOL utilization expectations.

~~The Company’s~~ income tax provision for the three months ended ~~September 30, 2005~~March 31, 2006 totaled ~~$17.7~~$34.2 million, or ~~36.9%~~39.3% of pretax income, compared to ~~$11.0~~$14.8 million, or ~~41.4%~~36.9% of pretax income, for the three months ended September 30, 2004. The Company’s income tax provision for the nine months ended September 30, 2005 totaled $47.0 million, or 36.9%, of pretax income compared to $20.5 million, or 31.9%, of pretax income for the nine months ended September 30, 2004. Our effective tax rate was lower in the first nine months of 2004 as a result of the recognition of a $5.4 million income tax benefit related to the partial reversal of the valuation allowance applied against NOLs which were recorded as of the prior year end.March 31, 2005.

We currently estimate that our effective tax rate for the full year ~~2005~~2006 will approximate ~~35% to 38%~~37%. Our actual effective tax rate could differ materially from this estimate, which is subject to a number of uncertainties, including future taxable income projections, the amount of income attributable to domestic versus foreign sources, the amount of capital expenditures and any changes in applicable tax laws and regulations. Based upon the loss limitation provisions of Section 382, we should be able to utilize approximately $8$4.4 million of our NOLs to offset taxable income generated by the Company during the tax year ended December 31, ~~2005.~~2006. The income statement benefit of substantially all of our NOLs has been recognized in prior periods.

~~Recent~~Critical Accounting ~~Pronouncements~~Policies

In ~~the fourth quarter~~our selection of ~~2004, the FASB issued Statement No. 123 (revised 2004), or SFAS No. 123R, “Share-Based Payment,” which replaces Statement No. 123 “Accounting for Stock-Based Compensation,”~~critical accounting policies, our objective is to properly reflect our financial position and ~~supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R eliminates the alternative to~~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 APB Opinion 25’s intrinsic value method of accounting that was provided in Statement No. 123 as originally issued. After a phase-in period for Statement No. 123R, pro forma disclosure will no longer be allowed.our judgment about uncertainties.

~~Alternative phase-in methods~~There are ~~allowed under Statement No. 123R,~~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, warranty claims, contract claims and discontinued operations.

The assessment of impairment on long-lived assets, including goodwill and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. The determination of the amount of impairment, which is ~~effective for registrants~~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 ~~beginning~~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 ~~first fiscal year beginning after June 15, 2005. We~~revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are ~~currently~~subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the ~~process~~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 ~~evaluating~~inventory, involve reviews of underlying details of these assets, known trends in the ~~impact~~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.

Since the adoption of SFAS No. 123R on– Share Based Payments, effective January 1, 2006, we are required to estimate the fair value of stock compensation made pursuant to awards under the Company’s 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 Shoals Merton “closed form” model to value stock options awarded under the Plan. We have chosen this model because our ~~consolidated condensed financial statements.~~option awards have been made under straightforward and consistent vesting terms, option prices and option lives. Utilizing the Black Shoals Merton model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will ~~adopt SFAS No. 123R on January 1, 2006.~~continually monitor our actual experience and change future assumptions for awards as we consider appropriate.

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, 2005,~~March 31, 2006, we had floating rate obligations totaling approximately ~~$223.3~~$226.9 million for amounts borrowed under our revolving credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rate were to increase by 1% from ~~September 30, 2005~~March 31, 2006 levels, our consolidated interest expense would increase by a total of approximately ~~$2.2~~$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. WeIn the past, we have hedged U.S. dollar balances and cash flows ~~totaling $5.5 million~~ in our U.K. ~~subsidiary in the fourth quarter~~subsidiary; however, no active hedges exist as of ~~2005 through the first quarter of~~March 31, 2006. Results of operations have not been materially affected by foreign currency hedging activity.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

Item 1A. “Risk Factors” of our 2005 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 2005 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

ITEM 5. OTHER INFORMATION

None


		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~~ Months Ended ~~September 30,~~March 31, 2006 and 2005 ~~and 2004~~		3
	Consolidated Balance Sheets ~~–September 30, 2005~~— March 31, 2006 (unaudited) and December 31, ~~2004~~2005		4
	Unaudited Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2006 and 2005 ~~and 2004~~		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 – 2421

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		2422

Item 4.	Controls and Procedures		2522

	Part II — OTHER INFORMATION

Item 1.	Legal Proceedings		2623

Item 1A.	Risk Factors		23

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		2623

Item 3.	Defaults Upon Senior Securities		2623

Item 4.	Submission of Matters to a Vote of Security Holders		2623

Item 5.	Other Information		2623

Item 6.	Exhibits		~~26 - 27~~24

	(a) Index of Exhibits		2624

	Signature Page		2825
Non-Employee Director Compensation Summary
Certification of CEO pursuant to Rules ~~13a-14a/15d-14a~~13a-14(a)or 15d-14(a)
Certification of CFO pursuant to Rules ~~13a-14a/15d-14a~~13a-14(a)or 15d-14(a)
Certification of CEO pursuant to Rules ~~13a-14b/15d-14b~~13a-14(b)or 15d-14(b)
Certification of CFO pursuant to Rules ~~13a-14b/15d-14b~~13a-14(b)or 15d-14(b)


	SEPTEMBER 30,			DECEMBER 31,			MARCH 31,			DECEMBER 31,
	2005			2004			2006			2005
Inventories, net:
Tubular goods	$	241,543		$	123,555		$	265,846		$	274,232
Other finished goods and purchased products		40,146			29,255			44,063			35,716
Work in process		30,506			39,936			35,495			30,288
Raw materials		28,160			21,978			29,054			26,412


Total inventories		340,355			214,724			374,458			366,648
Inventory reserves		(5,765	)		(4,899	)		(5,771	)		(5,722	)

	$	334,590		$	209,825		$	368,687		$	360,926
	��


	ESTIMATED	SEPTEMBER 30,			DECEMBER 31,			ESTIMATED	MARCH 31,			DECEMBER 31,
	USEFUL LIFE	2005			2004			USEFUL LIFE	2006			2005
Property, plant and equipment, net:
Land		$	9,468		$	5,909			$	9,315		$	9,576
Buildings and leasehold improvements	5-40 years		59,879			43,482		5-40 years		58,740			60,049
Machinery and equipment	2-20 years		277,810			236,266		2-20 years		271,713			292,713
Rental tools	3-15 years		70,038			56,572		2-10 years		57,283			72,327
Office furniture and equipment	1-10 years		16,325			14,238		1-15 years		16,030			16,231
Vehicles	2-5 years		27,255			11,036		2-10 years		26,920			26,035
Construction in progress			9,008			12,841				26,975			22,283


Total property, plant and equipment			469,783			380,344				466,976			499,214
Less: Accumulated depreciation			(179,464	)		(153,001	)			(161,110	)		(188,762	)

		$	290,319		$	227,343			$	305,866		$	310,452


	SEPTEMBER 30,		DECEMBER 31,		MARCH 31,		DECEMBER 31,
	2005		2004		2006		2005
Accounts payable and accrued liabilities:
Trade accounts payable	$	135,324	$	124,193	$	160,722	$	168,445
Accrued compensation		18,228		13,589		13,046		22,529
Accrued insurance		5,269		4,261		5,367		4,820
Accrued taxes, other than income taxes		6,719		3,310		5,717		4,354
Reserves related to discontinued operations		3,647		4,200		3,510		3,527
Other		10,699		9,712		8,767		10,829

	$	179,886	$	159,265	$	197,129	$	214,504


Shares of common stock outstanding — January 1, 2005	49,577,786

Shares issued upon exercise of stock options	660,052
Repurchase of shares held in treasury	(1,183,432	) (1)

Shares of common stock outstanding — September 30, 2005	49,054,406


	THREE MONTHS ENDED				NINE MONTHS ENDED
	SEPTEMBER 30				SEPTEMBER 30
	2005		2004		2005		2004
	(In thousands, except per share data)
Basic earnings per share:
Net income	$	30,308	$	15,513	$	80,448	$	43,825


Weighted average number of shares outstanding		48,925		49,409		49,436		49,262


Basic earnings per share	$	0.62	$	0.31	$	1.63	$	0.89


Diluted earnings per share:
Net income	$	30,308	$	15,513	$	80,448	$	43,825


Weighted average number of shares outstanding		48,925		49,409		49,436		49,262
Effect of dilutive securities:
Options on common stock		1,095		621		936		596
Restricted stock		88		31		70		37


Total shares and diluted securities		50,108		50,061		50,442		49,895


Diluted earnings per share	$	0.60	$	0.31	$	1.59	$	0.88


	THREE MONTHS					NINE MONTHS					THREE MONTHS
	ENDED SEPTEMBER 30,					ENDED SEPTEMBER 30,					ENDED MARCH 31,
	2005			2004		2005			2004		2006		2005
Comprehensive income:
Net income	$	30,308		$	15,513	$	80,448		$	43,825	$	52,916	$	25,289
Other comprehensive income:
Cumulative translation adjustment		6,211			5,489		1,676			3,070		24		(1,021	)
Foreign currency hedge		(10	)		—		(72	)		—		41		23

Total comprehensive income	$	36,509		$	21,002	$	82,052		$	46,895	$	52,981	$	24,291


~~(1)~~	~~See Note 6~~
Shares of common stock outstanding — ~~Debt~~January 1, 2006		49,179,258

Shares issued upon exercise of stock options and vesting of stock awards		303,466
Shares withheld for ~~discussion~~taxes on vesting of ~~treasury~~restricted stock ~~purchased.~~awards and transferred to treasury		(2,410	)

Shares of common stock outstanding — March 31, 2006		49,480,314


(1)		Subsequent to the March 1, 2006 effective date of the sale of our workover services business (See Note 10), we have classified our investment in Boots & Coots International Well Control, Inc. common stock and the notes receivable acquired in the transaction as workover services assets.


	Average Rig Count for										Average Rig Count for
	Year Ended December 31,										Year Ended December 31,
	2004		2003		2002		2001		2000		2005		2004		2003		2002		2001
U.S. Land		1,093		924		718		1,003		778		1,294		1,093		924		718		1,003
U.S. Offshore		97		108		113		153		140		89		97		108		113		153

Total U.S		1,190		1,032		831		1,156		918
Total U.S.												1,383		1,190		1,032		831		1,156
Canada (1)		369		372		266		341		345		458		369		372		266		341

Total North America		1,559		1,404		1,097		1,497		1,263		1,841		1,559		1,404		1,097		1,497


	Average Rig Count for								Average Rig Count for
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2005		2004		2005		2004		2006		2005
U.S. Land		1,330		1,133		1,254		1,075		1,438		1,178
U.S. Offshore		98		95		97		96		81		101

Total U.S		1,428		1,228		1,351		1,171
Total U.S.										1,519		1,279
Canada (1)		494		328		416		346		665		521

Total North America		1,922		1,556		1,767		1,517		2,184		1,800


(1)		Canadian rig counts typically increase during the peak winter drilling season.


Exhibit No.		Description
31.110.21,	—	~~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.~~Non-Employee Director Compensation Summary

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.~~


~~Exhibit No.~~		~~Description~~
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.~~


~~OIL STATES INTERNATIONAL, INC.~~

~~Date: November 3, 2005~~	By	~~/s/ CINDY B. TAYLOR~~

		~~Cindy B. Taylor~~
		~~Senior Vice President, Chief Financial Officer and~~
		~~Treasurer (Principal Financial Officer)~~

~~Date: November 3, 2005~~	By	~~/s/ ROBERT W. HAMPTON~~

		~~Robert W. Hampton~~
		~~Vice President — Finance and Accounting and~~
		~~Secretary (Principal Accounting Officer)~~


*		~~Filed herewith~~

~~***~~		~~Furnished herewith.~~


*		Filed herewith

**		Management contracts or compensation plans or arrangements

***		Furnished herewith.


~~Exhibit No.~~		~~Description~~
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.



Date: May 5, 2006	By	/s/ CINDY B. TAYLOR

		Cindy B. Taylor
	��	Senior Vice President, Chief Financial Officer and
		Treasurer (Principal Financial Officer)

Date: May 5, 2006	By	/s/ ROBERT W. HAMPTON

		Robert W. Hampton
		Vice President — Finance and Accounting and
		Secretary (Principal Accounting Officer)


Exhibit No.		Description
10.21*,	—	Non-Employee Director Compensation Summary

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.