OIL STATES INTERNATIONAL, INC - Quarter Report: 2007 September (Form 10-Q)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2007

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

For the transition period from                      to                     

OIL STATES INTERNATIONAL, INC.

(Exact name of registrant as specified in its charter)

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

(713) 652-0582

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year,

if changed since last report)

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

YES þ      NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 50,096,856 shares of common stock outstanding and 2,090,954 shares of treasury stock as of October 22, 2007.

 

 

OIL STATES INTERNATIONAL, INC.

INDEX

		Page No.
Part I — FINANCIAL INFORMATION
Item 1. Financial Statements:
Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Statements of Income for the Three and Nine Month Periods Ended September 30, 2007 and 2006			3
Consolidated Balance Sheets — September 30, 2007 (unaudited) and December 31, 2006			4
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006			5
Notes to Unaudited Condensed Consolidated Financial Statements			6 — 12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			13 — 23
Item 3. Quantitative and Qualitative Disclosures About Market Risk			23
Item 4. Controls and Procedures			23 — 24
Part II — OTHER INFORMATION
Item 1. Legal Proceedings			24
Item 1A. Risk Factors			24
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities			24 — 25
Item 3. Defaults Upon Senior Securities			25
Item 4. Submission of Matters to a Vote of Security Holders			25
Item 5. Other Information			25
Item 6. Exhibits			25 — 26
(a) Index of Exhibits			25 — 26
Signature Page			27
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

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

		THREE MONTHS ENDED								NINE MONTHS ENDED
		SEPTEMBER 30,								SEPTEMBER 30,
		2007				2006				2007				2006
Revenues		$	527,440			$	479,463			$	1,507,264			$	1,439,053
Costs and expenses:
Cost of sales			403,369				363,007				1,145,882				1,094,926
Selling, general and administrative expenses			30,884				27,414				86,433				79,611
Depreciation and amortization expense			18,788				13,880				49,320				39,762
Other operating (income)/expense			(374	)			(330	)			(516	)			56
			452,667				403,971				1,281,119				1,214,355
Operating income			74,773				75,492				226,145				224,698
Interest expense			(4,217	)			(4,797	)			(12,798	)			(14,531	)
Interest income			890				714				2,599				1,670
Equity in earnings of unconsolidated affiliates			753				2,637				2,043				4,624
Gain on sale of workover services business			—				—				—				11,250
Gain on sale of investment			—				—				12,774				—
Other income			243				1,866				595				2,111
Income before income taxes			72,442				75,912				231,358				229,822
Income tax expense			(21,964	)			(25,860	)			(76,186	)			(81,549	)
Net income		$	50,478			$	50,052			$	155,172			$	148,273
Net income per share:
Basic		$	1.02			$	1.01			$	3.14			$	2.99
Diluted		$	0.97			$	0.99			$	3.05			$	2.91
Weighted average number of common shares outstanding:
Basic			49,661				49,736				49,423				49,514
Diluted			51,822				50,475				50,883				50,909

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In Thousands)

		SEPTEMBER 30,				DECEMBER 31,
		2007				2006
		(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents		$	29,201			$	28,396
Accounts receivable, net			414,211				351,701
Inventories, net			355,704				386,182
Prepaid expenses and other current assets			33,967				17,710
Total current assets			833,083				783,989
Property, plant, and equipment, net			538,842				358,716
Goodwill, net			390,741				331,804
Investments in unconsolidated affiliates			23,604				38,079
Other non-current assets, net			75,521				58,506
Total assets		$	1,861,791			$	1,571,094
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt		$	179,659			$	6,873
Accounts payable and accrued liabilities			252,802				199,842
Income taxes			4,062				11,376
Deferred revenue			46,167				58,645
Other current liabilities			739				3,680
Total current liabilities			483,429				280,416
Long-term debt			253,376				391,729
Deferred income taxes			40,482				38,020
Other liabilities			27,300				21,093
Total liabilities			804,587				731,258
Stockholders’ equity:
Common stock			522				511
Additional paid-in capital			399,963				372,043
Retained earnings			642,512				487,627
Accumulated other comprehensive income			72,365				30,183
Treasury stock			(58,158	)			(50,528	)
Total stockholders’ equity			1,057,204				839,836
Total liabilities and stockholders’ equity		$	1,861,791			$	1,571,094

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)

		NINE MONTHS
		ENDED SEPTEMBER 30,
		2007				2006
Cash flows from operating activities:
Net income		$	155,172			$	148,273
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			49,320				39,762
Deferred income tax provision			5,053				1,411
Excess tax benefits from share-based payment arrangements			(8,116	)			(4,966	)
Equity in earnings of unconsolidated subsidiaries			(2,043	)			(4,624	)
Non-cash compensation charge			5,872				5,815
Gain on sale of investment			(12,774	)			—
Non-cash gain on sale of workover services business			—				(11,250	)
Gain on disposal of assets			(1,454	)			(3,102	)
Other, net			214				1,895
Changes in working capital			25,095				(73,359	)
Net cash flows provided by operating activities			216,339				99,855
Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired			(102,159	)			(99	)
Cash balances of workover services business sold			—				(4,366	)
Capital expenditures			(172,068	)			(104,114	)
Proceeds from sale of investment			29,354				—
Proceeds from sale of equipment			2,685				8,069
Other, net			(681	)			(1,068	)
Net cash flows used in investing activities			(242,869	)			(101,578	)
Cash flows from financing activities:
Revolving credit borrowings (repayments)			24,219				(1,563	)
Debt repayments			(6,918	)			(2,236	)
Issuance of common stock			10,601				8,275
Purchase of treasury stock			(12,211	)			(10,083	)
Excess tax benefits from share-based payment arrangements			8,116				4,966
Other, net			(431	)			(194	)
Net cash flows provided by (used in) financing activities			23,376				(835	)
Effect of exchange rate changes on cash			4,450				570
Net increase (decrease) in cash and cash equivalents from continuing operations			1,296				(1,988	)
Net cash used in discontinued operations — operating activities			(491	)			(112	)
Cash and cash equivalents, beginning of period			28,396				15,298
Cash and cash equivalents, end of period		$	29,201			$	13,198
Non-cash investing activities:
Receipt of stock and notes for hydraulic workover services business in merger transaction, net of unrecognized gain of $9.4 million (See Note 11)			—			$	50,105
Non-cash financing activities:
Reclassification of 2 3/8% contingent convertible senior notes to current liabilities		$	175,000				—
Borrowings and assumption of liabilities for business and asset acquisitions and related intangibles			9,000				514

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

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

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

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

     From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

     The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2006.

2. RECENT ACCOUNTING PRONOUNCEMENT

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (SFAS 157), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. The Company has not implemented and is currently evaluating the impact of SFAS 157, but does not expect the adoption of SFAS 157 to have a material impact on its results from operations or financial position.

     In February 2007, the FASB issued SFAS No. 159 (SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115.” SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company has not implemented and is currently evaluating the impact of SFAS 159, but does not expect the adoption of SFAS 159 to have a material impact on its results from operations or financial position.

     In August 2007, the FASB issued proposed FASB Staff Position (FSP) No. APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which, if issued, would change the accounting for our 2 3/8% Contingent Convertible Senior Subordinated Notes (2 3/8% Notes). Under the proposed new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity would be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the proposed

new rules on our 2 3/8% Notes is that the equity component would be classified as part of stockholders’ equity on our balance sheet and the value of the equity component would be treated as an original issue discount for purposes of accounting for the debt component of the 2 3/8% Notes. Higher non-cash interest expense would result by recognizing the accretion of the discounted carrying value of the 2 3/8% Notes as interest expense over the estimated life of the 2 3/8% Notes using an effective interest rate method of amortization. However, there would be no effect on our cash interest payments. The proposed FSP is expected to be effective for fiscal years beginning after December 15, 2007 and will require retrospective application. The Company is currently evaluating the impact of this proposed FSP.

     See also Note 9 – Income Taxes and Change in Accounting Principle for a discussion of the FASB’s Interpretation No. 48 – Accounting for Uncertainty in Income Taxes.

3. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS

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

		SEPTEMBER 30,				DECEMBER 31,
		2007				2006
Accounts receivable, net:
Trade		$	321,843			$	269,136
Unbilled revenue			88,124				83,782
Other			7,803				1,726
Allowance for doubtful accounts			(3,559	)			(2,943	)
		$	414,211			$	351,701

		SEPTEMBER 30,				DECEMBER 31,
		2007				2006
Inventories, net:
Tubular goods		$	208,551			$	261,785
Other finished goods and purchased products			60,708				50,095
Work in process			44,534				45,848
Raw materials			49,855				35,642
Total inventories			363,648				393,370
Inventory reserves			(7,944	)			(7,188	)
		$	355,704			$	386,182

		ESTIMATED				SEPTEMBER 30,				DECEMBER 31,
		USEFUL LIFE				2007				2006
Property, plant and equipment, net:
Land						$	11,979			$	9,112
Buildings and leasehold improvements		5-50 years					96,301				77,853
Machinery and equipment		2-20 years					429,528				326,977
Rental tools		1-10 years					98,909				64,178
Office furniture and equipment		1-10 years					22,327				18,832
Vehicles		4-10 years					47,112				31,541
Construction in progress							72,836				18,811
Total property, plant and equipment							778,992				547,304
Less: Accumulated depreciation							(240,150	)			(188,588	)
						$	538,842			$	358,716

		SEPTEMBER 30,				DECEMBER 31,
		2007				2006
Accounts payable and accrued liabilities:
Trade accounts payable		$	191,744			$	142,204
Accrued compensation			27,140				29,058
Accrued insurance			5,952				5,836
Accrued taxes, other than income taxes			7,993				3,317
Reserves related to discontinued operations			2,866				3,357
Other			17,107				16,070
		$	252,802			$	199,842

4. EARNINGS PER SHARE

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

		THREE MONTHS ENDED								NINE MONTHS ENDED
		SEPTEMBER 30,								SEPTEMBER 30,
		2007				2006				2007				2006
Basic earnings per share:
Net income		$	50,478			$	50,052			$	155,172			$	148,273
Weighted average number of shares outstanding			49,661				49,736				49,423				49,514
Basic earnings per share		$	1.02			$	1.01			$	3.14			$	2.99
Diluted earnings per share:
Net income		$	50,478			$	50,052			$	155,172			$	148,273
Weighted average number of shares outstanding			49,661				49,736				49,423				49,514
Effect of dilutive securities:
Options on common stock			649				670				659				852
2 3/8% Convertible Senior Subordinated Notes			1,421				23				721				489
Restricted stock awards and other			91				46				80				54
Total shares and dilutive securities			51,822				50,475				50,883				50,909
Diluted earnings per share		$	0.97			$	0.99			$	3.05			$	2.91

5. BUSINESS ACQUISITIONS AND GOODWILL

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

     In July 2007, we acquired substantially all of the assets of Wire Line Service, Ltd. (“Well Testing”), a Midland, Texas business that primarily provides well testing and flowback services through its locations in Texas and New Mexico for total consideration of $44.2 million, including transaction costs and a $3.0 million note payable to the seller that bears interest at 6% and is payable in two equal annual installments beginning one year from the July 2, 2007 date of the closing of the transaction. The operations of Well Testing have been included in the rental tools business within the well site services segment.

     In August 2007, we completed the acquisition of substantially all of the assets of Schooner Petroleum Services, Inc. (“Schooner”). Schooner, headquartered in Houston, Texas, primarily provides completion-related rental tools and services through eleven locations in Texas, Louisiana, Wyoming and Arkansas. The consideration for the assets acquired totaled approximately $67.5 million, including transaction costs and net of cash acquired and a $6.0 million note payable to the seller that bears interest at 6% and is payable in two equal annual installments beginning one year from the August 2, 2007 date of the closing of the transaction. The operations of Schooner have been included in the rental tools business within the well site services segment.

     The cash consideration for these acquisitions was funded with amounts available under the Company’s existing credit facility. As of September 30, 2007, the total purchase consideration for these acquisitions has been allocated as follows: working capital $15.6 million; property, plant and equipment $27.9 million; goodwill $49.9 million and other intangible assets $18.3 million. The allocation of purchase price for these acquisitions is still being finalized.

     Changes in the carrying amount of goodwill for the nine month period ended September 30, 2007 are as follows (in thousands):

		Balance as of				Acquisitions				Foreign currency				Balance as of
		January 1,				and				translation and				September 30,
		2007				adjustments				other changes				2007
Offshore Products		$	75,716			$	—			$	295			$	76,011
Tubular Services			62,453				410				—				62,863
Well Site Services			193,635				49,946				8,286				251,867
Total		$	331,804			$	50,356			$	8,581			$	390,741

6. DEBT

     As of September 30, 2007 and December 31, 2006, long-term debt consisted of the following (in thousands):

		September 30,				December 31,
		2007				2006
		(Unaudited)
U.S. revolving credit facility, with available commitments up to $300 million and with an average interest rate of 6.3% for the nine month period ended September 30, 2007		$	166,000			$	186,200
Canadian revolving credit facility, with available commitments up to $100 million and with an average interest rate of 5.4% for the nine month period ended September 30, 2007			81,301				29,177
2 3/8% contingent convertible senior subordinated notes due 2025			175,000				175,000
Subordinated unsecured notes payable to sellers of businesses, interest ranging from 5% to 6%, maturing in 2007 to 2009			9,000				6,689
Capital lease obligations and other debt			1,734				1,536
Total debt			433,035				398,602
Less: current maturities			(179,659	)			(6,873	)
Total long-term debt		$	253,376			$	391,729

     The $175.0 million of 2 3/8% Notes are convertible into cash and common stock of the Company at $31.75 per share (Conversion Price) only upon the occurrence of certain events prior to July 1, 2023. Upon conversion, a holder will receive cash for the principal amount of each note and shares of the Company’s common stock for the conversion value in excess of such principal amount. Based upon the closing price of the Company’s common stock for the prescribed measurement periods during the quarter ended September 30, 2007, the contingent conversion conditions on the 2 3/8% Notes were met. As a result, the 2 3/8% Notes were convertible at the option of the holder as of September 30, 2007, and, as such, the principal balance of the notes has been classified as a current liability. The holders of the 2 3/8% Notes may convert their notes only during the quarter ended December 31, 2007 based on the share price performance during measurement periods in the quarter ended September 30, 2007. The future convertibility and resultant balance sheet classification of this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company’s common stock during prescribed measurement periods.

7. COMPREHENSIVE INCOME AND CHANGES IN COMMON STOCK OUTSTANDING:

     Comprehensive income for the three and nine months ended September 30, 2007 and 2006 was as follows (in thousands):

		THREE MONTHS								NINE MONTHS
		ENDED SEPTEMBER 30,								ENDED SEPTEMBER 30,
		2007				2006				2007				2006
Comprehensive income:
Net income		$	50,478			$	50,052			$	155,172			$	148,273
Other comprehensive income:
Cumulative translation adjustment			18,538				661				42,182				12,281
Foreign currency hedge			—				—				—				41
Total comprehensive income		$	69,016			$	50,713			$	197,354			$	160,595

Shares of common stock outstanding — January 1, 2007			49,296,740
Shares issued upon exercise of stock options and vesting of stock awards			1,051,667
Shares withheld for taxes on vesting of restricted stock awards and transferred to treasury			(12,051	)
Repurchase of shares — held in treasury			(240,000	)
Shares of common stock outstanding — September 30, 2007			50,096,356

8. STOCK BASED COMPENSATION

     During the first nine months of 2007, we granted restricted stock awards totaling 197,563 shares valued at $6.3 million. A total of 162,707 of these awards vest in four equal annual installments, 15,860 of these awards vest in three annual installments, 3,800 of these awards vest in two annual installments and the remaining 15,196 awards vest after one year.

     Stock based compensation pre-tax expense recognized in the nine month periods ended September 30, 2007 and September 30, 2006 totaled $5.9 million and $5.8 million, or $0.08 and $0.07 per diluted share after tax, respectively. For the three month periods ended September 30, 2007 and September 30, 2006, our stock compensation pre-tax expense totaled $2.2 million and $1.6 million, or $0.03 and $0.02 per diluted share after tax, respectively. At September 30, 2007, $16.2 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized. The total fair value of restricted stock awards that vested during the nine months ended September 30, 2007 was $2.2 million.

9. INCOME TAXES AND CHANGE IN ACCOUNTING PRINCIPLE

     The Company’s income tax provision for the three months and nine months ended September 30, 2007 totaled $22.0 million, or 30.3%, of pretax income and $76.2 million, or 32.9%, of pretax income, respectively, compared to $25.9 million, or 34.1%, of pretax income for the three months ended September 30, 2006 and $81.5 million, or 35.5%, of pretax income for the nine months ended September 30, 2006. Adjustments made to the Company’s income tax liabilities upon the filing of its 2006 federal tax return in the third quarter of 2007 compared to income tax liabilities estimated at the time of the finalization of the December 31, 2006 consolidated financial statements and the completion of the IRS audit of the Company’s 2004 federal income tax return lowered the effective tax rate in the three and nine month periods ended September 30, 2007. In addition, our effective tax rates were higher in 2006 than 2007 because of the higher effective tax rate applicable to the gain on the sale of the workover services business recognized in 2006.

     In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (FIN 48), which became effective for the Company on January 1, 2007. The Interpretation prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The adoption of FIN 48 has resulted in a transition adjustment reducing beginning retained earnings by $0.3 million; $0.2 million in taxes and $0.1 million in interest. Had the transition adjustment not been recognized as an adjustment of beginning retained earnings, it would have affected the effective tax rate. Interest costs and penalties related to income taxes are classified as income tax expense.

     The total amount of unrecognized tax benefits as of September 30, 2007 was $3.0 million, including $0.4 million of accrued interest. An examination of the Company’s consolidated U.S. federal return for the year 2004 by the Internal Revenue Service was completed during the third quarter of 2007. No significant adjustments were proposed as a result of this examination. Tax years subsequent to 2004 remain open to U.S. federal tax audit and, because of net operating losses (NOL’s) utilized by the Company, years from 1994 to 2002 remain subject to federal tax audit with respect to NOL’s available for tax carryforward. Our Canadian subsidiaries’ federal tax returns since 2003 are subject to audit by Canada Revenue Agency.

10. SEGMENT AND RELATED INFORMATION

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

Canadian business related to the provision of work force accommodations, catering and logistics services are seasonal with significant activity occurring in the peak winter drilling season. 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) (Boots & Coots) and a note receivable – See Note 11.

     Financial information by business segment for each of the three and nine months ended September 30, 2007 and 2006 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 September 30, 2007
Well Site Services —
Accommodations		$	65,894			$	5,972			$	16,147			$	43,444			$	421,698
Rental tools			73,602				6,580				19,825				11,594				412,073
Drilling and other (1)			40,216				3,215				12,908				10,808				172,993
Total Well Site Services			179,712				15,767				48,880				65,846				1,006,764
Offshore Products			132,124				2,612				22,074				4,156				441,767
Tubular Services			215,604				351				9,529				1,455				379,462
Corporate and Eliminations			—				58				(5,710	)			56				33,798
Total		$	527,440			$	18,788			$	74,773			$	71,513			$	1,861,791
Three months ended September 30, 2006
Well Site Services —
Accommodations		$	63,973			$	4,589			$	13,802			$	18,092			$	289,957
Rental tools			53,320				4,231				18,775				6,636				265,725
Drilling and other (1)			37,126				2,045				14,473				19,494				160,785
Total Well Site Services			154,419				10,865				47,050				44,222				716,467
Offshore Products			110,038				2,713				16,342				2,987				378,145
Tubular Services			215,006				272				16,629				398				419,001
Corporate and Eliminations			—				30				(4,529	)			9				14,124
		$	479,463			$	13,880			$	75,492			$	47,616			$	1,527,737

		Revenues from				Depreciation				Operating
		unaffiliated				and				income				Capital				Total
		customers				amortization				(loss)				expenditures				assets
Nine months ended September 30, 2007
Well Site Services —
Accommodations		$	221,311			$	14,722			$	64,291			$	99,337			$	421,698
Rental tools			178,082				16,443				51,437				29,449				412,073
Drilling and other (1)			107,886				8,758				34,719				30,082				172,993
Workover services (1)			—				—				—				—				—
Total Well Site Services			507,279				39,923				150,447				158,868				1,006,764
Offshore Products			386,601				8,237				63,889				10,565				441,767
Tubular Services			613,384				1,005				27,973				2,349				379,462
Corporate and Eliminations			—				155				(16,164	)			286				33,798
Total		$	1,507,264			$	49,320			$	226,145			$	172,068			$	1,861,791
Nine months ended September 30, 2006
Well Site Services —
Accommodations		$	243,577			$	12,191			$	54,743			$	48,126			$	289,957
Rental tools			149,685				12,465				49,785				17,941				265,725
Drilling and other (1)			97,349				5,550				39,860				29,832	(2)			160,785
Workover services (1)			8,544				650				1,922				263				—
Total Well Site Services			499,155				30,856				146,310				96,162				716,467
Offshore Products			281,984				8,013				41,592				7,347				378,145
Tubular Services			657,914				805				51,470				1,040				419,001
Corporate and Eliminations			—				88				(14,674	)			66				14,124
Total		$	1,439,053			$	39,762			$	224,698			$	104,615			$	1,527,737

11. WORKOVER SERVICES BUSINESS TRANSACTION

     Effective March 1, 2006, we completed a transaction to combine our workover services business with 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 $21.2 million.

     As a result of the closing of the transaction, we initially owned 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 their shares we received in the transaction and also allowing us certain rights to include our shares of common stock of Boots & Coots in a registration statement they filed. A shelf registration statement was filed by Boots and Coots and it was finalized and effective in the fourth quarter of 2006. The transaction terms also allowed us to designate three additional members to Boots & Coots’ existing five-member Board of Directors, which we have done.

     The closing of the transaction resulted in a non-cash pretax gain of $20.7 million of which, 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, $9.4 million ($9.6 million as of March 31, 2006) was not recognized in connection with the initial sale of our workover services business. 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, in the first quarter of 2006. We 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 unrecognized gain on the sale of the workover services business and to goodwill.

     In April 2007, the Company sold, pursuant to a registration statement filed by Boots & Coots, 14,950,000 shares of Boots & Coots stock that it owned for net proceeds of $29.4 million and, as a result, we recognized a net after tax gain of $8.4 million, or approximately $0.17 per diluted share in the second quarter of 2007. After the sale of Boots & Coots shares by the Company and the sale of primary shares of stock directly by Boots & Coots in April 2007, the Company’s ownership interest in Boots & Coots was reduced to approximately 15%. The equity method of accounting will continue to be used to account for the Company’s remaining investment in Boots & Coots common stock (11.5 million shares). The carrying value of the Company’s remaining investment in Boots & Coots stock totals $18.7 million as of September 30, 2007.

12. 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.

     This quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Exchange Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to Item “Part I, Item 1.A. Risk Factors” and the financial statement line item discussions set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K Annual Report for the year ended December 31, 2006 filed with the Securities and Exchange Commission on February 28, 2007 and Item 2 of this Form 10-Q, which follows. Should one or more of these risks or uncertainties materialize, or should the assumptions prove incorrect, actual results may differ materially from those expected, estimated or projected. Our management believes these forward-looking statements are reasonable. However, you should not place undue reliance on these forward-looking statements, which are based only on our current expectations. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.

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

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

Overview

     We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices 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 and pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs. In this segment, we are particularly influenced by deepwater drilling and production activities, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales and gross margins of our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled (for example, deepwater wells usually require higher priced seamless alloy tubulars) and the level of oil country tubular goods (OCTG) inventory and pricing. Historically, tubular services’ gross margin expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. In our well site services business segment, we provide land drilling services, work force accommodations, 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, completion and workover activity in the U.S. and Canada. Our accommodations business is conducted primarily in Canada and its activity levels are driven by oil sands development in Northern Alberta, oil and gas drilling activity, and to a lesser extent mining activities.

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

		Average Drilling Rig Count for the
		Three Months Ended								Nine Months Ended
		September 30,				September 30,				September 30,				September 30,
		2007				2006				2007				2006
U.S. Land			1,716				1,624				1,682				1,533
U.S. Offshore			72				95				77				91
Total U.S.			1,788				1,719				1,759				1,624
Canada (1)			348				494				340				480
Total North America			2,136				2,213				2,099				2,104

     The average North American rig count for the nine months ended September 30, 2007 decreased by 5 rigs, or 0.2%, compared to the nine months ended September 30, 2006. The increases in U.S. land rig counts have contributed to increased well site services revenues, particularly in our U.S. rental tool and land drilling businesses. However, decreased Canadian rig counts, compared to the first nine months of 2006, have adversely impacted our rental tools and accommodations, catering and logistical services which support Canadian oil and gas drilling operations. These decreases in Canada were partially offset in the first nine months of 2007 by growth in accommodations, catering and logistical services in support of oil sands development in Canada. For the third quarter of 2007, increased accommodations, catering and logistical services revenues in support of oil sands development in Canada compared to the third quarter of 2006 more than offset the impact of decreased Canadian oil and gas drilling operations. Our well site services segment results for the first nine months of 2007 also benefited from capital spending, which aggregated $180 million in the twelve months ended September 30, 2007 in that segment and included $33 million in our drilling services business and $111 million in our accommodations business, and the acquisitions discussed below of two rental tool companies for aggregate consideration of $112 million.

     During the first nine months of 2007, the results generated by our Canadian workforce accommodations, catering and logistics operations benefited from the strengthening of the Canadian currency. In the first nine months of 2007, the Canadian dollar was valued at an average exchange rate of $0.91 U.S. dollars compared to $0.88 in the first nine months of 2006, an increase of 3.4%. The Canadian dollar to U.S. dollar exchange rate averaged $0.96 in the third quarter of 2007 compared to $0.89 in the third quarter of 2006, an increase of 7.9%.

     Our 2007 capital expenditures are estimated to total $254 million and include $230 million to be spent in well site services, $20 million for offshore products and $4 million for tubular services and other areas. We continue to increase our capital commitments for the expansion of large accommodations facilities in support of oil sands development activities in Canada. Our well site services 2007 estimated capital expenditures consist of $137 million for accommodations, including $132 million for Canadian accommodations related projects, $51 million for rental tools and $42 million for drilling services.

     We continue to seek to acquire businesses that we believe are a good strategic fit with our existing businesses. In July and August we acquired two rental tool businesses for total consideration of $112 million, which was funded primarily with borrowings under our bank credit facility. The acquired businesses provide well testing and flowback services and completion – related rental tools in the U.S. market. The results of operations of the acquired businesses have been included in the rental tools business within the well site services segment.

     Management believes that, based on the current economic environment, oil and gas producers will continue to explore for and develop oil and gas reserves at an active pace in spite of continued volatility in current U.S. domestic natural gas and crude oil prices, given their longer term views of supply and demand fundamentals. Management estimates that approximately 55% to 65% of the Company’s revenues are dependent on North American natural gas drilling and completion activity with a significant amount of such revenues being derived from lower margin OCTG sales. As such, we estimate that our profitability is more evenly impacted by oil driven activity and natural gas driven activity. Our customers have increased their spending and commitments for deepwater offshore exploration and development which has benefited our offshore products segment. Our customers have also announced significant levels of expenditures for oil sands related projects in Canada. We see continued growth in activity for our accommodations business in the oil sands region as labor needs in the region are expected to double

over the next three to five years. We continue to focus on expansion opportunities and execution initiatives in these high growth markets supporting deepwater development and Canadian oil sands spending.

     There can be no assurance that these trends will continue, and there is a risk that lower energy prices for sustained periods could negatively impact drilling and completion activity and, correspondingly, reduce oil and gas expenditures. Such a decline would be adverse to our business. In addition, particularly in our well site services segment, we must continue to monitor industry capacity additions in relationship to our own capital expenditures and expected returns, considering project risks and expected cash flows from such investments. In tubular services, we continue to monitor industry wide OCTG inventory levels, mill shipments, OCTG pricing and our inventory turnover levels.

Consolidated Results of Operations (in millions)

		THREE MONTHS ENDED																NINE MONTHS ENDED
		September 30,																September 30,
										Variance																Variance
										2007 vs. 2006																2007 vs. 2006
		2007				2006				$				%				2007				2006				$				%
Revenues
Well Site Services —
Accommodations		$	65.9			$	64.0			$	1.9				3	%		$	221.3			$	243.6			$	(22.3	)			(9	%)
Rental Tools			73.6				53.3				20.3				38	%			178.1				149.7				28.4				19	%
Drilling and Other			40.2				37.1				3.1				8	%			107.9				97.4				10.5				11	%
Workover Services			—				—				—				—	%			—				8.5				(8.5	)			(100	%)
Total Well Site Services			179.7				154.4				25.3				16	%			507.3				499.2				8.1				2	%
Offshore Products			132.1				110.1				22.0				20	%			386.6				282.0				104.6				37	%
Tubular Services			215.6				215.0				0.6				0	%			613.4				657.9				(44.5	)			(7	%)
Total		$	527.4			$	479.5			$	47.9				10	%		$	1,507.3			$	1,439.1			$	68.2				5	%
Cost of sales
Well Site Services —
Accommodations		$	37.2			$	40.5			$	(3.3	)			(8	%)		$	125.5			$	162.3			$	(36.8	)			(23	%)
Rental Tools			39.0				24.0				15.0				63	%			90.5				69.8				20.7				30	%
Drilling and Other			23.9				19.7				4.2				21	%			62.8				49.9				12.9				26	%
Workover Services			—				—				—				—	%			—				5.3				(5.3	)			(100	%)
Total Well Site Services			100.1				84.2				15.9				19	%			278.8				287.3				(8.5	)			(3	%)
Offshore Products			100.6				83.4				17.2				21	%			291.5				210.5				81.0				38	%
Tubular Services			202.7				195.4				7.3				4	%			575.6				597.1				(21.5	)			(4	%)
Total		$	403.4			$	363.0			$	40.4				11	%		$	1,145.9			$	1,094.9			$	51.0				5	%
Gross margin
Well Site Services —
Accommodations		$	28.7			$	23.5			$	5.2				22	%		$	95.8			$	81.3			$	14.5				18	%
Rental Tools			34.6				29.3				5.3				18	%			87.6				79.9				7.7				10	%
Drilling and Other			16.3				17.4				(1.1	)			(6	%)			45.1				47.5				(2.4	)			(5	%)
Workover Services			—				—				—				—	%			—				3.2				(3.2	)			(100	%)
Total Well Site Services			79.6				70.2				9.4				13	%			228.5				211.9				16.6				8	%
Offshore Products			31.5				26.7				4.8				18	%			95.1				71.5				23.6				33	%
Tubular Services			12.9				19.6				(6.7	)			(34	%)			37.8				60.8				(23.0	)			(38	%)
Total		$	124.0			$	116.5			$	7.5				6	%		$	361.4			$	344.2			$	17.2				5	%
Gross margin as a percent of revenues
Well Site Services —
Accommodations			44	%			37	%											43	%			33	%
Rental Tools			47	%			55	%											49	%			53	%
Drilling and Other			41	%			47	%											42	%			49	%
Workover Services			—	%			—	%											—	%			38	%
Total Well Site Services			44	%			45	%											45	%			42	%
Offshore Products			24	%			24	%											25	%			25	%
Tubular Services			6	%			9	%											6	%			9	%
Total			24	%			24	%											24	%			24	%

THREE MONTHS ENDED SEPTEMBER 30, 2007 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2006

     We reported net income for the quarter ended September 30, 2007 of $50.5 million, or $0.97 per diluted share. These results compare to $50.1 million, or $0.99 per diluted share, reported for the quarter ended September 30, 2006.

     Revenues. Consolidated revenues increased $47.9 million, or 10%, in the third quarter of 2007 compared to the third quarter of 2006.

     Our offshore products revenues increased $22.0 million, or 20%, due to increased deepwater development spending and capital equipment upgrades by our customers. Our offshore products backlog increased to $396.0 million at September 30, 2007 compared to $349.3 million at December 31, 2006 and $321.2 million at September 30, 2006.

     Tubular services revenues increased $0.6 million, or 0.3%, in the third quarter of 2007 compared to the third quarter of 2006 as a result of a 5.7% increase in tons shipped, partially offset by a 5.1% decrease in average selling prices per ton.

     Our well site services revenues increased $25.3 million, or 16%, in the third quarter of 2007 compared to the third quarter of 2006.

     Rental tools revenues increased $20.3 million, or 38%, in the third quarter of 2007 compared to the third quarter of 2006 as a result of the acquisitions of Well Testing and Schooner and capital additions made since the third quarter of 2006, which were only partially offset by decreased Canadian rental tool revenues in the third quarter of 2007 caused by reduced Canadian drilling and completion activity. Our drilling revenues increased $3.1 million, or 8%, in the third quarter of 2007 compared to the third quarter of 2006 as a result of an increased rig fleet size (three additional rigs) and higher rates, partially offset by lower utilization in the third quarter of 2007 compared to 2006.

     Our accommodations revenues increased $1.9 million, or 3%, as a result of increased activity in support of the oil sands developments in Canada, which were only partially offset by decreased oil and gas drilling activity levels in Canada and lower third party accommodations manufacturing revenues in the U.S. and Canada.

     Cost of Sales. Our consolidated cost of sales increased $40.4 million, or 11%, in the third quarter of 2007 compared to the third quarter of 2006 primarily as a result of increases at offshore products of $17.2 million, or 21%, at well site services of $15.9 million, or 19%, and at tubular services of $7.3 million, or 4%. Our overall gross margin as a percent of revenues was 24% in both the third quarter of 2007 and 2006.

     Tubular services cost of sales increased primarily as a result of increased tonnage shipped. Our tubular services gross margin as a percentage of revenues decreased from 9% in the third quarter of 2006 to 6% in the third quarter of 2007 as a result of lower OCTG mill pricing and higher industry wide inventory levels which contributed to more competitive pricing and lower margins.

     Our well site services gross margins as a percent of revenue decreased from 45% to 44% in the third quarter of 2007 compared to the third quarter of 2006. Our accommodations cost of sales decrease was driven by lower costs associated with fewer third party manufacturing projects in 2007 compared to 2006 and by lower activity in support of Canadian drilling operations in 2007. Our accommodations gross margin as a percentage of revenues improved from 37% in the third quarter of 2006 to 44% in the third quarter of 2007 primarily because of capacity additions and economies of scale in our major oil sands lodges and lower manufacturing revenues, which generally earn lower margins than accommodations rentals or catering work.

     Our rental tool cost of sales increased $15.0 million, or 63%, in the third quarter of 2007 compared to the third quarter of 2006 primarily as a result of operating costs associated with acquisitions made in the third quarter of 2007. Our rental tool gross margin decreased from 55% in the third quarter of 2006 to 47% in the third quarter of

2007 primarily as a result of margins for one of the acquired business lines which are typically lower than our existing rental tool businesses and reduced Canadian rental tool activity.

     Our drilling services cost of sales increased $4.2 million, or 21%, in the third quarter of 2007 compared to the third quarter of 2006 as a result of an increase in the number of rigs that we operate and increased costs associated with footage-based drilling contracts. Increased costs coupled with lower utilization in our areas of operations have reduced our drilling services gross margin from 47% in the third quarter of 2006 to 41% in the third quarter of 2007.

     Our offshore products cost of sales increased, on a percentage basis, approximately in line with the increase in offshore products revenues.

     Selling, General and Administrative Expenses. Selling, general and administrative expenses (SG&A) increased $3.5 million, or 12.7%, in the third quarter of 2007 compared to the third quarter of 2006. The increase is primarily attributable to SG&A expense associated with acquisitions made in the third quarter of 2007, increased salaries, wages and benefits and an increase in headcount. SG&A was 5.9% of revenues in the quarter ended September 30, 2007 compared to 5.7% of revenues in the quarter ended September 30, 2006.

     Depreciation and Amortization. Depreciation and amortization expense increased $4.9 million, or 35%, in the third quarter of 2007 compared to the same period in 2006 due primarily to capital expenditures made during the previous twelve months.

     Operating Income. Consolidated operating income decreased $0.7 million, or 1%, in the third quarter of 2007 compared to the third quarter of 2006 primarily as a result of a decrease at tubular services of $7.1 million, or 43%, which was partially offset by increases at offshore products of $5.7 million, or 35%, and at well site services of $1.8 million, or 4%.

     Interest Expense and Interest Income. Interest expense decreased by $0.6 million, or 12%, in the third quarter of 2007 compared to the third quarter of 2006 due to the impact of lower interest rates and interest capitalization. The weighted average interest rate on the Company’s revolving credit facility was 6.1% in the third quarter of 2007 compared to 6.4% in the third quarter of 2006. Interest income in 2007 and 2006 relates primarily to the subordinated notes receivable obtained in consideration for the sale of our hydraulic workover business (see Note 11 to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q).

     Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is lower in the third quarter of 2007 than in the third quarter of 2006 primarily because of the sale of 14.95 million shares of our investment in Boots & Coots in April 2007. Following this sale, our ownership interest in Boots & Coots decreased to approximately 15%.

     Income Tax Expense. Our income tax provision for the third quarter of 2007 totaled $22.0 million, or 30.3%, of pretax income compared to $25.9 million, or 34.1%, of pretax income for the third quarter of 2006. Adjustments made to the Company’s income tax liabilities upon the filing of its 2006 federal tax return in the third quarter of 2007 compared to income tax liabilities estimated at the time of the finalization of the December 31, 2006 consolidated financial statements and the completion of the IRS audit of the Company’s 2004 federal income tax return lowered the effective tax rate in the three month period ended September 30, 2007. In addition, our effective tax rates were higher in 2006 than 2007 because of the higher effective tax rate applicable to the gain on the sale of the workover services business recognized in 2006.

NINE MONTHS ENDED SEPTEMBER 30, 2007 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2006

     We reported net income for the nine months ended September 30, 2007 of $155.2 million, or $3.05 per diluted share. These results compare to $148.3 million, or $2.91 per diluted share, reported for the nine months ended September 30, 2006. Net income for the first nine months of 2007 included a pre-tax gain of $12.8 million, or an after tax gain of $0.17 per diluted share, on the sale of 14.95 million shares of Boots & Coots. During the first nine months of 2006, we recognized an $11.3 million pre-tax gain or an after tax gain of $0.12 per diluted share from the

sale of our workover business to Boots & Coots. See Note 11 to the Unaudited Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

     Revenues. Consolidated revenues increased $68.2 million, or 5%, in the first nine months of 2007 compared to the first nine months of 2006.

     Our offshore products revenues increased $104.6 million, or 37%, due to increased deepwater development spending and capital equipment upgrades by our customers.

     Tubular services revenues decreased $44.5 million, or 7%, in the first nine months of 2007 compared to the first nine months of 2006 as a result of a 3.9% decrease in tons shipped and a 3.0% decrease in average selling prices per ton.

     Our well site services revenues increased $8.1 million, or 2%, in the first nine months of 2007 compared to the first nine months of 2006.

     Rental tools revenues increased $28.4 million, or 19%, in the first nine months of 2007 compared to the first nine months of 2006 as a result of the acquisitions of Well Testing and Schooner, increased prices realized and capital additions made since the first nine months of 2006, which were only partially offset by decreased Canadian rental tool revenues in the first nine months of 2007 caused by lower Canadian drilling and completion activity when compared to the first nine months of 2006. Our drilling revenues increased $10.5 million, or 11%, in the first nine months of 2007 compared to the first nine months of 2006 as a result of an increased rig fleet size (four additional rigs) and higher rates, partially offset by lower utilization in the first nine months of 2007. The sale of our workover services business in March 2006 caused an $8.5 million decrease in revenues in the first nine months of 2007 compared to the first nine months of 2006.

     Our accommodations business revenues decreased $22.3 million, or 9%, as a result of decreased oil and gas drilling activity levels in Canada and lower third party accommodations manufacturing revenues in the U.S. and Canada, which were only partially offset by higher revenues driven by increased activity in support of the oil sands developments in Canada.

     Cost of Sales. Our consolidated cost of sales increased $51.0 million, or 5%, in the first nine months of 2007 compared to the first nine months of 2006 primarily as a result of an increase at offshore products of $81.0 million, or 38%, partially offset by decreases at tubular services of $21.5 million, or 4%, and well site services of $8.5 million, or 3%. Our overall gross margin as a percent of revenues was 24% in the first nine months of 2007 and 2006.

     Tubular services cost of sales decreased as a result of decreased tonnage shipped which was partially offset by the impact of OCTG price increases for inventory purchased. Our tubular services gross margin as a percentage of revenues decreased from 9% to 6% in the first nine months of 2007 compared to the first nine months of 2006 as a result of lower OCTG mill pricing, higher industry wide inventory levels, which contributed to more competitive pricing and lower margins, and a greater mix of relativity low margin carbon grade OCTG sales in 2007.

     Our well site services gross margin as a percent of revenues increased from 42% to 45% in the first nine months of 2007 compared to the first nine months of 2006. Our accommodations cost of sales decreased due to lower costs associated with fewer third party manufacturing projects in 2007 compared to 2006 and reduced activity in support of Canadian drilling operations in 2007. Our accommodations gross margin as a percentage of revenues improved from 33% in the first nine months of 2006 to 43% in the first nine months of 2007 primarily because of capacity additions and economies of scale in our major oil sands lodges and lower manufacturing revenues, which generally earn lower margins than accommodations rentals or catering work.

     Our rental tool cost of sales increased $20.7 million, or 30%, in the first nine months of 2007 compared to the first nine months of 2006 primarily as a result of operating costs associated with acquisitions made in the third quarter of 2007 and higher costs associated with increased revenue at our existing rental tool businesses. Our rental tool gross margin decreased from 53% in the first nine months of 2006 to 49% in the first nine months of 2007

primarily as a result of margins for one of the acquired business lines which are typically lower than our existing rental tool businesses and reduced Canadian rental tool activity.

     Our drilling services cost of sales increased $12.9 million, or 26%, in the first nine months of 2007 compared to the first nine months of 2006 as a result of an increase in the number of rigs that we operate, increased wages paid to our employees and increased costs associated with footage-based drilling contracts. Increased costs coupled with lower utilizations have reduced our drilling services gross margin from 49% in the first nine months of 2006 to 42% in the first nine months of 2007.

     Our offshore products cost of sales, on a percentage basis, increased approximately in line with the increase in offshore products revenues.

     Selling, General and Administrative Expenses. SG&A increased $6.8 million, or 9%, in the first nine months of 2007 compared to the first nine months of 2006 due primarily to SG&A expense associated with acquisitions made in the third quarter of 2007, increased salaries, wages and benefits and an increase in headcount. SG&A was 5.7% of revenues in the nine months ended September 30, 2007 compared to 5.5% of revenues in the nine months ended September 30, 2006.

     Depreciation and Amortization. Depreciation and amortization expense increased $9.6 million, or 24%, in the first nine months of 2007 compared to the same period in 2006 due primarily to capital expenditures made during the previous twelve months.

     Operating Income. Consolidated operating income increased $1.4 million, or 1%, in the first nine months of 2007 compared to the first nine months of 2006 primarily as a result of increases at offshore products of $22.3 million, or 54%, and at well site services of $4.1 million, or 3%, which were partially offset by decreased tubular services operating income of $23.5 million, or 46%.

     Interest Expense and Interest Income. Interest expense decreased by $1.7 million, or 12% in the first nine months of 2007 compared to the first nine months of 2006 due to lower average debt levels. The weighted average interest rate on the Company’s revolving credit facility was 6.1% in the first nine months of 2007 and 2006. Interest income in 2007 and 2006 relates primarily to the subordinated notes receivable obtained in consideration for the sale of our hydraulic workover business (see Note 11 to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q).

     Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is lower in the first nine months of 2007 than in the first nine months of 2006 primarily because of the sale of 14.95 million shares of our investment in Boots & Coots in April 2007. Following this sale, our ownership interest decreased to approximately 15%.

     Income Tax Expense. Our income tax provision for the first nine months of 2007 totaled $76.2 million, or 32.9% of pretax income, compared to $81.5 million, or 35.5% of pretax income, for the first nine months of 2006. Adjustments made to the Company’s income tax liabilities upon the filing of its 2006 federal tax return in the third quarter of 2007 compared to income tax liabilities estimated at the time of the finalization of the December 31, 2006 consolidated financial statements and the completion of the IRS audit of the Company’s 2004 federal income tax return lowered the effective tax rate in the nine month period ended September 30, 2007. In addition, our effective tax rates were higher in 2006 than 2007 because of the higher effective tax rate applicable to the gain on the sale of the workover services business recognized in 2006.

Liquidity and Capital Resources

     Our primary liquidity needs are to fund capital expenditures, such as expanding our accommodations facilities, expanding and upgrading our manufacturing facilities and equipment, adding drilling rigs and increasing and replacing rental tool assets, funding new product development and 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 $213.2 million was provided by operations during the first nine months of 2007 compared to cash totaling $99.9 million provided by operations during the first nine months of 2006. During the first nine months of 2007, $25.1 million was provided by working capital changes primarily due to a $52.9 million reduction in tubular services inventories in 2007, partially offset by other working capital increases. During the first nine months of 2006, $73.4 million was used to fund working capital due primarily to increases in receivables and inventories in our offshore products segment given the growth in activity compared to 2005.

     Cash was used in investing activities during the nine months ended September 30, 2007 and 2006 in the amount of $242.9 million and $101.6 million, respectively. Capital expenditures, including capitalized interest, totaled $172.1 million and $104.1 million during the nine months ended September 30, 2007 and 2006, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment. Net proceeds from the sale of 14.95 million shares of Boots & Coots common stock totaled $29.4 million during the nine months ended September 30. 2007. See Note 11 to the Unaudited Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q.

     In the nine months ended September 30, 2007, we expended cash of $102.2 million to acquire two rental tool businesses.

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

     We currently expect to spend a total of approximately $254 million for capital expenditures during 2007 to expand our Canadian oil sands related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. We expect to fund these capital expenditures with internally generated funds and proceeds from borrowings under our revolving credit facilities.

     Net cash of $23.4 million was provided by financing activities during the nine months ended September 30, 2007, primarily as a result of revolving credit facility borrowings and proceeds from stock option exercises partially offset by treasury stock purchases and other debt repayments. A total of $0.8 million was used by financing activities during the nine months ended September 30, 2006.

     During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, an additional $50 million was approved and the duration of the program was extended to August 31, 2008. Through September 30, 2007, a total of $57.3 million of our stock (2,064,432 shares), has been repurchased under this program, leaving a total of up to approximately $42.7 million remaining available under the program.

     On December 5, 2006, we amended our existing credit agreement dated as of October 30, 2003 (the Credit Agreement). The amendment to the Credit Agreement increased the total commitments under the Credit Agreement from $325 million to $400 million and extended the maturity of the Credit Agreement to December 5, 2011.

     As of September 30, 2007, we had $247.3 million outstanding under the Credit Agreement and an additional $9.8 million of outstanding letters of credit, leaving $142.9 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. and the U.K. that provide for an aggregate borrowing capacity of $9.1 million. As of September 30, 2007, we had $1.3 million outstanding under these other facilities and an additional $0.6 million of outstanding letters of credit leaving $7.2 million available to be drawn under these facilities. Our total debt represented 29.1% of the total of debt and shareholder’s equity at September 30, 2007 compared to 32.2% at December 31, 2006 and 33.5% at September 30, 2006.

     As of September 30, 2007, we have reclassified the $175.0 million principal amount of our 2 3/8% Notes to a current liability because certain contingent conversion thresholds based on the Company’s stock price were met at that date and, as a result, note holders could present their notes for conversion only during the quarter subsequent to the September 30, 2007 measurement date.  The future convertibility and resultant balance sheet classification of

this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company common stock during the prescribed measurement periods.  As of September 30, 2007, the recent trading prices of the 2 3/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder.  The trading price for the 2 3/8% Notes is dependent on current market conditions, the length of time until the first put / call date of the 2 3/8% Notes and general market liquidity, among other factors.  Based on recent trading patterns of the 2 3/8% Notes, we do not currently expect any significant amount of the 2 3/8% Notes to convert over the next twelve months. In August 2007, the FASB issued proposed FASB Staff Position (FSP) No. APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which, if issued, would change the accounting for our 2 3/8% Notes. Under the proposed new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity would be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the proposed new rules on our 2 3/8% Notes is that the equity component would be classified as part of stockholders’ equity on our balance sheet and the value of the equity component would be treated as an original issue discount for purposes of accounting for the debt component of the 2 3/8% Notes. Higher non-cash interest expense would result by recognizing the accretion of the discounted carrying value of the 2 3/8% Notes as interest expense over the estimated life of the 2 3/8% Notes using an effective interest rate method of amortization. However, there would be no effect on our cash interest payments. The proposed FSP is expected to be effective for fiscal years beginning after December 15, 2007 and will require retrospective application. The Company is currently evaluating the impact of this proposed FSP.

     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.

Critical Accounting Policies

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

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

     We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, interest, insurance claims, warranty claims, contract claims and discontinued operations.

     The assessment of impairment on long-lived assets, including goodwill and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. The determination of the amount of impairment, which is other than a temporary decline in value, would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether an other than temporary decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.

     We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this

method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the period in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.

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

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

     Since the adoption of SFAS No. 123R, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An initial estimate of fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward and consistent vesting terms, option prices and option lives. Utilizing the Black Scholes model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change 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, 2007, we had floating rate obligations totaling approximately $248.6 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, 2007 levels, our consolidated interest expense would increase by a total of approximately $2.5 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 September 30, 2007. Results of operations have not been materially affected by foreign currency hedging activity.

ITEM 4. Controls and Procedures

     Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2007 in ensuring that

material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act, including this Quarterly Report on Form 10-Q, is recorded, processed, summarized and reported within the time periods specified in the Commission rules and forms.

     Changes in Internal Control over Financial Reporting. During the three months ended September 30, 2007, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act of 1934) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

     We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses and in other cases, we have indemnified the buyers 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.

ITEM 1A. Risk Factors

     Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2006 (the 2006 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 2006 Form 10-K except as detailed below.

Customer labor problems could adversely affect us

     Our accommodations facilities serving oil sands development work in Northern Alberta, Canada house both union and non-union customer employees. If a union representing members employed by one or more of our customers threatens or engages in a strike, work stoppage or other slowdown, this could cause us to experience a disruption of our operations which could adversely affect our business, financial condition and results of operations.

Royalty levels imposed by governmental authorities can impact economics of oil and gas producers and, therefore, affect their demand for our accommodations

     After the end of the third quarter of 2007, the government of Alberta announced its plans to increase the royalties payable by oil and gas companies in both traditional hydrocarbon production and in oil sands production. It is too early to determine how these increased taxes will impact our customers’ spending plans, and, as a result, our oil sands accommodations operations. To the extent any increased royalties cause our customers to curtail their operations or spending plans, our oil sands accommodations operations could be adversely affected. At this time, we have not changed any of our announced plans to expand our oil sands accommodations.

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

Unregistered Sales of Equity Securities and Use of Proceeds

None

Purchases of Equity Securities by the Issuer and Affiliated Purchases

										Total Number of				Approximate
										Shares Purchased				Dollar Value of Shares
										as Part of the Share				Remaining to be Purchased
		Total Number of				Average Price				Repurchase				Under the Share Repurchase
Period		Shares Purchased				Paid per Share				Program				Program
July 1, 2007 — July 31, 2007			—				—				2,064,432			$	42,733,264
August 1, 2007 — August 31, 2007			—				—				2,064,432			$	42,733,264
September 1, 2007 — September 30, 2007			—				—				2,064,432			$	42,733,264	(1)
Total			—				—				2,064,432			$	42,733,264