NOV Inc. - Quarter Report: 2009 March (Form 10-Q)

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2009


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

Commission File Number 1-12317

NATIONAL OILWELL VARCO, INC.

(Exact name of registrant as specified in its charter)


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

7909 Parkwood Circle Drive
Houston, Texas
77036-6565

(Address of principal executive offices)

(713) 346-7500

(Registrant’s telephone number, including area code)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of May 1, 2009 the registrant had 418,149,765 shares of common stock, par value $.01 per share, outstanding.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
PART II — OTHER INFORMATION
	Item 6. Exhibits
SIGNATURE
INDEX TO EXHIBITS
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)


	March 31,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,232		$	1,543
Receivables, net		2,892			3,136
Inventories, net		3,833			3,806
Costs in excess of billings		616			618
Deferred income taxes		206			271
Prepaid and other current assets		411			283

Total current assets		10,190			9,657

Property, plant and equipment, net		1,677			1,677
Deferred income taxes		147			126
Goodwill		5,281			5,225
Intangibles, net		4,241			4,300
Investment in unconsolidated affiliate		451			421
Other assets		93			73

Total assets	$	22,080		$	21,479


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	855		$	852
Accrued liabilities		2,467			2,376
Billings in excess of costs		2,083			2,161
Current portion of long-term debt and short-term borrowings		5			4
Accrued income taxes		358			230

Total current liabilities		5,768			5,623

Long-term debt		868			870
Deferred income taxes		2,144			2,134
Other liabilities		127			128

Total liabilities		8,907			8,755


Commitments and contingencies

Stockholders’ equity:
Common stock — par value $.01; 418,129,630 and 417,350,924 shares issued and outstanding at March 31, 2009 and December 31, 2008		4			4
Additional paid-in capital		8,005			7,989
Accumulated other comprehensive loss		(194	)		(161	)
Retained earnings		5,266			4,796

Total Company stockholders’ equity		13,081			12,628
Noncontrolling interests		92			96

Total stockholders’ equity		13,173			12,724

Total liabilities and stockholders’ equity	$	22,080		$	21,479

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(In millions, except per share data)


	Three Months Ended
	March 31,
	2009			2008
Revenue	$	3,481		$	2,685
Cost of revenue		2,442			1,888

Gross profit		1,039			797
Selling, general and administrative		319			228

Operating profit		720			569
Interest and financial costs		(13	)		(10	)
Interest income		2			16
Equity income in unconsolidated affiliate		28			—
Other income (expense), net		(36	)		13

Income before income taxes		701			588
Provision for income taxes		228			188

Net income		473			400
Net income attributable to noncontrolling interests		3			2

Net income attributable to Company	$	470		$	398


Net income attributable to Company per share:
Basic	$	1.13		$	1.12

Diluted	$	1.13		$	1.11


Weighted average shares outstanding:
Basic		416			356

Diluted		418			359

See notes to unaudited consolidated financial statements.

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


	Three Months Ended
	March 31,
	2009			2008
Cash flows from operating activities:
Net income	$	473		$	400
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		116			61
Excess tax benefit from exercise of stock options		—			(2	)
Equity income in unconsolidated affiliate		(28	)		—
Other non-cash items, net		51			22
Change in operating assets and liabilities, net of acquisitions:
Receivables		227			(153	)
Inventories		(39	)		(224	)
Costs in excess of billings		3			(123	)
Prepaid and other current assets		(126	)		(20	)
Accounts payable		3			55
Billings in excess of costs		(77	)		209
Other assets/liabilities, net		182			378

Net cash provided by operating activities		785			603


Cash flows from investing activities:
Purchases of property, plant and equipment		(79	)		(54	)
Business acquisitions, net of cash acquired		—			(129	)

Net cash used in investing activities		(79	)		(183	)


Cash flows from financing activities:
Borrowings against lines of credit and other debt		—			1
Payments against lines of credit and other debt		—			(147	)
Proceeds from exercise of stock options		1			11
Excess tax benefit from exercise of stock options		—			2

Net cash provided by (used in) financing activities		1			(133	)
Effect of exchange rates on cash		(18	)		10

Increase in cash equivalents		689			297
Cash and cash equivalents, beginning of period		1,543			1,842

Cash and cash equivalents, end of period	$	2,232		$	2,139


Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	10		$	9
Income taxes	$	78		$	32

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 generally accepted accounting principles (“GAAP”) 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 of National Oilwell Varco, Inc. (the “Company”) present information in accordance with GAAP 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 GAAP in the United States for complete consolidated financial statements and should be read in conjunction with our 2008 Annual Report on Form 10-K.

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, 2009 are not necessarily indicative of the results to be expected for the full year.

2. Grant Prideco Merger

The Grant Prideco merger has been accounted for as a purchase business combination. Assets acquired and liabilities assumed were recorded at their estimated fair values as of April 21, 2008. The total preliminary purchase price is $7,199 million, including Grant Prideco stock options assumed and estimated acquisition related transaction costs and is comprised of (in millions):


Consideration given to acquire the outstanding common stock of Grant Prideco:
Shares issued totaled approximately 56.9 million shares at $72.74 per share	$	4,135
Cash paid at $23.20 per share		2,932
Grant Prideco stock options assumed		55
Merger related transaction costs		77

Total preliminary purchase price	$	7,199

Preliminary Purchase Price Allocation

The primary area of the purchase price allocation, which is not yet finalized, relates to adjustments to deferred taxes for jurisdictional classification. The following table, set forth below, displays the total preliminary purchase price allocated to Grant Prideco’s net tangible and identifiable intangible assets based on their estimated fair values as of April 21, 2008 (in millions):


Cash and cash equivalents	$	171
Receivables		420
Assets held for sale, net		784
Inventories		611
Prepaid and other current assets		210
Property, plant and equipment		392
Goodwill		2,803
Intangibles		3,696
Investment in unconsolidated affiliate		512
Other assets		98
Accounts payable and accrued liabilities		(316	)
Accrued income taxes		(624	)
Long-term debt		(176	)
Deferred income taxes		(1,336	)
Minority interest		(25	)
Other liabilities		(21	)

Total preliminary purchase price	$	7,199

Unaudited Pro Forma Financial Information

The unaudited financial information in the table below summarizes the combined results of operations of National Oilwell Varco and Grant Prideco, on a pro forma basis, as though the companies had been combined as of the beginning of 2008. The pro forma financial information is presented for informational purposes only and may not be indicative of the results of operations that would have been achieved if the Merger had taken place at the beginning of 2008. The pro forma financial information for the three months ending March 31, 2008 includes the business combination accounting effect on historical Grant Prideco revenues, adjustments to depreciation on acquired property, amortization charges from acquired intangible assets, financing costs on new debt in connection with the Merger and related tax effects. (in millions, except per share data):


	Three Months Ended
	March 31,
	2009		2008
Total revenues	$	3,481	$	3,169

Net income attributable to Company	$	470	$	452

Basic net income attributable to Company per share	$	1.13	$	1.09

Diluted net income attributable to Company per share	$	1.13	$	1.09

3. Inventories, net

Inventories consist of (in millions):


	March 31,		December 31,
	2009		2008
Raw materials and supplies	$	745	$	739
Work in process		1,491		1,326
Finished goods and purchased products		1,597		1,741

Total	$	3,833	$	3,806

4. Accrued Liabilities

Accrued liabilities consist of (in millions):


	March 31,		December 31,
	2009		2008
Compensation	$	185	$	258
Customer prepayments and billings		784		912
Warranty		144		114
Interest		15		11
Taxes (non income)		75		76
Insurance		53		50
Accrued purchase orders		835		688
Fair value of derivatives		168		59
Other		208		208

Total	$	2,467	$	2,376

Service and Product Warranties

The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with SFAS 5. Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product performance issues and accrues for them when they are encountered.

The changes in the carrying amount of service and product warranties are as follows (in millions):


Balance, December 31, 2008	$	114

Net provisions for warranties issued during the year		44
Payments		(13	)
Foreign currency translation		(1	)


Balance, March 31, 2009	$	144

5. Costs and Estimated Earnings on Uncompleted Contracts

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


	March 31,			December 31,
	2009			2008
Costs incurred on uncompleted contracts	$	5,149		$	4,776
Estimated earnings		2,581			2,277

		7,730			7,053
Less: Billings to date		9,197			8,596

	$	(1,467	)	$	(1,543	)


Costs and estimated earnings in excess of billings on uncompleted contracts	$	616		$	618
Billings in excess of costs and estimated earnings on uncompleted contracts		(2,083	)		(2,161	)

	$	(1,467	)	$	(1,543	)

6. Comprehensive Income

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


	Three Months Ended
	March 31,
	2009			2008
Net income	$	473		$	400
Currency translation adjustments, net of tax		(55	)		27
Derivative financial instruments, net of tax		22			21
Change in defined benefit plans, net of tax		—			(1	)

Comprehensive income		440			447
Comprehensive income attributable to noncontrolling interest		3			2

Comprehensive income attributable to Company	$	437		$	445

The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in Other Comprehensive Income in accordance with SFAS 52, “Foreign Currency Translation.” For the three months ended March 31, 2009, a majority of these local currencies weakened against the U.S. dollar resulting in a net decrease to Other Comprehensive Income of $55 million (net of tax of $25 million) upon the translation of their financial statements from their local currency to the U.S. dollar.

Derivative financial instruments are related to the effects of currency movement, which they are designated to offset. The increase in Other Comprehensive Income of $22 million (net of tax of $12 million) for the three months ended March 31, 2009 was due to the substantial weakening of the hedged currencies against the U.S. dollar. The change in the value of the derivatives is reflected in Other Comprehensive Income until the resulting unrealized gain or loss from the underlying hedged transactions are completed and reported in earnings.

7. Business Segments

Operating results by segment are as follows (in millions):


	Three Months Ended
	March 31,
	2009			2008
Revenue:
Rig Technology	$	2,199		$	1,603
Petroleum Services & Supplies		1,014			830
Distribution Services		408			366
Elimination		(140	)		(114	)

Total Revenue	$	3,481		$	2,685


Operating Profit:
Rig Technology	$	606		$	406
Petroleum Services & Supplies		164			195
Distribution Services		25			19
Unallocated expenses and eliminations		(75	)		(51	)

Total Operating Profit	$	720		$	569


Operating Profit %:
Rig Technology		27.6	%		25.3	%
Petroleum Services & Supplies		16.2	%		23.5	%
Distribution Services		6.1	%		5.1	%
Total Operating Profit %		20.7	%		21.2	%

The Company’s first quarter 2008 results do not include Grant Prideco, which was acquired on April 21, 2008.

8. Debt

Debt consists of (in millions):


	March 31,		December 31,
	2009		2008
Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011	$	150	$	150

Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011		207		208

Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012		200		200

Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012		151		151

Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015		151		151

Other		14		14

Total debt		873		874
Less current portion		5		4

Long-term debt	$	868	$	870

Senior Notes

In connection with the Merger of Grant Prideco, the Company completed an exchange offer relative to the $175 million of 6.125% Senior Notes due 2015 previously issued by Grant Prideco. On April 21, 2008, $151 million of Grant Prideco Senior Notes were exchanged for National Oilwell Varco Senior Notes. The National Oilwell Varco Senior Notes have the same

interest rate, interest payment dates, redemption terms and maturity as the Grant Prideco Senior Notes. In November 2008, the Company repurchased $23 million of the unexchanged Grant Prideco Senior Notes.

Revolving Credit Facilities

On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2 billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility. At March 31, 2009, there were no borrowings against these facilities, and there were $636 million in outstanding letters of credit issued under these facilities, resulting in $1,364 million of funds available under this revolving credit facility at March 31, 2009. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% subject to a ratings-based grid, or the prime rate. In early February 2009, we terminated early the $1 billion, 364-day revolving credit facility, which matured April 20, 2009.

The Company also had $2,515 million of additional outstanding letters of credit at March 31, 2009, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. We were in compliance with all covenants at March 31, 2009.

Other

Other debt includes approximately $6 million in promissory notes due to former owners of businesses acquired.

9. Tax

The effective tax rate for the three months ended March 31, 2009 was 32.5% compared to 32.0% for the same period in 2008. The rate increase in 2009 is primarily due to an increase in the valuation allowance for losses that may not be deducted in future years.

The difference between the effective tax rate reflected in the provision for income taxes and the U.S. federal statutory rate of 35% was as follows (in millions):


	Three Months Ended
	March 31,
	2009			2008
Federal income tax at U.S. federal statutory rate of 35.0%	$	245		$	206

Foreign income tax rate differential		(32	)		(20	)
State income tax, net of federal benefit		6			6
Foreign dividends, net of foreign tax credits		1			2
Benefit of U.S. Manufacturing Deduction		(4	)		(2	)
Nondeductible expenses		8			3
Other		4			(7	)

Provision for income taxes	$	228		$	188

The Company accounts for uncertainty in income taxes in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes” and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a return. Under FIN 48, the impact of an uncertain income tax position, in management’s opinion, on the income tax return must be recognized at the largest amount that is more-likely-than not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has a less than 50% likelihood of being sustained.

During the three month period ended March 31, 2009, the Company recognized no material changes in the balance of unrecognized tax benefits. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within 12 months of this reporting date.

The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The Company has significant operations in the U.S., Canada, the U. K., the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdiction vary by legal entity, but are generally open in the U.S. for the tax years after 2003 and outside the U.S. for tax years ending after 2001.

To the extent penalties and interest would be assessed on any underpayment of income tax, such accrued amounts have been classified as a component of income tax expense in the financial statements.

10. Stock-Based Compensation

The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights. The number of shares authorized under the Plan is 15 million. As of March 31, 2009, 1,412,568 shares remain available for future grants under the Plan, all of which are available for grants of stock options, performance-based share awards, restricted stock awards, phantom shares, stock payments and stock appreciation rights. Total stock-based compensation for all share-based compensation arrangements under the Plan was $16 million and $13 million for the three months ended March 31, 2009 and 2008, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $5 million and $4 million for the three months ended March 31, 2009 and 2008, respectively.

During the three months ended March 31, 2009, the Company granted 3,206,400 stock options and 743,400 restricted stock awards, which includes 309,000 performance-based restricted stock awards. The stock options were granted February 20, 2009 with an exercise price of $25.96. These options generally vest over a three-year period from the grant date. The restricted stock awards were granted February 20, 2009 and vest on the third anniversary of the date of grant. The performance-based restricted stock awards were granted February 20, 2009. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s average operating income growth, measured on a percentage basis, from January 1, 2009 through December 31, 2011 exceeding the median operating income level growth of a designated peer group over the same period.

11. Derivative Financial Instruments

The Financial Accounting Standards Board (“FASB”) issues Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”), requires companies to recognize all of its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed by using derivative instruments are foreign currency exchange rate risk, and interest rate risk. Forward contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk on forecasted revenue and expenses denominated in currencies other than the functional currency of the operating unit (cash flow hedge). Other forward exchange contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk associated with certain firm commitments denominated in currencies other than the functional currency of the operating unit (fair value hedge). In addition the Company will enter into non-designated forward contracts against various foreign currencies to manage the foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts (non-designated hedge). Interest rate swaps are entered into to manage interest rate risk associated with the Company’s fixed and floating-rate borrowings.

In accordance with SFAS 133 the Company records all derivative financial instruments at their fair value in our consolidated balance sheet. Except for certain non-designated hedges and interest rate swap agreements discussed below, all derivative financial instruments we hold are designated as either cash flow or fair value hedges and are highly effective in offsetting movements in the underlying risks. Such arrangements typically have terms between two and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog. We may also use interest rate contracts to mitigate our exposure to changes in interest rates on anticipated long-term debt issuances.

As of March 31, 2009, the Company did not have any interest rate swaps and our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that is subject to a particular currency risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are cash flows associated with forecasted revenues). The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffectiveness portion) or hedge components excluded from the assessment of effectiveness, are recognized in the Consolidated Statements of Income during the current period.

To protect against the reduction in value of forecasted foreign currency cash flows resulting from forecasted sales and expenses, the Company has instituted a cash flow hedging program. The Company hedges portions of its forecasted revenues and expenses denominated in nonfunctional currencies with forward contracts. When the U.S. dollar strengthens against the foreign currencies, the decrease in present value of future foreign currency revenue and costs is offset by gains in the fair value of the forward contracts designated as hedges. Conversely, when the U.S. dollar weakens, the increase in the present value of future foreign currency cash flows is offset by losses in the fair value of the forward contracts.

As of March 31, 2009, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and costs:


	Currency
Foreign Currency	Denomination
	(in millions)
British Pound Sterling	£	55
Danish Kroner	DKK	147
Euro	€	376
Norwegian Kroner	NOK	8,931
U.S. Dollar	$	193

Fair Value Hedging Strategy

For derivative instruments that are designated and qualify as a fair value hedge (i.e., hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is subject to a particular risk), the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings (e.g., in “revenue” when the hedged item is a contracted sale).

The Company enters into forward exchange contracts to hedge certain firm commitments of revenue and costs that are denominated in currencies other than the functional currency of the operating unit. The purpose of the Company’s foreign currency hedging activities is to protect the Company from risk that the eventual U.S. dollar-equivalent cash flows from the sale of products to customers will be adversely affected by changes in the exchange rates.

As of March 31, 2009, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency fair values of firm commitments of revenues and costs:


	Currency
Foreign Currency	Denomination
	(in millions)
Euro	€	1
Korean Won	KRW	1,917
U.S. Dollar	$	95

Non-designated Hedging Strategy

For derivative instruments that are non-designated the gain or loss on the derivative instrument subject to the hedged risk (i.e. nonfunctional currency monetary accounts) are recognized in the same line item associated with the hedged item in current earnings.

The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary accounts. The purpose of the Company’s foreign currency hedging activities is to protect the Company from risk that the eventual U.S. dollar-equivalent cash flows from the nonfunctional currency monetary accounts will be adversely affected by changes in the exchange rates.

As of March 31, 2009, the Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts:


	Currency
Foreign Currency	Denomination
	(in millions)
British Pound Sterling	£	6
Danish Kroner	DKK	48
Euro	€	105
Norwegian Kroner	NOK	2,986
Swedish Kroner	SEK	14
U.S. Dollar	$	479

As of March 31, 2009, the Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions):


	March 31, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
Derivatives designated as hedging instruments under SFAS 133

Foreign exchange contracts	Prepaid and other current assets	$	49	Accrued liabilities	$	76
Foreign exchange contracts	Other Assets		11	Other Liabilities		25


Total derivatives designated as hedging instruments under SFAS 133		$	60		$	101

Derivatives not designated as hedging instruments under SFAS 133

Foreign exchange contracts	Prepaid and other current assets	$	2	Accrued liabilities	$	48
Foreign exchange contracts	Other Assets		30	Other Liabilities		3


Total derivatives not designated as hedging instruments under SFAS 133		$	32		$	51


Total derivatives		$	92		$	152

The Effect of Derivative Instruments on the Consolidated Statement of Income
For the Period Ended March 31, 2009
(in millions)

Location of Gain (Loss)

Recognized in Income on

Amount of Gain (Loss)

Location of Gain (Loss)

Amount of Gain (Loss)

Derivative (Ineffective

Recognized in Income on

Amount of Gain (Loss)

Reclassified from

Portion and Amount

Derivative (Ineffective

Derivatives in SFAS 133

Recognized in OCI on

Accumulated OCI into

Excluded from

Portion and Amount

Cash Flow Hedging

Derivative (Effective

Income

Income (Effective

Effectiveness

Excluded from

Relationships

Portion) (a)

(Effective Portion)

Portion)

Testing)

Effectiveness Testing) (b)

Foreign exchange contracts

Revenue

)

Other income (expense), net

)

Foreign exchange contracts

—

Cost of revenue

(28

)

Total

(29

)

Location of Gain (Loss)

Derivatives in SFAS 133

Location of Gain (Loss)

Amount of Gain (Loss)

SFAS 133

Recognized in Income on

Fair Value

Recognized in Income

Recognized in Income on

Fair Value Hedge

Related

Related Hedged

Hedging Relationships

on Derivative

Derivative (a)

Relationships

Hedged Item

Items

Foreign exchange contracts

Revenue

)

Firm commitments

Revenue

Foreign exchange contracts

Cost of revenue

Firm commitments

Cost of revenue

)

Total

)


Derivatives Not Designated as	Location of Gain (Loss)	Amount of Gain (Loss)
Hedging Instruments under	Recognized in Income	Recognized in Income on
SFAS 133	on Derivative	Derivative (a)
Foreign exchange contracts	Other income (expense), net		(20	)


Total			(20	)


(a)		The Company expects that $13 million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying

(b)		The amount of gain (loss) recognized in income represents $(9) million related to the ineffective portion of the hedging relationships and $3 million related to the amount excluded from the assessment of the hedge effectiveness.

We assess the functional currencies of our operating units to ensure that the appropriate currencies are utilized in accordance with the guidance of SFAS No. 52, Foreign Currency Translation. Effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian krone to the U.S. dollar to more appropriately reflect the primary economic environment in which they operate. This change was precipitated by significant changes in the economic facts and circumstances including, the increased order rate for large drilling platforms and components technology, the use of our Norway unit as our preferred project manager of these projects, increasing revenue and cost base in U.S. dollars, and the implementation of an international cash pool denominated in U.S. dollars. As a Norwegian krone functional unit, Norway was subject to increasing foreign currency exchange risk as a result of these changes in its economic environment and was dependent upon significant hedging transactions to offset its non-functional currency positions.

At December 31, 2007, our Norway operations had foreign currency forward contracts with notional amounts aggregating $2,551 million with a fair value of $91 million to mitigate foreign currency exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the functional currency, the Company terminated these hedges. The related net gain position of $109 million associated with the terminated hedges has been deferred and is being recognized into earnings in the future period(s) the forecasted transactions affect earnings, of which $33 million remains to be recognized into earnings at March 31, 2009. The Company has subsequent to January 1, 2008, entered into new hedges to cover the exposures as a result of the changes to U.S. dollar functional. At March 31, 2009, our Norway operations had derivatives with $2,515 million in notional value with a fair value liability of $24 million.

12. Net Income Attributable to Company Per Share

The following table sets forth the computation of weighted average basic and diluted shares outstanding (in millions, except per share data):


	Three Months Ended
	March 31,
	2009		2008
Numerator:
Net income attributable to Company	$	470	$	398

Denominator:
Basic—weighted average common shares outstanding		416		356

Dilutive effect of employee stock options and other unvested stock awards		2		3

Diluted outstanding shares		418		359


Net income attributable to Company per share:
Basic	$	1.13	$	1.12

Diluted	$	1.13	$	1.11

In addition, we had stock options outstanding that were anti-dilutive totaling 7 million at March 31, 2009 and 1 million at March 31, 2008.

13. Subsequent Events

Subsequent to March 31, 2009, the Company has acquired the four businesses, ASEP Group Holding BV (“ASEP”), Anson Ltd. (“Anson”), Spirit Fluids Ltd (“Spirit Fluids”), and Spirit Minerals LP (“Spirit Minerals”), for a total of approximately $375 million. The results of operations from ASEP will be included in the Rig Technology segment and the results of operations from Anson, Spirit Fluids, and Spirit Minerals will be included in the Petroleum Services & Supplies segment.

During the second quarter of 2009 the Company announced a voluntary early retirement program and expects to report a $45 million to $60 million charge associated with enhanced retirement benefits being offered to some of its long-tenured employees in the U.S.

14. Recently Issued Accounting Standards

financial statements on a recurring basis (at least annually) until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company adopted the provisions of SFAS 157 for financial assets and liabilities as of January 1, 2008. At March 31, 2009, the Company has determined that its financial assets of $101 million and liabilities of $152 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At March 31, 2009, the fair value of the Company’s foreign currency forward contracts totaled $(60) million. There was no significant impact to the Company’s consolidated financial statements from the adoption of SFAS 157.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”). SFAS 141R provides revised guidance on how acquirers recognize and measure the consideration transferred, identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired in a business combination. SFAS 141R also expands required disclosures surrounding the nature and financial effects of business combinations. SFAS 141R is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted SFAS 141R There was no significant impact to the Company’s first quarter consolidated financial statements from the adoption of SFAS 141R. The Company expects that in future periods this new standard will impact certain aspects of its accounting for business combinations on a prospective basis, including the determination of fair values assigned to certain purchased assets and liabilities.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 160 establishes requirements for ownership interests in subsidiaries held by parties other than the Company (previously called minority interests) be clearly identified, presented, and disclosed in the consolidated statement of financial position within equity, but separate from the parent’s equity. All changes in the parent’s ownership interests are required to be accounted for consistently as equity transactions and any noncontrolling equity investments in deconsolidated subsidiaries must be measured initially at fair value. SFAS 160 is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. However, presentation and disclosure requirements must be retrospectively applied to comparative financial statements. On January 1, 2009, the Company adopted SFAS 160, and reclassified noncontrolling interests in the amounts of $92 million and $96 million from the mezzanine section to equity in the March 31, 2009 and December 31, 2008 balance sheets, respectively.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements for derivative instruments and hedging activities, with the intent to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial statements. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. On January 1, 2009, the Company adopted SFAS 161. See Note 11. “Derivative Financial Instruments”, in the notes to the consolidated financial statements.

In April 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3”). FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets". The objective of this FSP is to improve the consistency between the useful life of a recognized intangible asset under Statement No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted FSP SFAS 142-3. There was no significant impact to the Company’s consolidated financial statements from the adoption of FSP SFAS 142-3.

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

Introduction

National Oilwell Varco, Inc. (the “Company”) 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; rig instrumentation 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 adding additional operations in the United States, Canada, Norway, the United Kingdom, China, Belarus, and India.

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 drill pipe, wired drill pipe, transfer pumps, solids control systems, drilling motors, drill bits, reamers and other downhole tools, 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 drill pipe, line pipe, 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 adding additional operations in the United States, Canada, the United Kingdom, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, and the United Arab Emirates.

Distribution Services

Our Distribution Services segment provides maintenance, repair and operating supplies (“MRO”) 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 Mexico, 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 is determined primarily by the level of drilling, servicing, and oil and gas production activities.

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2008, we identified our most critical accounting policies. In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are most critical in nature which are related to revenue recognition under long-term construction contracts; allowance for doubtful accounts; inventory reserves; impairments of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets and income taxes. 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.

Goodwill and Other Indefinite — Lived Intangible Assets

The Company has approximately $5.3 billion of goodwill and $0.8 billion of other intangible assets with indefinite lives on its consolidated balance sheet as of March 31, 2009. The Company tests goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that goodwill or other indefinite-lived intangible assets might be impaired. The annual impairment test is performed during the fourth quarter of each year. The Company performed its annual impairment analysis in the fourth quarter of 2008 and due to significant drops in both commodity prices and rig activity in the fourth quarter of 2008; the Company updated its impairment analysis as of December 31, 2008. Based on its analysis, the Company did not report any impairment of goodwill and other indefinite-lived intangible assets for the year ended December 31, 2008.

The level of drilling activity during the first quarter of 2009 averaged 2,681 rigs, a decline of 21 percent compared to the average of 3,395 rigs working during the fourth quarter of 2008. However, the price of crude oil has improved in recent weeks, rising from $35-$40 per barrel through much of the first quarter to $50-$55 per barrel presently. Prices for future oil deliveries are higher ($63.77 per barrel for December 2010 deliveries, for example), and, likewise, future gas prices are considerably higher than current spot pricing ($6.74/mmbtu for December 2010 deliveries versus $3.55/mmbtu currently), indicating an expectation of recovery of commodity prices within the next several quarters. Based on these factors, the Company has not identified any impairment indicators since December 31, 2008.

The Company will continue to closely monitor indicators of impairment which could include, but are not limited to, further declines in worldwide rig activity, further declines in commodity prices or futures, or further significant economic declines. If such further deterioration of indicators occurs, and the Company believes that these negative trends are likely to persist for a prolonged period of time, then the Company’s expected future earnings and cash flows from operations would be adversely impacted. This may result in impairment to either or both goodwill and indefinite-lived intangible assets, and such impairment may be material.

EXECUTIVE SUMMARY

National Oilwell Varco generated earnings of $470 million or $1.13 per fully diluted share in its first quarter ended March 31, 2009, on revenues of $3,481 million. Revenue increased 30 percent and net income attributable to the Company increased 18 percent from the first quarter of 2008, due in part to our acquisition of Grant Prideco, Inc., discussed below. Revenue declined nine percent and net income attributable to the Company declined 20 percent from the fourth quarter of 2008, due to a downturn in economic activity during the first quarter of 2009. Operating income was $720 million or 20.7 percent of sales for the first quarter, compared to $857 million or 22.5 percent of sales in the fourth quarter of 2008, and $569 million or 21.2 percent of sales in the first quarter of 2008.

Grant Prideco Acquisition

On April 21, 2008 the Company completed its acquisition of Grant Prideco, Inc. for a combination of approximately $3.0 billion in cash and the issuance of 56.9 million shares of National Oilwell Varco common stock. The Grant Prideco merger further strengthened National Oilwell Varco’s position as manufacturer to the oilfield. Its drill bits and reamers are being integrated into the Company’s offering of drilling motors, non-magnetic drill collars, jars and shock tools, to complement its comprehensive package of bottomhole assembly tools used to drill complex wellpaths. Additionally, Grant Prideco’s drill pipe products are purchased and consumed by the Company’s existing drilling contractor customer base. The Company believes that consumption of drill pipe per foot of hole drilled, or per rig running, has been increasing due to the rising complexity of wellpath designs. Overall the acquisition better positioned National Oilwell Varco to capitalize on continued application of horizontal, directional and extended-reach drilling, through both drill pipe and drill bit product sales. Integration of the business has proceeded well. The Company is introducing new drill pipe tracking products, and expanding OEM drill pipe repair and maintenance offerings through its worldwide network of pipe service operations. The Company is also consolidating a number of bit and downhole tool sales facilities worldwide, and leveraging combined manufacturing and marketing capabilities.

Oil & Gas Equipment and Services Market

Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks are responding vigorously, but credit and financial markets have not yet recovered, and a credit-driven worldwide economic recession deepened during the first quarter. Asset and commodity prices, including oil and gas prices, have declined sharply. After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to an average of $42.91 per barrel range during the first quarter. Higher oil and gas prices over the past several years have led to high levels of exploration and development drilling in many oil and gas basins around the globe, but this is slowing, at least in the near term. The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but has decreased to 955 rigs as of April 2009, as a result of the lower commodity prices and tight credit. Many oil and gas operators reliant on external financing to fund their drilling programs are curtailing some of their drilling activity in view of tighter credit markets and lower commodity prices. So far this appears to be having the greatest impact on gas drilling across North America. Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings. Therefore we expect international drilling activity to be less impacted by the credit crisis, but the international rig count is showing some declines nonetheless, falling from its September 2008 peak of 1,108 to 1,012 in March 2009. During the first quarter of 2009 the Company saw its Petroleum Services & Supplies segment and its Distribution Services segment affected most acutely by a drilling downturn (revenues down 27 percent and down 16 percent, respectively, from the fourth quarter of 2008) while the Company’s Rig Technology segment was less impacted in the short term owing to its high level of backlog (revenues improved five percent from the fourth quarter of 2008).

Recent downturns follow an extended period of high drilling activity which fueled strong demand for oilfield services since 2003. Incremental drilling activity through the upswing shifted toward harsh environments, employing increasingly sophisticated technology to find and produce reserves. 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. 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. The drilling process effectively consumes the mechanical components of a rig, which wear out and need periodic repair or replacement. This process has been accelerated by

very high rig utilization and wellbore complexity. Drilling consumes rigs; more complex and challenging drilling consumes rigs faster.

The industry responded by launching many new rig construction projects since 2005, to retool the existing fleet of jackup rigs (more than 75 percent of the existing 440 jackup rigs are more than 20 years old); to replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and to build out additional ultradeep floating drilling rigs, including semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet, and that declining dayrates may accelerate the retirement of older rigs. As a result of these trends the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at March 31, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders have declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $9.6 billion by March 31, 2009. These are the first backlog declines posted since National Oilwell and Varco merged in 2005. The Company expects the backlog to continue to decline during 2009 as revenue out of backlog is likely to exceed inbound new orders.

The land rig backlog comprised 12 percent and equipment destined for offshore operations comprised 88 percent of the total backlog as of March 31, 2009. Equipment destined for international markets totaled 91 percent of the backlog. The Company believes that its existing contracts for rig equipment are very strong in that they carry significant down payment and progress billing terms favorable to the ultimate completion of these projects, and generally do not allow customers to cancel projects for convenience. For this reason we do not expect the credit crisis or softer market conditions to result in material cancelation of contracts or abandonment of major projects; however, there can be no assurance that such discontinuance of projects will not occur, particularly if the credit crisis or economic downturn deepens significantly. The Company had approximately $380 million of projects in its March 31, 2009 backlog that it considers at risk.

Segment Performance

Rig Technology generated $2,199 million in revenue and $606 million in operating profit in the first quarter of 2009, yielding a record operating margin for the segment of 27.6 percent. The segment generated 44 percent operating leverage or flowthrough (the increase in operating profit divided by the increase in revenue) on five percent revenue growth from the fourth quarter of 2008, and 34 percent operating leverage on 37 percent revenue growth from the first quarter of 2008. The revenue growth from the fourth quarter was due to higher revenue out of backlog, which improved 15 percent sequentially to $1,688 million. As of March 31, 2009 the scheduled outflow of revenue from backlog is expected to be in the range of $3.8 billion for the remainder of 2009, $4.7 billion in 2010, and $1.1 billion for 2011. From 2005 through the current quarter, the segment has delivered a total of 54 newly built offshore rigs. Aftermarket spare parts and services revenue, and sales of smaller capital items which do not qualify for booking into the backlog, declined 18 percent from the fourth quarter. This was due mostly to lower purchases by North American land customers who are curtailing expenditures and cannibalizing spares and equipment from idle rigs to deploy onto working rigs.

The Petroleum Services & Supplies segment generated revenues of $1,014 million and operating profit of $164 million or 16.2 percent of sales in the first quarter of 2009. Revenues declined 27 percent from the fourth quarter of 2008, and decremental operating leverage was 48 percent on the sequential decline, leading to a sharp sequential decline in operating margins for the segment. On a combined adjusted basis for a full first quarter 2008 contribution from Grant Prideco, Inc. (including estimated fixed asset and intangible asset stepup impact but excluding transaction charges and inventory stepup amortization), the segment’s revenues declined 23 percent from the prior year first quarter. Negative comparisons for both periods were due mostly to lower sales of drill pipe both year-over-year and sequentially, although the segment posted lower sales for substantially all of its products during the first quarter of 2009 as compared to both the first quarter of 2008 and the fourth quarter of 2008. Lower drill pipe sales were the result of many contractors redeploying drill pipe from idle rigs to active rigs, in lieu of purchasing new drill pipe. Lower drilling activity negatively impacted revenue and pricing for this group in most major oilfield markets around the world, with North America, the North Sea, and China posting some of the steepest declines. Approximately 54 percent of first quarter 2009 sales for the segment were in North America.

Distribution Services segment revenues were $408 million during the first quarter of 2009, a decrease of 16 percent from the fourth quarter of 2008. Sequential decremental operating leverage was 24 percent on the revenue declines, higher than the segment has typically experienced due to pricing pressure accompanying the volume declines. Compared to the first quarter of 2008, revenues increased 11 percent, at 14 percent operating leverage, during the first quarter of 2009. Sales in the U.S. and Canada declined in both the sequential and year-over-year-comparisons, but these were partly offset by higher international sales in the first quarter of 2009. Sales of Mono artificial lift products, particularly into Latin America, helped improve margins for these products. Approximately 69 percent of the segment’s first quarter 2009 sales were in North America.

Outlook

The recent emergence of a serious banking crisis, a global recession, and lower commodity prices are presenting challenging prospects to our business. Consequently we are cautious in our outlook for the remainder of 2009, and believe we will see orders for new rigs fall in 2009 (although we are nevertheless optimistic that drilling contractors will place orders for new build floating rigs during the year for the Brazilian deepwater market). Drilling activity, particularly by independent gas producers reliant on external financing, has fallen sharply and we do not know when it will recover.

As a result of the much lower rig count our outlook for the Company’s Petroleum Services & Supplies segment and Distribution Services segment remains very guarded. We expect revenues for both groups to continue to decline in the second quarter. Decremental leverage for both groups is expected to be above our long term estimated levels (30 percent for Petroleum Services & Supplies; 10 percent for Distribution Services) due to rising pricing pressure we are experiencing, particularly in North America, which can be only partly offset by cost reduction measures we have taken. During the second quarter of 2009 we announced a voluntary retirement program and expect to report a $45 million to $60 million charge associated with enhanced retirement benefits we are offering to some of our long-tenured employees in the U.S. Our outlook for international markets, which are more driven by national oil company activity, are historically less volatile and expected to see better market conditions. The Rig Technology segment is expected to be less affected by the downturn due to the strength of its backlog.

The Company believes it is nevertheless well positioned to manage through this uncertain period, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders which are expected to continue to generate earnings well into the downturn. The Company has a long history of cost-control and downsizing in response to depressed market conditions, and of executing strategic acquisitions during difficult periods. The Company completed four acquisitions, ASEP, Anson, Spirit Fluids, and Spirit Minerals since March 31, 2009 for an aggregate cash amount of approximately $375 million, and continues to pursue others. Steel prices have begun to decline in many areas, and the Company is reducing outsourcing, overtime, and discretionary expenditures in view of the market. Such a period may present opportunities to the Company to effect new organic growth and acquisition initiatives, and we remain hopeful that a downturn will generate new opportunities.

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 quarter of 2009 and 2008, and the fourth quarter of 2008 include the following:


							%			%
							1Q09 v			1Q09 v
	1Q09*		1Q08*		4Q08*		1Q08			4Q08
Active Drilling Rigs:
U.S.		1,326		1,771		1,898		(25.1	%)		(30.1	%)
Canada		329		507		408		(35.1	%)		(19.4	%)
International		1,026		1,046		1,089		(1.9	%)		(5.8	%)

Worldwide		2,681		3,324		3,395		(19.3	%)		(21.0	%)

West Texas Intermediate Crude Prices (per barrel)	$	42.91	$	97.87	$	58.18		(56.2	%)		(26.2	%)

Natural Gas Prices ($/mmbtu)	$	4.57	$	8.64	$	6.40		(47.1	%)		(28.6	%)


*		Averages for the quarters indicated. See sources below.

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, 2009 on a quarterly basis:

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

The worldwide and U.S. quarterly average rig count decreased 19.3% (from 3,324 to 2,681) and 25.1% (from 1,771 to 1,326), respectively, in the first quarter of 2009 compared to the first quarter of 2008. The average per barrel price of West Texas Intermediate Crude decreased 56.2% (from $97.87 per barrel to $42.91 per barrel) and natural gas prices decreased 47.1% (from $8.64 per mmbtu to $4.57 per mmbtu) in the first quarter of 2009 compared to the first quarter of 2008.

U.S. rig activity at May 1, 2009 was 945 rigs compared to the first quarter average of 1,326 rigs. The price for West Texas Intermediate Crude was at $53.20 per barrel as of May 1, 2009, increasing 24% from the first quarter 2009 average. The global financial credit crisis that began in 2008 has created a worldwide economic slowdown.

Results of Operations

Operating results by segment are as follows (in millions):


	Three Months Ended
	March 31,
	2009			2008
Revenue:
Rig Technology	$	2,199		$	1,603
Petroleum Services & Supplies		1,014			830
Distribution Services		408			366
Elimination		(140	)		(114	)

Total Revenue	$	3,481		$	2,685


Operating Profit:
Rig Technology	$	606		$	406
Petroleum Services & Supplies		164			195
Distribution Services		25			19
Unallocated expenses and eliminations		(75	)		(51	)

Total Operating Profit	$	720		$	569


Operating Profit %:
Rig Technology		27.6	%		25.3	%
Petroleum Services & Supplies		16.2	%		23.5	%
Distribution Services		6.1	%		5.1	%
Total Operating Profit %		20.7	%		21.2	%

Rig Technology

Three Months Ended March 31, 2009 and 2008. Rig Technology revenue in the first quarter of 2009 was $2,199 million, an increase of $596 million (37%) compared to the same period in 2008. Backlog was $9.6 billion down 3% from the same period last year. Revenue out of backlog increased 49% offset by an 8% decrease in non-backlog revenue from the prior year period reflecting a decrease in capital spending by North American land drillers and pressure pumpers.

Operating profit from Rig Technology was $606 million for the first quarter ended March 31, 2009, an increase of $200 million (49%) over the same period of 2008. Operating profit percentage increased to 27.6%, up from 25.3% for the same prior year period primarily driven by ongoing work on drillships and construction contracts.

Petroleum Services & Supplies

Three Months Ended March 31, 2009 and 2008. Revenue from Petroleum Services & Supplies was $1,014 million for the first quarter of 2009 compared to $830 million for the first quarter of 2008, an increase of $184 million (22%). The increase was primarily attributable to incremental revenues from the acquisition of Grant Prideco.

Operating profit from Petroleum Services & Supplies was $164 million for the first quarter of 2009 compared to $195 million for the same period in 2008, a decrease of $31 million (16%), and operating profit percentage decreased to 16.2% down from 23.5% in the same period of 2008. Decremental operating profit is a result of the dramatic decline in drilling activity beginning in late third quarter 2008. North American rig count has decreased 54% since the end of September 2008, and 43% since the end of December 2008.

Distribution Services

Three Months Ended March 31, 2009 and 2008. Revenue from Distribution Services was $408 million, an increase of $42 million (12%) during the first quarter of 2009 over the comparable 2008 period.

Operating profit of $25 million in the first quarter of 2009 increased $6 million over the first quarter of 2008. Operating profit percentage increased to 6.1%, from 5.1% for the same prior year period. U.S. and Canada markets have experienced significant declines in the past six months due to the decrease in drilling activity, offset by international markets. International drilling activity has seen a slight decrease since the third quarter of 2008.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $75 million for the three months ended March 31, 2009, compared to $51 million for the same period in 2008. This increase is primarily due to greater intercompany profit elimination related to sales between the segments and higher legal expenses as a result of acquisition costs.

Interest and financial costs

Interest and financial costs remained relatively constant at $13 million for the three months ended March 31, 2009, compared to $10 million for the same period in 2008 due to the consistency in debt levels.

Other income (expense), net

Other income (expense), net was expense, net of $(36) million for the three months ended March 31, 2009 compared to income, net of $13 million for the same period in 2008. This is mainly due to foreign exchange charges of $26 million incurred in 2009 compared to a $15 million gain for the first quarter of 2008 related to hedging positions in Norway.

Provision for income taxes

The effective tax rate for the three month period ended March 31, 2009 was 32.5%, compared to 32.0% for the same period in 2008. The rate increase in 2009 was primarily due to an increase in the valuation allowance for losses that may not be deducted in future years.

The difference between the effective tax rate reflected in the provision for income taxes and the U.S. federal statutory rate of 35% was as follows (in millions):


	Three Months Ended
	March 31,
	2009			2008
Federal income tax at U.S. federal statutory rate of 35.0%	$	245		$	206
Foreign income tax rate differential		(32	)		(20	)
State income tax, net of federal benefit		6			6
Foreign dividends, net of foreign tax credits		1			2
Benefit of U.S. Manufacturing Deduction		(4	)		(2	)
Nondeductible expenses		8			3
Other		4			(7	)

Provision for income taxes	$	228		$	188

Liquidity and Capital Resources

At March 31, 2009, the Company had cash and cash equivalents of $2,232 million, and total debt of $873 million. At December 31, 2008, cash and cash equivalents were $1,543 million and total debt was $874 million. A portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. The Company’s outstanding debt at March 31, 2009 consisted of $200 million of 5.65% Senior Notes due 2012, $200 million of 7.25% Senior Notes due 2011, $150 million of 6.5% Senior Notes due 2011, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $22 million.

For the first three months of 2009, cash provided by operating activities was $785 million compared to cash provided by operating activities of $603 million in the same period of 2008. Cash was provided by operations primarily through net income of $473 million plus non-cash charges of $167 million, decreases in accounts receivable of $227 million, decreases in costs in excess of billings of $3 million, increases in accounts payable of $3 million, increases in income taxes of $124 million, increases in customer prepayments of $2 million and increases in other assets/liabilities, net of $56 million. The increase in billings in excess of costs and increases in other assets/liabilities were mainly due to increases in customer deposits and prepayments, and invoicing on rig construction projects. These positive cash flows were offset by equity income from our equity method affiliate of approximately $28 million, increases in inventory of $39 million, increases in prepaids and other current assets of $126 million, and increases in billings in excess of costs of $77 million

For the first three months of 2009, cash used in investing activities was $79 million compared to cash used of $183 million for the same period of 2008. The cash used in investing activities for the first three months of 2009 related to capital expenditures totaling approximately $79 million.

For the first three months of 2009, cash provided by financing activities was $1 million compared to cash used of $133 million for the same period of 2008. The cash provided by financing activities for the first three months of 2009 related to cash proceeds from exercised stock options in the amount of $1 million.

The effect of the change in exchange rates on cash flows was a negative $18 million and a positive $10 million for the three months ended March 31, 2009 and 2008, respectively.

The Company’s cash balance as of March 31, 2009 was $2,232 million. We believe that cash on hand, 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.

Recently Issued Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. In February 2008, the FASB issued FSP 157-2, which delayed the effective date of SFAS 157 for all nonfinancial assets and liabilities that are not recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company adopted the provisions of SFAS 157 for financial assets and liabilities as of January 1, 2008. At March 31, 2009, the Company has determined that its financial assets of $101 million and liabilities of $152 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At March 31, 2009, the fair value of the Company’s foreign currency forward contracts totaled $(60) million. There was no significant impact to the Company’s consolidated financial statements from the adoption of SFAS 157.

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 ended December 31, 2008, 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.

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 extensive operations in foreign 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 typically 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 a foreign exchange loss in our income statement of approximately $26 million in the first three months of 2009, compared to a $15 million foreign currency gain in the same period of the prior year. The gain/losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of the current economic environment. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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. Similarly some of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also gives rise to foreign currency exchange rate exposure. 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.

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods as of March 31, 2009 (in millions, except contract rates):


	As of March 31, 2009											December 31,
Functional Currency	2009			2010			2011		Total			2008
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		424			—			—		424			527
Average CAD to USD contract rate		1.2623			—			—		1.2623			1.1843
Fair Value at March 31, 2009 in U.S. dollars		(4	)		—			—		(4	)		14

Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		95			20			—		135			241
Average CAD to USD contract rate		1.0654			1.0638			—		1.0652			1.1196
Fair Value at March 31, 2009 in U.S. dollars		(13	)		(3	)		—		(16	)		(18	)

EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		5			—			—		5			11
Average USD to EUR contract rate		1.3690			—			—		1.3690			1.4397
Fair Value at March 31, 2009 in U.S. dollars		—			—			—		—			—

Sell USD/Buy EUR:
Notional amount to buy (in euros)		153			36			1		190			245
Average USD to EUR contract rate		1.3863			1.3420			1.4431		1.3780			1.3986
Fair Value at March 31, 2009 in U.S. dollars		(10	)		(1	)		—		(11	)		1

GBP Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		35			2			—		37			34
Average USD to GBP contract rate		1.4768			1.5313			—		1.4800			1.5647
Fair Value at March 31, 2009 in U.S. dollars		(2	)		—			—		(2	)		(4	)


	As of March 31, 2009												December 31,
Functional Currency	2009			2010			2011			Total			2008
USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		30			1			—			31			47
Average DKK to USD contract rate		5.7550			5.8029			5.7975			5.7569			5.4968
Fair Value at March 31, 2009 in U.S. dollars		1			—			—			1			2

Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		589			9			—			598			749
Average USD to EUR contract rate		1.3699			1.3138			—			1.3690			1.3791
Fair Value at March 31, 2009 in U.S. dollars		(21	)		—			—			(21	)		14

Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		87			—			—			87			108
Average USD to GBP contract rate		1.4438			1.4443			—			1.4438			1.5623
Fair Value at March 31, 2009 in U.S. dollars		(1	)		—			—			(1	)		(8	)

Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		845			407			79			1,331			1,325
Average NOK to USD contract rate		6.4574			6.4199			6.3632			6.4403			6.5338
Fair Value at March 31, 2009 in U.S. dollars		(36	)		(24	)		(6	)		(66	)		(101	)

Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		56			—			3			59			76
Average USD to EUR contract rate		1.3188			—			1.2715			1.3160			1.3777
Fair Value at March 31, 2009 in U.S. dollars		—			—			—			—			(2	)

Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		459			96			—			555			589
Average NOK to USD contract rate		6.0221			6.0282			—			6.0232			5.8647
Fair Value at March 31, 2009 in U.S. dollars		49			11			—			60			104

Other Currencies
Fair Value at March 31, 2009 in U.S. dollars		—			—			—			—			—


Total Fair Value		(37	)		(17	)		(6	)		(60	)		2

The Company had other financial market risk sensitive instruments denominated in foreign currencies totaling $91 million as of March 31, 2009 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 other financial market risk sensitive instruments could affect net income by $6 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 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, 2009 our long term borrowings consisted of $150 million in 6.5% Senior Notes, $200 million in 7.25% Senior Notes, $200 million in 5.65% Senior Notes, $150 million in 5.5% Senior Notes and $151 million in 6.125% 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.

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 Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files under the Exchange Act is accumulated and communicated to the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures and is recorded, processed, summarized and reported within the time period specified in the rules and forms of the Securities and Exchange Commission. Based upon that evaluation, the Company’s Chief Executive Officer and 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 at a reasonable assurance level.

There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 6. Exhibits

Reference is hereby made to the Exhibit Index commencing on Page 31.

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 6, 2009		By: /s/ Clay C. Williams
		Clay C. Williams
		Executive Vice President and Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer)

INDEX TO EXHIBITS

(a) Exhibits


2.1		Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 between National-Oilwell, Inc. and Varco International, Inc. (4).

2.2		Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (8).

3.1		Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1).

3.2		Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (9).

10.1		Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2).

10.2		Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2).

10.3		Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3).

10.4		National Oilwell Varco Long-Term Incentive Plan (5)*.

10.5		Form of Employee Stock Option Agreement (Exhibit 10.1) (6).

10.6		Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (6).

10.7		Form of Performance-Based Restricted Stock (18 Month) Agreement (Exhibit 10.1) (7).

10.8		Form of Performance-Based Restricted Stock (36 Month) Agreement (Exhibit 10.2) (7).

10.9		Five-Year Credit Agreement, dated as of April 21, 2008, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacities as Administrative Agent, Co-Lead Arranger and Joint Book Runner, DnB Nor Bank ASA, as Co-Lead Arranger and Joint Book Runner, and Fortis Capital Corp., The Bank of Nova Scotia and The Bank of Tokyo — Mitsubishi UFJ, Ltd., as Co-Documentation Agents. (Exhibit 10.1) (10).

10.10		First Amendment to Employment Agreement dated as of December 22, 2008 between Merrill A. Miller, Jr. and National Oilwell Varco (Exhibit 10.1) (11).

10.11		Second Amendment to Executive Agreement, dated as of December 22, 2008, of Clay Williams and National Oilwell Varco (Exhibit 10.2) (11).

10.12		First Amendment to Employment Agreement dated as of December 22, 2008 between Mark A. Reese and National Oilwell Varco (Exhibit 10.3) (11).

10.13		First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco (Exhibit 10.4) (11).

10.14		Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco (Exhibit 10.5) (11).


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.


*		Compensatory plan or arrangement for management or others

(1)		Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 11, 2000.

(2)		Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002.

(3)		Filed as an Exhibit to Varco International, Inc.’s Quarterly Report on Form 10-Q filed on May 6, 2004.

(4)		Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004.

(5)		Filed as Annex D to our Amendment No. 1 to Registration Statement on Form S-4 filed on January 31, 2005.

(6)		Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006.

(7)		Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007.

(8)		Filed as Annex A to our Registration Statement on Form S-4 filed on January 28, 2008.

(9)		Filed as an Exhibit to our Current Report on Form 8-K filed on February 21, 2008.

(10)		Filed as an Exhibit to our Current Report on Form 8-K filed on April 22, 2008.

(11)		Filed as an Exhibit to our Current Report on Form 8-K filed on December 23, 2008.

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith.

NOV Inc. - Quarter Report: 2009 March (Form 10-Q)

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