NOV Inc. - Quarter Report: 2006 March (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 QUARTER ENDED MARCH 31, 2006 OR

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

NATIONAL OILWELL VARCO, INC.

Delaware		76-0475815
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

(713) 346-7500

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 “accelerated filer and large accelerated filer” in Rule 12b-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

As of May 2, 2006, 174,968,830 common shares were outstanding.

 

 

ITEM 1. Financial Statements

		March 31,				December 31,
		2006				2005
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	263.0			$	209.4
Receivables, net			1,204.5				1,139.2
Inventories, net			1,353.5				1,198.3
Costs in excess of billings			348.7				341.9
Deferred income taxes			58.6				58.6
Prepaid and other current assets			90.2				50.8
Total current assets			3,318.5				2,998.2
Property, plant and equipment, net			878.4				877.6
Deferred income taxes			52.4				52.2
Goodwill			2,136.6				2,117.7
Intangibles, net			603.8				611.5
Other assets			19.8				21.3
Total assets		$	7,009.5			$	6,678.5
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	605.6			$	568.2
Accrued liabilities			641.5				530.1
Current portion of long-term debt and short-term borrowings			4.2				5.7
Accrued income taxes			115.3				83.2
Total current liabilities			1,366.6				1,187.2
Long-term debt			834.8				835.6
Deferred income taxes			357.2				373.3
Other liabilities			70.3				63.7
Total liabilities			2,628.9				2,459.8
Commitments and contingencies
Minority interest			24.9				24.5
Stockholders’ equity:
Common stock — par value $.01; 174,853,276 and 174,362,488 shares issued and outstanding at March 31, 2006 and December 31, 2005			1.7				1.7
Additional paid-in capital			3,409.5				3,400.9
Unearned stock-based compensation			—				(16.5	)
Accumulated other comprehensive loss			(5.7	)			(21.8	)
Retained earnings			950.2				829.9
Total stockholders’ equity			4,355.7				4,194.2
Total liabilities and stockholders’ equity		$	7,009.5			$	6,678.5

See notes to unaudited consolidated financial statements.

		Three Months Ended
		March 31,
		2006				2005
Revenue		$	1,511.8			$	814.9
Cost of revenue			1,162.0				653.1
Gross profit			349.8				161.8
Selling, general, and administrative (*)			144.1				86.1
Integration costs			7.9				9.8
Operating profit			197.8				65.9
Interest and financial costs			(13.6	)			(10.7	)
Interest income			1.7				1.0
Other expense, net			(3.0	)			(0.7	)
Income before income taxes and minority interest			182.9				55.5
Provision for income taxes			61.3				19.5
Income before minority interest			121.6				36.0
Minority interest in income of consolidated subsidiaries			1.3				0.4
Net income		$	120.3			$	35.6
Net income per share:
Basic		$	0.69			$	0.34
Diluted		$	0.68			$	0.33
Weighted average shares outstanding:
Basic			174.6				105.3
Diluted			176.6				106.6
(*) — Stock-based compensation expense included in selling, general, and administrative expense		$	6.8			$	1.1

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)

		Three Months Ended
		March 31,
		2006				2005
Cash flow from operating activities:
Net income		$	120.3			$	35.6
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation and amortization			38.4				16.3
Tax benefit from exercise of nonqualified stock options			—				13.5
Excess tax benefit from exercise of nonqualified stock options			(5.2	)			—
Other			1.1				1.8
Changes in assets and liabilities, net of acquisitions:
Receivables			(65.3	)			(19.9	)
Inventories			(155.2	)			(22.1	)
Costs in excess of billing			(6.8	)			(27.8	)
Prepaid and other current assets			(39.4	)			(0.6	)
Accounts payable			37.4				9.6
Billings in excess of cost			96.3				(28.8	)
Other assets/liabilities, net			65.0				(20.1	)
Net cash provided (used) by operating activities			86.6				(42.5	)
Cash flow from investing activities:
Purchases of property, plant and equipment			(30.2	)			(10.0	)
Cash acquired in Varco merger, net			—				158.8
Businesses acquisitions, net of cash acquired			(21.0	)			—
Other			—				3.3
Net cash provided (used) by investing activities			(51.2	)			152.1
Cash flow from financing activities:
Borrowing against lines of credit and other debt			3.6				143.0
Payments against lines of credit and other debt			(5.7	)			(135.1	)
Proceeds from stock options exercised			13.2				36.5
Excess tax benefit from exercise of nonqualified stock options			5.2				—
Net cash provided by financing activities			16.3				44.4
Effect of exchange rates on cash			1.9				(1.6	)
Increase in cash equivalents			53.6				152.4
Cash and cash equivalents, beginning of period			209.4				142.7
Cash and cash equivalents, end of period		$	263.0			$	295.1
Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest		$	8.9			$	10.4
Income taxes		$	39.1			$	16.2

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.
Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The accompanying unaudited consolidated financial statements present information in accordance with accounting principles generally accepted in the United States for interim financial information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not include all information or footnotes required by accounting principles generally accepted in the United States for complete financial statements and should be read in conjunction with our 2005 Annual Report on Form 10K.

In our opinion, the consolidated financial statements include all adjustments, all of which are of a normal, recurring nature, necessary for a fair presentation of the results for the interim periods. The results of operations for the three months ended March 31, 2006 are not necessarily indicative of the results to be expected for the full year.

2. Varco Merger

The Varco merger has been accounted for as a purchase business combination. Assets acquired and liabilities assumed were recorded at their fair values as of March 11, 2005. The total purchase price is $2,579.3 million, including the fair value of Varco stock options assumed and merger related transaction costs, and is comprised of (in millions):

Shares issued to acquire the outstanding common stock of Varco (84.0 million shares at $29.99 per share)		$	2,518.4
Fair value of Varco stock options assumed			48.9
Unearned compensation related to stock options assumed			(32.1	)
Merger related transaction costs			44.1
Total purchase price		$	2,579.3

Merger related transaction costs include severance and other external costs directly related to the merger.

Integration costs of $7.9 million in the first quarter of 2006 were comprised of $6.6 million for discontinued inventory, $0.5 million for combining operations and $0.8 million of other.

Purchase Price Allocation

Under the purchase method of accounting, the total purchase price was allocated to Varco’s net tangible and identifiable intangible assets based on their estimated fair values as of March 11, 2005 as set forth below (in millions).

Cash and marketable securities		$	163.5
Trade receivables			385.3
Other current assets			28.5
Inventory			377.1
Property, plant and equipment			598.4
Goodwill			1,496.2
Intangible assets			551.3
Other non-current assets			11.3
Accounts payable and accrued liabilities			(230.5	)
Income taxes payable			(13.7	)
Debt			(492.8	)
Deferred tax liabilities, net			(240.1	)
Other non-current liabilities			(54.0	)
Minority interest			(1.2	)
Total purchase price		$	2,579.3

3. Inventories, net

Inventories consist of (in millions):

		March 31,				December 31,
		2006				2005
Raw materials and supplies		$	224.7			$	220.4
Work in process			324.8				267.5
Finished goods and purchased products			804.0				710.4
Total		$	1,353.5			$	1,198.3

4. Accrued Liabilities

Accrued liabilities consist of (in millions):

		March 31,				December 31,
		2006				2005
Compensation		$	98.9			$	111.0
Warranty			27.0				24.9
Interest			16.5				11.7
Taxes (non income)			24.9				23.6
Insurance			21.3				30.2
Other			258.5				230.6
Billings in excess of costs			194.4				98.1
Total		$	641.5			$	530.1

5. Costs and Estimated Earnings on Uncompleted Contracts

Costs and estimated earnings on uncompleted contracts consist of (in millions):

		March 31,				December 31,
		2006				2005
Costs incurred on uncompleted contracts		$	1,098.5			$	1,440.9
Estimated earnings			215.5				300.6
			1,314.0				1,741.5
Less: Billings to date			1,159.7				1,497.7
		$	154.3			$	243.8
Costs and estimated earnings in excess of billings on uncompleted contracts		$	348.7			$	341.9
Billings in excess of costs and estimated earnings on uncompleted contracts			(194.4	)			(98.1	)
		$	154.3			$	243.8

6. Comprehensive Income

The components of comprehensive income are as follows (in millions):

		Three Months Ended March 31,
		2006				2005
Net income		$	120.3			$	35.6
Currency translation adjustments			9.3				(18.2	)
Other			6.8				3.1
Comprehensive income		$	136.4			$	20.5

7. Business Segments

Operating results by segment are as follows (in millions). The 2005 actual results include 20 days of Varco operations from the acquisition date of March 11, 2005 through March 31, 2005:

		Three Months Ended March 31,
		2006				2005
Revenue:
Rig Technology		$	715.3			$	424.4
Petroleum Services & Supplies			541.0				209.1
Distribution Services			326.5				235.9
Elimination			(71.0	)			(54.5	)
Total Revenue		$	1,511.8			$	814.9
Operating Profit:
Rig Technology		$	100.8			$	44.9
Petroleum Services & Supplies			118.3				35.2
Distribution Services			20.8				7.6
Unallocated expenses and eliminations			(27.4	)			(10.9	)
Integration costs and stock-based compensation			(14.7	)			(10.9	)
Total operating profit		$	197.8			$	65.9
Operating profit %:
Rig Technology			14.1	%			10.6	%
Petroleum Services & Supplies			21.9	%			16.8	%
Distribution Services			6.4	%			3.2	%
Total Operating Profit %			13.1	%			8.1	%

8. Debt

Debt consists of (in millions):

		March 31,				December 31,
		2006				2005
$100.0 million Senior Notes, interest at 7.5% payable semiannually, principal due on February 15, 2008		$	103.1			$	103.6
$150.0 million Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011			150.0				150.0
$200.0 million Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011			217.8				218.7
$200.0 million Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012			200.0				200.0
$150.0 million Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012			151.8				151.8
Other			16.3				17.2
Total debt			839.0				841.3
Less current portion			4.2				5.7
Long-term debt		$	834.8			$	835.6

Senior Notes

The Senior Notes contain reporting covenants and the credit facility contains financial covenants regarding maximum debt to capitalization and minimum interest coverage. We were in compliance with all covenants at March 31, 2006.

Revolver Facilities

On June 21, 2005, we amended and restated our existing $150 million revolving credit facility with a syndicate of lenders to provide the Company a $500 million unsecured revolving credit facility. This facility will expire in July 2010, and replaced the Company’s $175 million North American revolving credit facility and our Norwegian facility. The Company has the right to increase the facility to $750 million and to extend the term of the facility for an additional year. At March 31, 2006, there were no borrowings against this facility, and there were $142 million in outstanding letters of credit. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.30% subject to a ratings-based grid, or the prime rate.

Other

Other debt includes approximately $11 million in promissory notes due to former owners of businesses acquired who remain employed by the company.

9. Stock-Based Compensation

Prior to January 1, 2006 National Oilwell Varco “the company” accounted for its stock option plans using the intrinsic value method of accounting provided under APB Opinion No. 25, “Accounting for Stock Issued to Employees,” (APB 25) and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation,” (SFAS 123) under which no compensation expense was recognized for stock option grants. Share-based compensation was a pro forma disclosure in the financial statement footnotes and continues to be for periods prior to fiscal 2006.

Effective January 1, 2006 the company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment,” (SFAS 123(R)) using the modified-prospective transition method. Under this transition method, compensation cost recognized in first quarter 2006 includes: a) compensation cost for all share-based payments granted prior to January 1, 2006, but for which the requisite service period had not been completed as of March 31, 2006 based on the grant date fair value estimated in accordance with the original provisions of SFAS 123, and b) compensation cost for all share-based payments granted subsequent to January 1, 2006 based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R).

The adoption of SFAS 123(R) results in lower diluted shares outstanding than would have been calculated had compensation cost not been recorded for stock options. This is due to a modification required by SFAS 123(R) of the treasury stock method calculation utilized to compute the dilutive effect of stock options.

Prior to the adoption of SFAS 123(R), the company presented all tax benefits of deductions resulting from the exercise of options as operating cash flows in the Statement of Consolidated Cash Flows. SFAS 123(R) requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows.

The company provides compensation benefits to employees and non-employee directors under share-based payment arrangements including various employee stock option plans.

Total compensation cost that has been charged against income for all share-based compensation arrangements under the Plan was $6.8 million and $1.1 million for the three months ended March 31, 2006 and 2005, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements under the Plan was $2.4 million and $0.4 million for the three months ended March 31, 2006 and 2005, respectively.

The $16.5 million of unearned stock-based compensation on the company’s balance sheet at December 31, 2005 was reclassified to paid-in-capital upon the adoption of SFAS 123(R).

Pro Forma Net Income

The following table provides pro forma net income and income per share had the company applied the fair value method of SFAS 123(R) for the period ended March 31, 2005 (in millions, except per share data):

		Three Months
		Ended March 31,
		2005
Net income, before stock-based employee compensation		$	35.6
Add:
Total stock-based employee compensation expense included in net income, net of related tax effects			0.7
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(3.3	)
Pro forma net income		$	33.0
Net income per common share:
Basic, as reported		$	0.34
Basic, pro forma		$	0.31
Diluted, as reported		$	0.33
Diluted, pro forma		$	0.31

Stock Options

Stock options awards are generally granted with an exercise price equal to the closing market price of the Company’s stock price at the date of grant. Stock options generally vest over a three year period with one third vesting in each successive year so that the option is fully exercisable after three years and generally have ten year contractual terms.

Upon adoption of FAS 123(R), we began estimating the value of employee stock options on the date of grant using the Black Scholes model. Prior to the adoption of FAS 123(R), the value of each employee stock option was estimated on the date of grant using the Black-Scholes model for the purpose of the pro forma financial information in accordance with FAS 123. The determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to the expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. The use of the Black Scholes model requires the use of extensive actual employee exercise behavior data and the use of a number of complex assumptions including expected volatility, risk-free interest rate, expected dividends and expected term.

		Three Months Ended					Fiscal
		March 31, 2006					2005
Expected volatility			39.37	%			46.0	%
Risk-free interest rate			4.56	%			3.68	%
Expected dividends			0.0	%			0.0	%
Expected term			3.75				5.0
Forfeiture rate			1.09	%			5.0	%

We used the actual volatility for traded options on our stock since March 11, 2005 (merger date) as the expected volatility assumption required in the Black Scholes model, which is consistent with FAS 123(R) and SAB 107. Prior to the first quarter of fiscal 2006, we used our historical stock price volatility in accordance with FAS 123 for purposes of our pro forma information. The selection of the actual volatility approach was based upon the availability of actively traded options on our stock and our assessment that actual volatility since the merger with Varco is more representative of future stock price trends.

The risk-free interest rate assumption is based upon observed interest rates appropriate for the term of our employee stock options. The dividend yield assumption is based on the history and expectation of dividend payouts. The estimated expected term is based on the actual employee exercise behaviors for the past ten years.

As stock-based compensation expense recognized in the Consolidated Statement of Income for the first quarter of 2006 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. FAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated based on historical experience.

If factors change and we employ different assumptions in the application of FAS 123(R) in future periods, the compensation expense that we record under FAS 123(R) may differ significantly from what we have recorded in the current period.

The following summary presents information regarding outstanding options as of December 31, 2005 and changes during the first quarter of 2006 with regard to options under all stock option plans:

										Weighted
										Average
						Weighted				Remaining				Aggregate
						Average				Contractual				Intrinsic
		Shares				Exercise Price				Term				Value
Outstanding at December 31, 2005			4,340,842			$	30.36
Granted			2,340,000				66.58
Exercised			(480,633	)			27.42
Cancellations			(57,333	)			34.67
Outstanding at March 31, 2006			6,142,876			$	44.36				8.63			$	127,119,967
Vested or expected to vest			6,075,918			$	44.36				8.63			$	125,734,359
Exercisable at March 31, 2006			2,006,470			$	26.76				7.18			$	74,962,739

The weighted-average grant date fair values of options granted during the three months ended March 31, 2006 and 2005 were $23.79 and $16.85 (excluding options assumed in the Varco merger) respectively. The total intrinsic value of options exercised during the three months ended March 31, 2006 and 2005 was $20.3 million and $81.5 million, respectively.

As of March 31, 2006, total unrecognized compensation cost related to nonvested stock options was $78.0 million. This cost is expected to be recognized over a weighted average period of 2.9 years. The total fair value of stock vested during the three months ended March 31, 2006 and 2005 was approximately $18.1 million and $28.4 million respectively. Cash received from option exercises for the three months ended March 31, 2006 and 2005 was $13.2 million and $36.5 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $5.2 million and $13.5 million, respectively, for the three months ended March 31, 2006 and 2005. Cash used to settle equity instruments granted under all share-based payment arrangements for the three months ended March 31, 2006 and 2005 was immaterial in both periods.

The impact of adopting Statement 123(R) on January 1, 2006, on National Oilwell Varco’s income before income taxes, net income and basic and diluted earnings per share for the three months ended March 31, 2006 was immaterial.

10. Recently Issued Accounting Standards

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” an amendment of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” SFAS No. 155 simplifies accounting for certain hybrid instruments under SFAS No. 133 by permitting fair value remeasurement for financial instruments containing an embedded derivative that otherwise would require bifurcation. SFAS No. 155 eliminates both the previous restriction under SFAS No. 140 on passive derivative instruments that a qualifying special-purpose entity may hold and SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets,” which provides that beneficial interests are not subject to the provisions of SFAS No. 133. SFAS No. 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, and clarifies that concentrations of credit risk in the form of subordination are not imbedded derivatives. SFAS No. 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring after the beginning of an entity’s fiscal year that begins after September 15, 2006. We are currently evaluating the effect SFAS No. 155 will have on our consolidated financial position, liquidity, or results from operations.

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

Introduction

National Oilwell Varco is a worldwide leader in the design, manufacture and sale of equipment and components used in oil and gas drilling and production, the provision of oilfield services, and supply chain integration services to the upstream oil and gas industry. The following describes our business segments:

Rig Technology

Our Rig Technology segment designs, manufactures, sells and services complete systems for the drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line of highly-engineered equipment that automates complex well construction and management operations, such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; and cranes. Demand for Rig Technology products is primarily dependent on capital spending plans by drilling contractors, oilfield service companies, and oil and gas companies, and secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts for the segment’s large installed base of equipment. We have made strategic acquisitions and other investments during the past several years in an effort to expand our product offering and our global manufacturing capabilities, including new operations in Canada, Norway, the United Kingdom, China, and Belarus.

Petroleum Services & Supplies

Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service pipelines, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including transfer pumps, solids control systems, drilling motors and other downhole tools, rig instrumentation systems, and mud pump consumables. Demand for these services and supplies is determined principally by the level of oilfield drilling and workover activity by drilling contractors, major and independent oil and gas companies, and national oil companies. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drillpipe, linepipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including operations in Canada, the United Kingdom, China, Kazakhstan, and Mexico.

Distribution Services

Our Distribution Services segment provides maintenance, repair and operating supplies and spare parts to drill site and production locations worldwide. In addition to its comprehensive network of field locations supporting land drilling operations throughout North America, the segment supports major offshore drilling contractors through locations in the Middle East, Europe, Southeast Asia and South America. Distribution Services employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe. Demand for the segment’s services are determined primarily by the level of drilling and servicing activity, and oil and gas production activities.

Executive Summary

For the first quarter of 2006, National Oilwell Varco generated earnings of $120.3 million, or $0.68 per fully diluted share, on reported revenues of $1,511.8 million. These results include $6.8 million in pre-tax options expense charges ($0.03 per share after tax) related to the Company’s adoption of SFAS 123(R), and $7.9 million in pre-tax charges ($0.03 per share after tax) related to the Company’s integration of the operations of Varco.

The Company underwent a major transformation on March 11, 2005, when National Oilwell and Varco merged. As a result, the reported financial results for 2005 do not include the 70 days of Varco operations prior to the merger. The Company has presented supplemental unaudited pro forma results as if Varco and National Oilwell had been merged throughout 2004 and 2005, to better identify trends in our businesses and provide more meaningful comparison. The discussion and analysis below pertain to the results on this pro forma basis, which the Company tends to look at internally to evaluate results. Additionally, the Company’s disclosures since the merger have identified transaction, integration and stock-based compensation charges, including items such as severance, restructuring, equipment and inventory rationalization, amortization of options issued to replace Varco options, and write-offs of discontinued product lines related to the merger. The discussion of the results that follow generally excludes these items, except where noted, in order to better identify trends in our business and provide more meaningful comparison. The Company tends to review its results internally using this same methodology.

Oil & Gas Equipment and Services Market

Activity levels and demand for our products and services continued to improve in most of our markets during the first quarter of 2006. Recovering economies of developed nations, and the desire for improved standards of living among many in developing nations, have increased demand for oil and gas. As a result, oil and gas prices have increased significantly over the past few years, which has led to rising levels of exploration and development drilling in many oil and gas basins around the globe. The world-wide rig count, a good indicator of oilfield activity and spending, increased three percent from the fourth quarter of 2005 and 15 percent from the first quarter of 2005. Oil and gas companies have increased their levels of investment in new oil and gas wells, to reverse the trend of declining reserves and to grow production to satisfy the rising energy needs of the world. This has led to a level of drilling activity not seen since the early 1980’s, which has, in turn, resulted in steadily rising demand for oilfield services over the last several quarters. Much of the new incremental drilling activity is occurring in harsh environments, and employs increasingly sophisticated technology to find and produce reserves.

The rise in demand for drilling rigs has driven rig dayrates sharply higher over the past several quarters, which has increased cash flows and available financing to drilling contractors. Rising dayrates have caused many older rigs to be placed back into service, and we believe virtually every drilling rig that can operate is now working. The Company has played an important role in providing the equipment, consumables and services needed to reactivate many of these older rigs. Sales of individual drilling components have generally trended up over the past several quarters as operators reactivated rigs for service.

Higher utilization of drilling rigs has tested the capability of the world’s fleet of rigs, much of which is old and of limited capability. Technology has advanced significantly since most of the existing rig fleet was built. The industry invested little during the late 1980’s and 1990’s on new drilling equipment, but drilling technology progressed steadily nonetheless, as the Company and its competitors continued to invest in new and better ways of drilling. As a consequence, the safety, reliability, and efficiency of new, modern rigs surpass the performance of most of the older rigs at work today. Oil and gas producers demand top performance from drilling rigs, particularly at the premium dayrates that are being paid today. As a result of this trend, the Company has benefited from incremental demand for new products (such as our small iron roughnecks for land rigs, our LXT BOP’s, our Safe-T-Lite pump liner systems, among others) to upgrade certain rig functions to make them safer and more efficient.

Drilling rigs are now being pushed to drill deeper wells, more complex wells, highly deviated wells and horizontal wells, tasks which require larger rigs with more capabilities. Higher dayrates magnify the opportunity cost of rig downtime, and rigs are being pushed to maximize revenue days for their drilling contractor owners. The drilling process effectively consumes the mechanical components of a rig, which wear out and need periodic repair or replacement. We believe this process has been accelerated by the high levels of rig utilization seen over the past several quarters. In preceding years contractors could cannibalize mechanical components from their idle rigs, rather than purchase new components. As the fleet of idle rigs has dwindled, the availability of used components has dwindled as well, which has spurred incremental demand for rig components from the Company.

Changing methods of drilling have further benefited the Company’s business. Increasingly, hydraulic power – in addition to conventional mechanical rotary power – is being used to apply torque to the drill bit. This is done using downhole drilling motors powered by drilling fluids. The Company is a major provider of downhole drilling motors, and has seen demand for this

application of its drilling motors increase over the last several quarters. This trend has also increased demand for the Company’s high pressure mud pumps, which create the hydraulic power in the drilling fluids which drive the drilling motors.

While the increasingly efficient equipment provided by the Company has mitigated the effect, high activity levels have increased demand for personnel in the oilfield. Consequently, the Company, its customers and its suppliers have experienced wage inflation in certain markets. Hiring experienced drilling crews has been challenging for the drilling industry; however, the Company believes crews generally prefer working on newer, more modern rigs. The Company’s products which save labor and increase efficiency (such as its automatic slips and pipe handling equipment) also make the rig crew’s jobs easier, and make the rig a more desirable place to work.

Finally, the increase in drilling rig dayrates has made the economics of building new rigs compelling in many markets. For the first time in many years, the industry is actively building land rigs and offshore rigs. Many new offshore rig construction projects were announced throughout 2005, and there are approximately 62 new jackup rigs and 27 new floating rigs being constructed worldwide now. The available supply of offshore rigs declined during the third quarter of 2005 due to the impact of hurricanes Katrina and Rita, which seriously damaged or sunk several offshore rigs in the Gulf of Mexico.

Segment Performance

The Company’s Rig Technology group has been awarded many new orders for equipment for rigs being constructed or repaired around the world, and it completed the first quarter with a record backlog of $3,186.2 million as a result. New orders for capital equipment in to backlog were a record $1,308.1 million in the first quarter, a 39 percent increase from the fourth quarter of 2005. The company has the capability to supply up to approximately $48 million of equipment for a typical jackup rig, more than $150 million of equipment for a new floating rig, and effectively all of a new land rig (which range in price from less than $1 million to well over $20 million). Our strategy targets the high end of the market, emphasizing technology, quality and reliability. Most of the incremental growth in the backlog has been for offshore drilling packages for jackup, semi-submersible and drillship rigs being constructed or undergoing major refurbishment. The delivery of this equipment is typically tied to the construction schedule of the rig, which can take as long as four years to complete. As a result much of our backlog delivery extends well beyond 2006, and the Company has commissioning and installation work out as far as 2010. The Company expects to generate revenue of approximately $1.8 to $2.0 billion out of backlog during 2006. Currently approximately 78 percent of the drilling equipment in backlog is for offshore rigs, and 69 percent of the backlog is destined for international locations.

First quarter revenues for the Rig Technology group were $715.3 million, up 11 percent from the fourth quarter of 2005 and up 32 percent from the pro forma first quarter of 2005. Operating profit was $100.8 million or 14.1 percent of sales in the first quarter of 2006, compared to $80.5 million or 12.5 percent of sales in the fourth quarter of 2005 and $61.3 million or 11.3 percent of sales in the pro forma first quarter of 2005 (excluding merger, transaction and stock-based compensation from both periods, and including Varco results for the period prior to the closing of the merger). Operating flow-through or leverage (the period-to-period increase in operating profit divided by the increase in revenue) was 29 percent from the fourth quarter of 2005 to the first quarter of 2006, excluding merger, transaction and stock-based compensation from both periods. First quarter operating profit benefited from higher volumes, improving pricing, and merger-related cost savings partly offset by higher employee benefit costs and higher costs associated with purchased components. With record backlogs and improving efficiency our outlook for this business for the remainder of 2006 continues to be very good, but the nature of capital equipment shipments will continue to make quarter-to-quarter revenue changes volatile. We continue to expect normal long-term flowthroughs of 22% for this group, and hope to achieve 15 percent operating margins in the second quarter of 2006, driven by higher pricing and volumes.

The high oil and gas activity levels discussed above also increased demand for the Company’s Petroleum Services & Supplies group. The segment posted very good results for the first quarter of 2006, generating $541.0 million in revenue and $118.3 million in operating profit, or 21.9 percent operating margin. Sequential revenue growth from the fourth quarter of 2005 was five percent, slightly in excess of the growth in rig count worldwide. The group generated 61 percent operating profit flowthrough, despite higher personnel costs. Revenues grew 35 percent compared to the pro forma first quarter of 2005, substantially higher than the improvement in worldwide rig count over the same timeframe. The year-over-year revenue growth generated 39 percent operating profit flowthrough, due to higher volumes and improved pricing in most areas. The strong results were broad-based, with most products and services up sequentially and year-over-year, at higher margins. Our pipeline inspection services were an exception to this, where first quarter seasonal downturns drove lower sequential results. Mission Fluid King, Griffith/Vector downhole tools, Brandt solids control equipment and services, and Quality Tubing coiled tubing brands all posted double-digit growth as compared to the fourth quarter of 2005. Tuboscope pipe inspection and coating services posted sequential higher operating margins on higher pricing and volumes, as well. Additionally, our sales of fiberglass and composite pipe were roughly flat sequentially, as increases in sales to the oilfield were offset by lower seasonal sales in China, and lower industrial sales. Nevertheless, the fiberglass group posted sequentially higher operating margins in the first

quarter as compared to the fourth quarter of 2005. Most products and services within the Petroleum Services & Supplies group continue to gain increases in pricing in the range of three to seven percent each quarter, but the margin impact of these efforts is being mitigated somewhat by inflationary forces across our markets, as personnel, raw materials costs and energy expenses continue to rise.

We expect continued high levels of oilfield activity, coupled with price increases over the last few quarters, to drive continued improvement in the Petroleum Services & Supplies group in 2006, but expect to see our second quarter 2006 results affected by the seasonal breakup in Canada. In 2005 our Petroleum Services & Supplies operations in Canada saw operating profit decline over $10 million from the first quarter to the second, due to breakup. We expect the impact of breakup in Canada this year on the segment’s results to be in a similar range.

We continue to invest in the Petroleum Services & Supplies group to satisfy the needs of our customers for drilling motors, solids control equipment, instrumentation systems and other machinery we lease to drilling and production operations, to meet the rising demand we see in most oilfield markets around the world. This quarter, about 70 percent of our capital expenditures went to the Petroleum Services & Supplies group. Over the long run, and excluding swings in mix and other factors, we continue to expect operating profit flowthrough from this group to be in the range of 30 percent. Our overachievement of this level the past few quarters has largely been the result of the very favorable market and pricing environment we are enjoying.

The Company’s Distribution Services group has also benefited from higher levels of oilfield activity, which has spurred rising demand for the maintenance, repair and operating supplies it furnishes to the petroleum industry. Many oil companies and drilling contractors are outsourcing their purchasing of routine consumable items to the group, which offers greater purchasing power and sophisticated information management techniques. The segment performed well in the first quarter as a result. Revenue improved 6 percent from the fourth quarter, and 38 percent from the first quarter of 2005, to $326.5 million. Operating profit was $20.8 million in the first quarter. The group generated 32 percent operating profit flowthrough on the incremental revenue as compared to the fourth quarter of 2005, lifting margins 160 basis points to 6.4 percent of sales. Compared to the first quarter of 2005, operating profit flowthrough was 15 percent on the revenue increase. First quarter operating margins doubled compared to the first quarter of the prior year. The group has significantly improved its efficiency and reduced the costs of its products, while expanding selectively into attractive markets. Most of the sequential first quarter growth came from North America, with the mid-continent, Texas, and Canadian regions posting the largest increases. The Gulf Coast region saw sales ease slightly during the first quarter as fourth quarter 2005 sales in support of the hurricane rebuilding effort slowed. Strategic purchasing lifted our base margins by about 0.5 percent, and we benefited from mix as well. As a result of the strong performance, after-tax return on capital employed improved this quarter. We expect the Distribution Services group to continue to perform well throughout 2006, as we continue selective expansion into key international markets, strengthen alliances with customers, and leverage our buying power and IT infrastructure to keep costs low. We continue to expect long-term flowthroughs for the Distribution Services group, excluding swings in mix and other factors, to be around 10 percent.

Outlook

The outlook for the Company in 2006 is positive, as high commodity prices are expected to keep overall oil and gas activity high, and as the Company’s backlog for capital equipment sales has more than quadrupled since the beginning of 2005. High levels of drilling across the North America land market and the Middle East, in particular, are expected to continue to drive good results. Although the warm winter across North America has led to seasonally high gas storage levels which have reduced spot gas prices lately, we believe in the longer term this region faces significant gas deliverability issues. North America has been unable to meaningfully increase gas production despite significantly higher levels of gas drilling over the past few years. Oil remains subject to significant political risk in many regions as well, and the growth of China and other emerging economies has added significant demand to the oil markets. The Company expects the high commodity prices that have resulted to sustain very high levels of oilfield activity in 2006, provided the world’s major economies remain strong, and commodity prices remain high.

The Company expects to increase its capital spending about 40 percent in 2006, to a level in the range of $170 million, primarily to add rental equipment in its Petroleum Services & Supplies segment. Additionally the Company plans to add coiled tubing manufacturing capacity, and selectively invest in machining, assembly and fabrication equipment to improve its manufacturing efficiency in its Rig Technology and Petroleum Services & Supplies segments.

Operating Environment Overview

The Company’s results are dependent on, among other things, the level of worldwide oil and gas drilling, well remediation activity, the prices of crude oil and natural gas, capital spending by other oilfield service companies and drilling contractors, pipeline maintenance activity, and worldwide oil and gas inventory levels. Key industry indicators for the first quarters of 2006 and 2005, and the fourth quarter of 2005 include the following:

														%				%
														1Q06 vs.				1Q06 vs.
		1Q06*				1Q05*				4Q05*				1Q05				4Q05
Active Drilling Rigs:
U.S.			1,520				1,279				1,479				18.8	%			2.8	%
Canada			665				521				572				27.6	%			16.3	%
International			893				876				929				1.9	%			(3.9	%)
Worldwide			3,078				2,676				2,980				15.0	%			3.3	%
Active Workover Rigs:
U.S.			1,527				1,261				1,457				21.1	%			4.8	%
Canada			707				769				777				(8.1	%)			(9.0	%)
North America			2,234				2,030				2,234				10.0	%			—
West Texas Intermediate Crude Prices (per barrel)		$	63.18			$	49.88			$	60.42				26.7	%			4.6	%
Natural Gas Prices ($/mmbtu)		$	7.71			$	6.42			$	12.25				20.1	%			(37.1	%)

The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended March 31, 2006 on a quarterly basis:

Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude Price: Department of Energy, Energy Information Administration (www.eia.doe.gov).

The worldwide and U.S. quarterly average rig count increased 15.0% (from 2,676 to 3,078) and 18.8% (from 1,279 to 1,520), respectively, in the first quarter of 2006 compared to the first quarter of 2005. The average per barrel price of West Texas Intermediate Crude increased 26.7% (from $49.88 per barrel to $63.18 per barrel) while natural gas prices increased 20.1% (from $6.42 per mmbtu to $7.71 per mmbtu) in the first quarter of 2006 compared to the first quarter of 2005.

U.S. rig activity at April 28, 2006 was 1,608 rigs compared to the first quarter average of 1,520 rigs. The company believes that current industry projections are forecasting commodity prices to remain strong. However, numerous events could significantly alter these projections including political tensions in the Middle East, the acceleration or deceleration of the recovery of the U.S. and world economies, a build up in world oil inventory levels, or numerous other events or circumstances.

Results of Operations

Operating results by segment are as follows. The 2005 actual results include 20 days of Varco operations from the acquisition date of March 11, 2005 (in millions):

		Three Months Ended March 31,
		2006				2005
Revenue:
Rig Technology		$	715.3			$	424.4
Petroleum Services & Supplies			541.0				209.1
Distribution Services			326.5				235.9
Elimination			(71.0	)			(54.5	)
Total Revenue		$	1,511.8			$	814.9
Operating Profit:
Rig Technology		$	100.8			$	44.9
Petroleum Services & Supplies			118.3				35.2
Distribution Services			20.8				7.6
Unallocated expenses and eliminations			(27.4	)			(10.9	)
Integration costs and stock-based compensation			(14.7	)			(10.9	)
Total operating profit		$	197.8			$	65.9
Operating profit %:
Rig Technology			14.1	%			10.6	%
Petroleum Services & Supplies			21.9	%			16.8	%
Distribution Services			6.4	%			3.2	%
Total Operating Profit %			13.1	%			8.1	%

Rig Technology

Revenue from Rig Technology was $715.3 million, an increase of $290.9 million (68.5%) compared to the first quarter of 2005. The acquisition of Varco contributed approximately $118.9 million to the increase in revenue. The remainder of the increase can be attributed to the growing market for capital equipment, as evidenced by backlog growth over the past several quarters, and price increases implemented in 2005.

First quarter 2006 actual operating profit for Rig Technology was $100.8 million compared to $44.9 million for the first quarter of 2005, an increase of $55.9 million (124.5%). The acquisition of Varco contributed approximately $16.4 million of the increase in operating profit. In addition, operating profit benefited from higher volumes, improved pricing, and merger-related cost savings partly offset by higher employee benefit costs and higher costs associated with purchased components.

Petroleum Services & Supplies

Revenue from Petroleum Services & Supplies was $541.0 million for the first quarter of 2006 compared to $209.1 million for the first quarter of 2005, an increase of $331.9 million (158.7%). The majority of the increase is attributable to the addition of product lines acquired from Varco, which totaled approximately $192.9 million. The remaining increase is attributable to higher demand for virtually all products and services offered by the segment. These increases were the result of strong U.S. and worldwide drilling markets, as reflected by rig count increases of 18.8% and 15.0%, respectively, in the first quarter 2006 compared to the same period 2005. Petroleum Services & Supplies also benefited from price increases implemented during 2005.

Operating profit from Petroleum Services & Supplies was $118.3 million for the first quarter of 2006 compared to $35.2 million for the first quarter of 2005, an increase of $83.1 million (236.1%). The majority of the increase was attributable to the addition of product lines acquired from Varco. Incremental operating profit from these product lines was approximately $28.4 million.

The remaining increase was attributable to higher profitability across all products, driven by higher volumes and improved pricing.

Distribution Services

Revenue from Distribution Services was $326.5 million, an increase of $90.6 million (38.4%) during the first quarter of 2006 over the comparable 2005 period. The revenue growth was led by a strong demand for products in the US which was up 48%, followed by Canada up 28% and International revenues up 12%. US operations were especially impacted by robust increases in rig count activity in the Mid-Continent and Rocky Mountain regions where there is higher concentrations of drilling activity. Revenues generated from maintenance, repair and operating supplies were up 39%, spare parts up 36% and Tubular sales up 28%.

Operating income of $20.8 million in the first quarter of 2006 increased $13.2 million (173.7%) over the prior year results due to gross margin improvement on higher revenue volumes coupled with absorbing the revenue increase across an already established distribution infrastructure and expense base.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $27.4 million and $10.9 million for the quarters ended March 31, 2006 and 2005, respectively. The increase in operating costs was due to costs associated with Varco operations since the acquisition date and greater inter-segment profit eliminations.

Interest expense

Interest expense was $13.6 million for the first quarter of 2006 compared to $10.7 million for the same period of 2005. The increase was primarily due to interest costs associated with debt assumed in the Varco transaction. See summary of outstanding debt at March 31, 2006 under “Liquidity and Capital Resources”.

Provision for income taxes

The effective tax rate for the three months ended March 31, 2006 was 33.5% (33.6% excluding transactions costs associated with the Merger) compared to 35.1% for the same period in 2005 (32.7% excluding transaction costs associated with the merger), reflecting a lower percentage of earnings in foreign jurisdictions with lower tax rates and reduced benefits in the U.S. associated with export sales. The U.S. laws granting this tax benefit were repealed as part of the American Jobs Creation Act of 2004 and this benefit will be phased out after 2006. A new tax benefit associated with U.S. manufacturing operations passed into law under the same Act and will be phased in over the next five years. Whereas the timing of the phase out of the export tax benefit and the phase in of the manufacturing tax benefit may differ, we expect the tax reduction associated with the new manufacturing deduction, when fully implemented, to be similar in amount to the export benefit. We anticipate our tax rate for 2006 to be approximately 33.5% for continuing operations.

Liquidity and Capital Resources

At March 31, 2006, the Company had cash and cash equivalents of $263.0 million, and total debt of $839.0 million. At December 31, 2005, cash and cash equivalents were $209.4 million and total debt was $841.3 million. The Company’s outstanding debt at March 31, 2006 consisted of $200.0 million of 5.65% senior notes due 2012, $200.0 million of 7.25% senior notes due 2011, $150.0 million of 6.5% senior notes due 2011, $150.0 million of 5.5% senior notes due 2012, $100.0 million of 7.5% senior notes due 2008, and other debt $39.0 million. Included in other debt is the revaluation of the Varco debt assumed in the acquisition which resulted in additional debt recognition of $22.7 million. The difference is being amortized to interest expense over the remaining life of the debt.

For the first quarter of 2006, cash provided by operating activities was $86.6 million compared to cash used for operating activities of $42.5 million in the same period of 2005. Cash was provided by operations primarily through net income of $120.3 million plus non-cash charges of $38.4 million, and increases in billings in excess of costs of $96.3 million. These positive cash flows were offset by increases in receivables of $65.3 million, inventories of $155.2 million, and costs in excess of billings of $6.8 million. Receivables and costs in excess of billings increased due to greater revenue and activity in the first quarter of 2006 compared to the fourth quarter of 2005, while inventory increased due to growing backlog orders.

For the first quarter of 2006, cash used by investing activities was $51.2 million compared to cash provided of $152.1 million for the same period of 2005. Capital expenditures totaled approximately $30.2 million in the first quarter of 2006, primarily related to the Petroleum Services & Supplies service and rental businesses.

For the first quarter of 2006, cash provided by financing activities was $16.3 million compared to cash provided of $44.4 million for the same period of 2005. Cash proceeds from exercised stock options was $13.2 million.

On June 21, 2005, we amended and restated our existing $150 million revolving credit facility with a syndicate of lenders to provide the Company a $500 million unsecured revolving credit facility. This facility will expire in July 2010, and replaced the Company’s $175 million North American revolving credit facility and our Norwegian facility. The facility is available for general corporate purposes and acquisitions, including letters of credit and performance bonds. The Company has the right to increase the facility to $750 million and to extend the term of the facility for an additional year. At March 31, 2006, there were no borrowings against this facility, and there were $142 million in outstanding letters of credit. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.30% subject to a ratings-based grid, or the prime rate.

We believe cash generated from operations and amounts available under the credit facilities and from other sources of debt will be sufficient to fund operations, working capital needs, capital expenditure requirements and financing obligations. We also believe any significant increases in capital expenditures caused by any need to increase manufacturing capacity can be funded from operations or through debt financing.

We intend to pursue additional acquisition candidates, but the timing, size or success of any acquisition effort and the related potential capital commitments cannot be predicted. We expect to fund future cash acquisitions primarily with cash flow from operations and borrowings, including the unborrowed portion of the credit facility or new debt issuances, but may also issue additional equity either directly or in connection with acquisitions. There can be no assurance that additional financing for acquisitions will be available at terms acceptable to us.

Inflation has not had a material impact on our operating results or financial condition in recent years. We believe that the higher costs for energy, steel and other commodities experienced in 2005 have largely been mitigated by increased prices and component surcharges for the products we sell. However, higher steel, energy or other commodity prices may adversely impact future periods.

Critical Accounting Policies and Estimates

In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments related to allowance for doubtful accounts; inventory reserves; warranty accruals; impairments of long-lived assets (including goodwill); income taxes and pensions and other postretirement benefits. Our estimates are based on historical experience and on our future expectations that we believe are reasonable; the combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates, and those differences may be material.

Revenue Recognition

The Company’s products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post delivery obligations. Except for certain construction contracts described below, the Company records revenue at the time its manufacturing process is complete, the customer has been provided with all proper inspection and other required documentation, title and risk of loss has passed to the customer, collectibility is reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling cost are included in revenue and related costs are included in costs of sales.

Revenue Recognition under Long-term Construction Contracts

The Company uses the percentage-of-completion method to account for certain long-term construction contracts that are built or constructed to the customer’s specifications, and are manufactured outside the Company’s normal manufacturing process and marketed outside of the Company’s normal marketing channels. Projects recognized under the percentage-of-completion method include the following characteristics: 1) the contracts include custom designs for customer specific applications; 2) components are often modified with change orders throughout the project; 3) the structural design is unique and requires significant engineering efforts; and 4) construction projects often have progress payments. This method requires us to make estimates regarding the total costs of the project, our progress against the project schedule and the estimated completion date, all of which impact the amount of revenue and gross margin we recognize in each reporting period. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions, and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined.

Profit incentives are included in revenues when their realization is reasonably assured. Provisions for anticipated losses on uncompleted contracts are recorded in full when such losses become evident. The Company measures the extent of progress towards completion on these projects using either input or output based methods that are appropriate to the contract circumstances. The output methods are based upon engineering estimates and the input measures are based upon the ratio of costs incurred to the total projected costs.

Allowance for Doubtful Accounts

Allowance for doubtful accounts are determined on a specific identification basis when we believe that the required payment of specific amounts owed to us is not probable. A substantial portion of the Company’s revenues come from international oil companies, international oilfield service companies, and government-owned or government-controlled oil companies. Therefore, the Company has significant receivables in many foreign jurisdictions. If worldwide oil and gas drilling activity or changes in economic conditions in foreign jurisdictions deteriorate, our customers may be unable to repay these receivables, and additional allowances could be required.

Inventory Reserves

Reserves for inventory are determined based on our historical usage of inventory on-hand as well as our future expectations related to requirements to provide spare parts for our substantial installed base and new products. Changes in worldwide oil and gas drilling activity and the development of new technologies associated with the drilling industry could require the Company to record additional allowances to reduce the value of inventory to the lower of its cost or net realizable value.

Impairment of Long-Lived Assets (Including Goodwill)

Long-lived assets, which include property and equipment, goodwill, and identified intangible assets, comprise a significant amount of the Company’s total assets. The Company makes judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment periodically or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires the Company to make long-term forecasts of its future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for the Company’s products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions or the intended use of these assets could require a provision for impairment in a future period.

In accordance with SFAS 142, the Company performs a review of goodwill for impairment annually or earlier if indicators of potential impairment exist. The annual impairment tests are performed during the fourth quarter of each year. If it is determined that goodwill is impaired, that impairment is measured based on the amount by which the book value of goodwill exceeds its implied fair value. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Additional impairment assessments may be performed on an interim basis if the Company encounters events or changes in circumstances that would indicate that, more likely than not, the carrying amount of goodwill has been impaired. Fair value of the reporting units is determined based on internal management estimates, using a combination of three methods: discounted cash flow, comparable companies, and representative transactions.

Income Taxes

In accordance with the provisions of SFAS No. 109, Accounting for Income Taxes, we account for income taxes using the asset and liability method. In determining income (loss) for financial statement purposes, we must make certain estimates and judgments. These estimates and judgments affect the calculation of certain tax liabilities and the determination of the recoverability of certain of the deferred tax assets, which arise from temporary differences between the tax and financial statement recognition of revenue and expense. Deferred tax assets are also reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the recorded deferred tax assets will not be realized in future periods. In evaluating our ability to recover our deferred tax assets we consider all available positive and negative evidence including our past operating results, the existence of cumulative losses in the most recent years and our forecast of future taxable income. In estimating future taxable income, we develop assumptions including the amount of future state, federal and international pretax operating income, reversal of temporary differences and the implementation of feasible and prudent tax planning strategies. These assumptions require significant judgment about the forecasts of future taxable income and are consistent with the plans and estimates we are using to manage the underlying businesses.

We currently have recorded valuation allowances that we intend to maintain until it is more likely than not the deferred tax assets will be realized. Other than valuation allowances associated with tax attributes acquired through acquisitions, our income tax expense recorded in the future will be reduced to the extent of decreases in our valuation allowances. The realization of our remaining deferred tax assets is primarily dependent on future taxable income. Any reduction in future taxable income including but not limited to any future restructuring activities may require that we record an additional valuation allowance against our deferred tax assets. An increase in the valuation allowance would result in additional income tax expense in such period and could have a significant impact on our future earnings. If a change in a valuation allowance occurs, which was established in connection with an acquisition, such adjustment may impact goodwill rather than the income tax provision. In addition, the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations in a multitude of jurisdictions across our global operations. We recognize potential liabilities and record tax reserves for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. These tax liabilities are reflected net of related tax loss carry forwards. We adjust these reserves in light of changing facts and circumstances; however, due to the complexity of some of these uncertainties, the ultimate resolution may result in a payment that is materially different from our current estimate of the tax liabilities. If our estimate of tax liabilities proves to be less than the ultimate assessment, an additional charge to expense would result. If payment of these amounts ultimately proves to be less than the recorded amounts, the reversal of the liabilities would result in tax benefits being recognized in the period when we determine the reserves are no longer necessary. If the tax liabilities relate to tax uncertainties existing at the date of the acquisition of a business, the adjustment of such tax liabilities will result in an adjustment to the goodwill recorded at the date of acquisition.

Pensions and Other Postretirement Benefits

The Company accounts for our defined benefit pension plans in accordance with Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions (FAS 87), which requires that amounts recognized in the financial statements be determined on an actuarial basis. Significant elements in determining our pension income or expense in accordance with FAS 87 are the discount rate assumption and the expected return on plan assets. The discount rate used approximates the weighted average rate of return on high-quality fixed income investments whose maturities match the expected payouts. The expected return on plan assets is based upon the geometric mean of historical returns of a number of different equities, including stocks, bonds and U.S. treasury bills. The assumed long-term rate of return on assets is applied to a calculated value of plan assets which results in an estimated return on plan assets that is included in current year pension income or expense. The difference between this expected return and the actual return on plan assets is deferred and amortized against future pension income or expense. The total net expense associated with the Company’s defined benefit pension and postretirement benefit plans was approximately $1.2 million for the three months ended March 31, 2006, compared to $1.2 million for the same period of 2005.

Recently Issued Accounting Standards

In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” an amendment of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” SFAS No. 155 simplifies accounting for certain hybrid instruments under SFAS No. 133 by permitting fair value remeasurement for financial instruments containing an embedded derivative that otherwise would require bifurcation. SFAS No. 155 eliminates both the previous restriction under SFAS No. 140 on passive derivative instruments that a qualifying special-purpose entity may hold and SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets,” which provides that beneficial interests are not subject to the provisions of SFAS No. 133. SFAS No. 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, and clarifies that concentrations of credit risk in the form of subordination are not imbedded derivatives. SFAS No. 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring after the beginning of an entity’s fiscal year that begins after September 15, 2006. We are currently evaluating the effect SFAS No. 155 will have on our consolidated financial position, liquidity, or results from operations.

Forward-Looking Statements

Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected Merger synergies are forward-looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products, difficulties encountered in integrating mergers and acquisitions, and worldwide economic activity. You should also consider carefully the statements under “Risk Factors,” as disclosed in our Annual Report on Form 10-K for the year ending December 31, 2005, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Supplemental Unaudited Pro Forma Comparison

The pro forma information reflects results as if the Varco acquisition occurred at the beginning of the first quarter of 2005. The results include the estimated effect of purchase accounting adjustments, but do not include any effect from cost savings that may result from the merger and do not include restructuring charges, amortization of unvested compensation expense associated with options issued as part of the Merger, litigation gains and transaction-related costs in prior periods. The unaudited pro forma financial statements are presented for informational purposes only and are not necessarily indicative of actual results of operations or financial position that would have occurred had the transaction been consummated at the beginning of the period presented, nor are they necessarily indicative of future results.

Pro forma operating results by segment are as follows (in millions):

		Three Months Ended March 31,
		2006				2005
Revenue:
Rig Technology		$	715.3			$	543.3
Petroleum Services & Supplies			541.0				402.0
Distribution Services			326.5				235.9
Elimination			(71.0	)			(58.4	)
Total Revenue		$	1,511.8			$	1,122.8
Operating Profit:
Rig Technology		$	100.8			$	61.3
Petroleum Services & Supplies			118.3				63.6
Distribution Services			20.8				7.6
Unallocated expenses and eliminations			(27.4	)			(22.0	)
Transaction Costs			—				—
Total operating profit		$	212.5			$	110.5
Operating profit %:
Rig Technology			14.1	%			11.3	%
Petroleum Services & Supplies			21.9	%			15.8	%
Distribution Services			6.4	%			3.2	%
Total Operating Profit %			14.1	%			9.8	%

Rig Technology revenue on a pro forma basis increased $172.0 million (31.7%), from $543.3 million in the first quarter of 2005 to $715.3 million for the quarter ended March 31, 2006. This was principally due to the growing capital equipment market for drilling, workover and coiled tubing products discussed above. Rig Technology operating profit was $100.8 million for the first quarter, an increase of $39.5 million over the same period of 2005 on a pro forma basis. The increase was due to higher sales volumes and merger-related cost savings which were partly offset by increases in employee benefit costs and higher material costs. Backlog of the Rig Technology capital products was $3.2 billion at March 31, 2006, an increase of 39% over backlog of $2.3 billion at December 31, 2005. Pro forma orders for the period ending March 31, 2006 were $1.3 billion, reflective of the growing demand for the Company’s drilling and well servicing products.

Revenue from Petroleum Services & Supplies was $541.0 million for the first quarter of 2006 compared to $402.0 million for the first quarter of 2005 on a pro forma basis, an increase of $139.0 million (34.6%). The increase is attributable to a significant increase in U.S. and worldwide drilling activity; price increases implemented during 2005; and strong spare parts and consumable sales to support increased drilling. Operating profit for Petroleum Services & Supplies was $118.3 million for the first quarter of 2006 compared to $63.6 million for the first quarter of 2005 on a pro forma basis, an increase of $54.7 million (86.0%). Improved year-over-year results were posted across all products and services.

Revenue from Distribution Services was $326.5 million, an increase of $90.6 million (38.4%), during the first quarter of 2006 over the comparable 2005 period as all geographic regions showed improvement. Operating income of $20.8 million in the first quarter of 2006 increased $13.2 million over the prior year results, due to the increased revenue and higher base margins resulting from price increases on certain products.

Unallocated expenses and eliminations on a pro forma basis were $27.4 million and $22.0 million for the first quarter of 2006 and 2005. The increase in operating loss was due to greater inter-segment profit eliminations, greater employee benefit costs, and greater legal costs.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to changes in foreign currency exchange rates and interest rates. Additional information concerning each of these matters follows:

Foreign Currency Exchange Rates

We have operations in foreign countries, including Canada, Norway and the United Kingdom, as well as operations in Latin America, China and certain European countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that do impact income. We recorded foreign exchange losses in our income statement of approximately $0.6 million in the first three months of 2006, compared to $0.5 million in foreign exchange gains in the same period of the prior year. We do not believe that a hypothetical 10% movement in these foreign currencies would have a material impact on our earnings.

Some of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. In order to mitigate that risk, we may utilize foreign currency forward contracts to better match the currency of our revenues and associated costs. We do not use foreign currency forward contracts for trading or speculative purposes.

At March 31, 2006, we had also entered into several foreign currency forward contracts with notional amounts aggregating $299.8 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Euro, Norwegian Kroner and the Singapore Dollar. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. These foreign currency forward contracts are designated as cash flow hedging instruments and are fully effective. Based on quoted market prices as of March 31, 2006 for contracts with similar terms and maturity dates, we have recorded a gain for the first three months of $0.3 million, net of tax of $0.1 million, to adjust these foreign currency forward contracts to their fair market value. This gain is included in other comprehensive income in the consolidated balance sheet. We do not believe that a hypothetical 10% movement in these foreign currencies would have a material impact on our earnings related to these forward contracts.

The company also had several foreign currency forward contracts with notional amounts aggregating $611.9 million designated and qualifying as fair value hedges to hedge exposure to the British Pound Sterling, Euro, Norwegian Kroner and the Singapore Dollar. Based on quoted market prices as of March 31, 2006 for contracts with similar terms and maturity dates, we recorded a gain of $1.3 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated

losses on firm commitments. We do not believe that a hypothetical 10% movement in these foreign currencies would have a material impact on our earnings related to these forward contracts.

The Company has other financial market risk sensitive instruments denominated in foreign currencies totaling $32.1 million as of March 31, 2006 excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on these financial market risk sensitive instruments would affect net income by $2.1 million.

The counterparties to forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.

Interest Rate Risk

At March 31, 2006 our long term borrowings consisted of $100 million in 7.5% senior notes, $150 million in 6.5% senior notes, $200 million in 7.25% senior notes, $200 million in 5.65% senior notes and $150 million in 5.5% senior notes. We occasionally have borrowings under our other credit facilities, and a portion of these borrowings could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facilities, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to 6 months. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.

As of March 31, 2006, we had three interest rate swap agreements with an aggregate notional amount of $100 million associated with our 2008 senior notes. Under this agreement, we receive interest at a fixed rate of 7.5% and pay interest at a floating rate of six-month LIBOR plus a weighted average spread of approximately 4.675%. The swap agreements will settle semi-annually and will terminate in February 2008. The swap agreements originally entered into by Varco were recorded at their fair market value at the date of the Merger and no longer qualify as effective hedges under FAS 133. The swaps are marked-to-market for periods subsequent to the Merger and any change in their value will be reported as an adjustment to interest expense. The change in the fair market value of the interest swap agreements resulted in a $1.0 million increase in interest expense for the quarter ended March 31, 2006.

Item 4. Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the Company’s President and Chief Executive Officer along with the Company’s Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective as of the end of the period covered by this report to timely alert them to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company’s periodic Securities and Exchange Commission filings.

We are required to disclose certain changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our most recent fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. We implemented a worldwide financial reporting system in the first quarter of 2006. As a result, we made a variety of changes in our internal control structure. These changes did not impact the overall effectiveness of our controls.

PART II — OTHER INFORMATION

Item 6. Exhibits

   Reference is hereby made to the Exhibit Index commencing on Page 27.

SIGNATURE

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

Date: May 8, 2006		/s/ Clay C. Williams
		Clay C. Williams
		Senior Vice President and Chief Financial Officer
		(Duly Authorized Officer, Principal Financial and Accounting Officer)

INDEX TO EXHIBITS

(a)

Exhibits

31.1		Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
31.2		Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.