e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended 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 number 1-16337

OIL STATES INTERNATIONAL, INC.

(Exact name of registrant as specified in its charter)


Delaware		76-0476605

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

Three Allen Center, 333 Clay Street, Suite 4620,
Houston, Texas		77002

(Address of principal executive offices)		(Zip Code)

(713) 652-0582

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report)

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

YES þ NO o

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

Check one: Large Accelerated Filer þ Accelerated Filer o Non-Accelerated Filer o

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

YES o NO þ

The Registrant had 49,523,086 shares of common stock outstanding as of April 28, 2006.

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In Thousands)


	MARCH 31,			DECEMBER 31,
	2006			2005
	(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents	$	11,999		$	15,298
Accounts receivable, net		302,296			274,070
Inventories, net		368,687			360,926
Prepaid expenses and other current assets		14,074			13,450

Total current assets		697,056			663,744

Property, plant, and equipment, net		305,866			310,452
Goodwill, net		330,431			339,703
Investments in unconsolidated affiliates		31,730			2,265
Other noncurrent assets		47,138			26,708

Total assets	$	1,412,221		$	1,342,872


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	197,129		$	214,504
Income taxes		27,482			7,023
Current portion of long-term debt		3,566			3,901
Deferred revenue		33,243			34,046
Other current liabilities		3,814			3,223

Total current liabilities		265,234			262,697

Long-term debt		406,007			402,109
Deferred income taxes		38,936			35,259
Other liabilities		8,392			8,823

Total liabilities		718,569			708,888

Stockholders’ equity:
Common stock		507			504
Additional paid-in capital		357,581			350,667
Retained earnings		342,909			289,993
Accumulated other comprehensive income		23,202			23,137
Treasury stock		(30,547	)		(30,317	)

Total stockholders’ equity		693,652			633,984

Total liabilities and stockholders’ equity	$	1,412,221		$	1,342,872

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)


	THREE MONTHS ENDED MARCH 31,
	2006			2005
Cash flows from operating activities:
Net income	$	52,916		$	25,289
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		12,886			10,228
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		83			2,158
Changes in working capital		(38,418	)		(45,595	)

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

Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		(49	)		(22,606	)
Cash balances of workover business sold		(4,366	)		—
Capital expenditures		(26,542	)		(17,147	)
Proceeds from sale of equipment		792			501
Other, net		(30	)		(80	)

Net cash flows used in investing activities		(30,195	)		(39,332	)

Cash flows from financing activities:
Revolving credit borrowings		5,300			45,148
Debt repayments		(1,854	)		(113	)
Issuance of common stock		3,297			3,165
Excess tax benefits from share-based payment arrangements		1,791			—
Other, net		(101	)		(707	)

Net cash flows provided by financing activities		8,433			47,493

Effect of exchange rate changes on cash		(178	)		(439	)

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

Cash and cash equivalents, end of period	$	11,999		$	21,188


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

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

The accompanying unaudited consolidated financial statements of 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, 2005.

2. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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


	MARCH 31,			DECEMBER 31,
	2006			2005
Accounts receivable, net:
Trade	$	266,363		$	236,936
Unbilled revenue		35,575			36,789
Other		2,207			2,514
Allowance for doubtful accounts		(1,849	)		(2,169	)

	$	302,296		$	274,070


	MARCH 31,			DECEMBER 31,
	2006			2005
Inventories, net:
Tubular goods	$	265,846		$	274,232
Other finished goods and purchased products		44,063			35,716
Work in process		35,495			30,288
Raw materials		29,054			26,412


Total inventories		374,458			366,648
Inventory reserves		(5,771	)		(5,722	)

	$	368,687		$	360,926


	ESTIMATED	MARCH 31,			DECEMBER 31,
	USEFUL LIFE	2006			2005
Property, plant and equipment, net:
Land		$	9,315		$	9,576
Buildings and leasehold improvements	5-40 years		58,740			60,049
Machinery and equipment	2-20 years		271,713			292,713
Rental tools	2-10 years		57,283			72,327
Office furniture and equipment	1-15 years		16,030			16,231
Vehicles	2-10 years		26,920			26,035
Construction in progress			26,975			22,283


Total property, plant and equipment			466,976			499,214
Less: Accumulated depreciation			(161,110	)		(188,762	)

		$	305,866		$	310,452


	MARCH 31,		DECEMBER 31,
	2006		2005
Accounts payable and accrued liabilities:
Trade accounts payable	$	160,722	$	168,445
Accrued compensation		13,046		22,529
Accrued insurance		5,367		4,820
Accrued taxes, other than income taxes		5,717		4,354
Reserves related to discontinued operations		3,510		3,527
Other		8,767		10,829

	$	197,129	$	214,504

3. EARNINGS PER SHARE (EPS)


	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

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 total consideration of $22.1 million, including transaction costs, plus a note payable to the former owners of $0.8 million. At the date of acquisition, Elenburg owned and operated 7 rigs which 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 total consideration of $96.1 million, including transaction costs and a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 29 locations in the United States, Canada, Central and 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. 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 total consideration of $31.2 million 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 total consideration of $8.7 million, 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.

Accounting for certain acquisitions made 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.

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


						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.

5. DEBT

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


	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

6. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING:

Comprehensive income for the three month periods ended March 31, 2006 and 2005 was as follows (in thousands):


	THREE MONTHS
	ENDED MARCH 31,
	2006		2005
Comprehensive income:
Net income	$	52,916	$	25,289
Other comprehensive income:
Cumulative translation adjustment		24		(1,021	)
Foreign currency hedge		41		23

Total comprehensive income	$	52,981	$	24,291


Shares of common stock outstanding — January 1, 2006	49,179,258

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

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

7. STOCK BASED COMPENSATION

We adopted Statement of Financial Accounting Standards No. 123 R (SFAS 123R) effective January 1, 2006. This pronouncement requires companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. Prior to the adoption of SFAS 123R, this accounting treatment was optional with pro forma disclosures required. We adopted SFAS 123R using the modified prospective transition method, which is explained below.

SFAS 123R is effective for all stock options we grant beginning January 1, 2006. For those stock option awards granted prior to January 1, 2006, but for which the vesting period is not complete, we used the modified prospective transition method permitted by SFAS 123R. Under this method of accounting, the remaining unamortized value of non-vested options will be expensed over the remaining vesting period using the grant-date fair values. Our options typically vest in equal annual installments over a four year service period. Expense related to an option grant is recognized on a straight line basis over the specific vesting period for those options.

The fair value of options is determined at the grant date using a Black-Scholes option pricing model, which requires us to make several assumptions. The risk-free interest rate is based on the U.S Treasury yield curve in effect for the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future. The expected market price volatility of our common stock is based on an estimate made by us that considers the historical and implied volatility of our common stock as well as a peer group of companies over a time period equal to the expected term of the option. The expected life of the options awarded in 2006 was based on a formula considering the vesting period and term of the options awarded as permitted by U.S. Securities and Exchange Commission regulations.

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 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 of our 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, and have a term of six years. The weighted-average fair value of options granted during the 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 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


		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.

8. INCOME TAXES

The Company’s income tax provision for the three months ended March 31, 2006 totaled $34.2 million, or 39.3%, of pretax income compared to $14.8 million, or 36.9% of pretax income, for the three months ended March 31, 2005. The effective rate was higher in the quarter ended March 31, 2006 because of a higher effective tax rate applicable to the gain recognized on the sale of our workover services business.

The 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 in the period management determined that the earnings will no longer be indefinitely invested outside the United States.

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 month periods ended March 31, 2006 and 2005 is summarized in the following table (in thousands):


	Revenues from		Depreciation		Operating
	unaffiliated		and		income			Capital
	customers		amortization		(loss)			expenditures		Total assets
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		78,272		2,609		10,065			2,560		305,159
Tubular Services		227,220		263		17,818			286		404,077
Corporate and Eliminations		—		27		(4,502	)		23		19,957

Total	$	496,231	$	12,886	$	79,203		$	26,542	$	1,412,221


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		66,491		2,432		5,268			3,241		287,131
Tubular Services		137,860		172		15,145			71		233,803
Corporate and Eliminations		—		22		(2,801	)		126		8,400

Total	$	331,946	$	10,228	$	42,214		$	17,147	$	1,001,165


(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.

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, we announced that we had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of 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 our previously reported fourth quarter 2004 results. We and independent counsel retained by our audit committee conducted separate investigations consisting of interviews and a thorough examination of the facts and circumstances in this matter. We voluntarily reported the results of our investigation to the Securities and Exchange Commission (the “SEC”) and fully cooperated with requests for information received from the SEC. On October 31, 2005, our counsel received a “Wells Notice” from the staff of the SEC indicating that the staff 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 Company reached a settlement agreement with the SEC on April 27, 2006. The Company consented to an Order by the SEC (Order), without admitting or denying the findings in the Order, that required the Company to cease and desist from committing or causing violations of the “books and records” and “internal control provisions” of the laws of the Securities and Exchange Act of 1934. The settlement did not require the Company to pay a monetary penalty.

This quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Exchange Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to “Item 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 our Form 10-K Annual Report for the year ended December 31, 2005 filed with the Securities and Exchange Commission on March 2, 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.

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, 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 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. 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 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.


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

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

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


	Average Rig Count for
	Three Months Ended March 31,
	2006		2005
U.S. Land		1,438		1,178
U.S. Offshore		81		101

Total U.S.		1,519		1,279
Canada (1)		665		521

Total North America		2,184		1,800


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

The average North American rig count for the three months ended March 31, 2006 increased by 384 rigs, or 21.3%, compared to the three months ended March 31, 2005. This overall increase in activity, while tempered somewhat by lower activity levels in the U.S. Gulf of Mexico did contribute to increased revenues in our tubular services and well site services segments. Our well site services segment results for the first three months of 2006 also benefited from capital spending, which aggregated $82.9 million for that segment in the twelve months ended March 31, 2006, the acquisition of Elenburg Exploration Company on February 1, 2005 for total consideration of $22.1 million, the acquisition of Stinger Wellhead Protection, Inc. and certain affiliated companies and related intellectual property (collectively, Stinger) for total consideration of $96.1 million in May and June 2005 and the impact of increased activity levels and pricing gains in certain business lines. The Canadian rig count increased 27.6% in the first three months of 2006 compared to the corresponding period in 2005. Our remote accommodations, catering and logistics services activities benefited from the Canadian rig count increase and from increased activities in the Northern Alberta oil sands area.

Repair activity resulting from Hurricanes Katrina and Rita have continued to benefit our offshore products and U.S. Gulf accommodations businesses. Decreased rig counts in the U.S. Gulf, however, have negatively affected our tubular services segment and our rental tool business.

During the first three months of 2006, the results generated by our Canadian workforce accommodations, catering and logistics operations benefited from the strengthening of the Canadian currency. In the first three months of 2006, the Canadian dollar was worth $0.87 U.S. dollars compared to $0.82 in the first three months of 2005, an increase of 6.1%.

On June 2, 2005 we acquired all of the outstanding stock of Phillips Casing and Tubing, Inc. (Phillips) for total consideration of $31.2 million. This acquisition resulted in increased OCTG inventory and revenues from the date of acquisition. Our tubular services segment shipped 126,700 tons of OCTG in the first three months of 2006 compared to 82,000 tons in the first three months of 2005. Our tubular services segment benefited in the quarter from a 22.1% year-over-year increase in average U.S. land drilling activity. Our OCTG business is particularly leveraged to gas drilling in high pressure, tight formations given the higher volume and quality of tubulars used in the drilling completion of such wells. OCTG 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 inventory. Our tubular services gross margins have declined compared to historically high levels reached in 2005. Tubular services gross margin as a percent of revenues decreased to 9.3% in the first quarter of 2006 from a gross margin percent of 13.0% in the first quarter of 2005 and 11.0% in the fourth quarter of 2005. These decreases are attributable to less frequent and smaller OCTG price increases in the quarter and to a higher mix of lower margin carbon grade OCTG products sold in response to increased land drilling activity. The lingering effects of the hurricanes on Gulf of Mexico drilling activity resulted in reduced demand for higher margin seamless alloy tubulars while strong land based drilling activity increased carbon grade sales.

Our offshore products segment reported a much improved first quarter of 2006 compared to the first quarter of 2005 as a result of increased activity and greater fixed cost absorption. Our offshore products backlog totaled $220.8 million at March 31, 2006, $110.7 million at December 31, 2005 and $99.8 million at 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 changes in backlog levels from one quarter to the next 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 2005 levels.

Our income tax provision for the first quarter of 2006 totaled $34.2 million, or 39.3% of pretax income compared to $14.8 million, or 36.9% of pretax income, for the first quarter of 2005. Our effective tax rate increased in the first three months of 2006 compared to the first three months of 2005 as a result of a higher tax rate applicable to the gain recognized on the sale of our 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 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 have increased their spending and commitments for deepwater offshore exploration and development which has benefited our offshore products segment. However, there can be no assurance that these trends will 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.

Results of Operations (in millions, except margin percentages)


	THREE MONTHS ENDED
	MARCH 31,
	2006			2005
Revenues
Well Site Services -
Accommodations	$	104.6		$	83.2
Rental tools		49.6			19.1
Drilling services		28.0			16.8
Workover services		8.5			8.5

Total Well Site Services		190.7			127.6
Offshore Products		78.3			66.5
Tubular Services		227.2			137.8

Total	$	496.2		$	331.9


Gross Margin
Well Site Services -
Accommodations	$	33.3		$	23.0
Rental tools		26.5			8.7
Drilling services		14.0			5.8
Workover services		3.2			1.7

Total Well Site Services		77.0			39.2
Offshore Products		19.9			14.1
Tubular Services		21.1			18.0

Total	$	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		25.4	%		21.2	%
Tubular Services		9.3	%		13.1	%
Total		23.8	%		21.5	%

Operating Income (Loss)
Well Site Services -
Accommodations	$	25.3		$	17.1
Rental tools		16.9			3.2
Drilling services		11.8			4.2
Workover services		1.8			0.1

Total Well Site Services		55.8			24.6
Offshore Products		10.1			5.3
Tubular Services		17.8			15.1
Corporate / Other		(4.5	)		(2.8	)

Total	$	79.2		$	42.2

THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005

Revenues. Total revenues increased $164.3 million, or 49.5%, to $496.2 million during the current quarter compared to revenues of $331.9 million during the quarter ended March 31, 2005. Offshore products revenues increased $11.8 million, or 17.7%, due to higher activity levels supporting offshore production facility construction. Tubular services revenues and tons shipped increased $89.4 million, or 64.9%, and 44,700 tons, or 54.5%,

respectively, in the quarter ended March 31, 2006 compared to the quarter ended 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 6.6% from the first quarter of 2005 to the first quarter of 2006. Well site services revenues increased $63.1 million, or 49.5%, to $190.7 million during the current quarter compared to $127.6 million during the quarter ended March 31, 2005. Our drilling services revenues increased $11.2 million, or 66.7%, because of contributions from the Elenburg acquisition which added 7 rigs in February 2005, higher dayrates earned and 3 newly built rigs added to the 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 Venezuela in 2006. The rental tools business generated revenues in the first quarter of 2006 of $49.6 million, which were $30.5 million, or 159.7%, higher than the first quarter of 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 contributed materially to the increase in revenues generated from our rental tools business line. Accommodations revenues in the first quarter of 2006 were $21.4 million, or 25.7%, higher than accommodations revenues reported in the first quarter of 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 $46.7 million, or 65.5%, from $71.3 million in the quarter ended March 31, 2005 to $118.0 million in the quarter ended March 31, 2006. Overall margins as a percentage of revenue improved from 21.5% for the first quarter of 2005 to 23.8% of revenues in the first quarter of 2006 due to improving gross margins in all of 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 $19.9 million in the first quarter of 2006 compared to $14.1 million in the same period of the prior year representing an increase of 41.1%. Offshore products gross margin percentage improved from 21.2% in the first quarter of 2005 to 25.4% in the first quarter of this year due to higher activity which resulted in greater overhead absorption, higher margins on hurricane repair equipment and also to increased connector products sold in the current quarter.

Tubular services gross margins increased by $3.1 million, or 17.2%, in the three months ended March 31, 2006 compared to the three months ended March 31, 2005 as a result of 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 9.3% in the first quarter of 2006 compared to 13.1% in the first quarter of 2005 because of less frequent and smaller OCTG price increases, 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 first quarter of 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 $37.8 million, or 96.4%, during the quarter ended March 31, 2006 compared to the quarter ended March 31, 2005. Drilling services gross margins in the first quarter of 2006 totaled $14.0 million compared to $5.8 million in the first quarter of 2005, an increase of $8.2 million, or 141.4%. The drilling services gross margin percentage improved to 50.0% of revenues in the first quarter of 2006 from 34.5% of revenues in the first quarter of 2005 due primarily to higher dayrates in 2006 and a move from billing on a footage rate basis to billing on a dayrate basis for most of our drilling rigs. Rental tools gross margins totaled $26.5 million in the first quarter of 2006 compared to $8.7 million in the first quarter of 2005, an increase of $17.8 million, or 204.6%. Rental tools gross margin percentage increased from 45.5% for the first quarter of 2005 to 53.4% in the first quarter of 2006. The improvement in gross margins and gross margin as a percentage of revenues resulted primarily from the positive impact of the Stinger acquisition and pricing improvements realized. Workover gross margins improved to $3.2 million in the two months ended February 28, 2006 compared to $1.7 million in the three months ended 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 $23.0 million in the first quarter of 2005, an increase of $10.3 million, or 44.8%. The gross margin percentage increased to 31.8% in the first quarter of 2006 compared to a 27.6% gross margin percentage for the first quarter of 2005 due to the benefits of

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 $6.3 million, or 33.5%, in the first quarter of 2006 compared to the same period in 2005. During the three months ended March 31, 2006, SG&A totaled $25.4 million, or 5.1% of revenues, compared to SG&A of $19.1 million, or 5.7% of revenues, for the three months ended March 31, 2005. Increased SG&A expense associated with acquisitions completed since the first quarter of 2005, increased stock compensation expense due to the implementation of SFAS No. 123R which required the expensing of stock options beginning January 1, 2006 and increased incentive compensation accruals were the primary factors causing increased SG&A in 2006 compared to 2005.

Depreciation and Amortization. Depreciation and amortization expense increased $2.7 million, or 26.0%, in the first quarter 2006 compared to the first quarter 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 $37.0 million, or 87.7%, to $79.2 million for the quarter ended March 31, 2006 from $42.2 million for the quarter ended March 31, 2005. Offshore products operating income increased $4.8 million, tubular services operating income increased $2.7 million and well site services operating income increased $31.2 million. These increases were partially offset by higher corporate costs of $1.7 million.

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

Income Tax Expense. Income tax expense totaled $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 March 31, 2005. Our effective tax rate was higher in the first quarter of 2006 because of a higher effective tax rate applicable to the gain recognized on the sale of our workover services 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 rigs and rental tool assets, 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 proceeds from our $175 million convertible note offering in 2005.

Cash totaling $18.7 million was provided by operations during the quarter ended March 31, 2006 compared to cash used in operating activities totaling $6.1 million in the quarter ended March 31, 2005. During the first quarter of 2006, $38.0 million was used to fund working capital. Receivables increased seasonally in our Canadian accommodations business and inventories increased in our accommodations and offshore products segments.

Cash was used in investing activities during the quarters ended March 31, 2006 and 2005 in the amount of $30.2 million and $39.3 million, respectively. Capital expenditures totaled $26.5 million and $17.1 million during the quarters ended March 31, 2006 and 2005, respectively. Capital expenditures in both periods consisted principally of the purchase of assets for our well site services segment. We completed acquisitions for net cash consideration totaling $22.6 million during the first quarter of 2005.

We currently expect to spend a total of approximately $125.0 million for capital expenditures during 2006, for maintenance and upgrade of our equipment and facilities and also to expand our product and service offerings. We

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

Net cash of $8.4 million and $47.5 million were provided by financing activities during the quarters ended March 31, 2006 and 2005, respectively, primarily as a result of borrowings made under our revolving credit facility. During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50 million of our common stock, par value $.01 per share, over a two year period. Through March 31, 2006, a total of $30 million of our stock (1,183,432 shares), has been repurchased under this program. No shares of our stock were repurchased during the three months ended March 31, 2006 leaving a total of up to $20 million 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 our leverage ratio, on the unused commitments under the Credit Agreement. During the first quarter of 2006, our applicable margin over LIBOR was 1.25%. Our weighted average interest rate paid under the Credit Agreement was 5.8% during the quarter ended March 31, 2006 and 4.2% for the quarter ended March 31, 2005.

As of March 31, 2006, we had $226.9 million outstanding under the Credit Facility and an additional $10.9 million of outstanding letters of credit, leaving $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 $8.5 million. We had no borrowings outstanding under these other facilities as of March 31, 2006. Our total debt represented 37.1% of our total capitalization at 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 income tax provision for the three months ended March 31, 2006 totaled $34.2 million, or 39.3% of pretax income, compared to $14.8 million, or 36.9% of pretax income, for the three months ended March 31, 2005.

We currently estimate that our effective tax rate for the full year 2006 will approximate 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 $4.4 million of our NOLs to offset taxable income generated by the Company during the tax year ended December 31, 2006. The income statement benefit of substantially all of our NOLs has been recognized in prior periods.

Critical Accounting Policies

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

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

We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, interest, 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 other than a temporary decline in value, would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether an other than temporary decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.

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

Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required.

The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.

Since the adoption of SFAS No. 123R – 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 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 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 March 31, 2006, we had floating rate obligations totaling approximately $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 March 31, 2006 levels, our consolidated interest expense would increase by a total of approximately $2.3 million annually.

Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in currencies other than the U.S. dollar, which is our functional currency or the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks, we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. In the past, we have hedged U.S. dollar balances and cash flows in our U.K. subsidiary; however, no active hedges exist as of March 31, 2006. Results of operations have not been materially affected by foreign currency hedging activity.

ITEM 4. Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2006 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to allow disclosure as required in this Quarterly Report on Form 10-Q. During the three months ended March 31, 2006, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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 Months Ended March 31, 2006 and 2005		3
	Consolidated Balance Sheets — March 31, 2006 (unaudited) and December 31, 2005		4
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2006 and 2005		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 – 21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		22

Item 4.	Controls and Procedures		22

	Part II — OTHER INFORMATION

Item 1.	Legal Proceedings		23

Item 1A.	Risk Factors		23

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		23

Item 3.	Defaults Upon Senior Securities		23

Item 4.	Submission of Matters to a Vote of Security Holders		23

Item 5.	Other Information		23

Item 6.	Exhibits		24

	(a) Index of Exhibits		24

	Signature Page		25
Non-Employee Director Compensation Summary
Certification of CEO pursuant to Rules 13a-14(a)or 15d-14(a)
Certification of CFO pursuant to Rules 13a-14(a)or 15d-14(a)
Certification of CEO pursuant to Rules 13a-14(b)or 15d-14(b)
Certification of CFO pursuant to Rules 13a-14(b)or 15d-14(b)


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.


*		Filed herewith

**		Management contracts or compensation plans or arrangements

***		Furnished herewith.



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.

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