Edgar Filing: NATIONAL OILWELL VARCO INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q for quarterly period ended March 31, 2012

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2012

¨	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 of

incorporation or organization)

(I.R.S. Employer
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 x No ¨

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 x No ¨

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):

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

As of May 2, 2012 the registrant had 426,213,862 shares of common stock, par value $.01 per share, outstanding.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)


	March 31,		December 31,
	2012		2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	3,390	$	3,535
Receivables, net		3,330		3,291
Inventories, net		4,528		4,030
Costs in excess of billings		810		593
Deferred income taxes		352		336
Prepaid and other current assets		426		325

Total current assets		12,836		12,110

Property, plant and equipment, net		2,531		2,445
Deferred income taxes		204		267
Goodwill		6,206		6,151
Intangibles, net		4,004		4,073
Investment in unconsolidated affiliates		409		391
Other assets		97		78

Total assets	$	26,287	$	25,515

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,009	$	901
Accrued liabilities		2,172		2,376
Billings in excess of costs		965		865
Current portion of long-term debt and short-term borrowings		351		351
Accrued income taxes		649		709
Deferred income taxes		299		214

Total current liabilities		5,445		5,416

Long-term debt		159		159
Deferred income taxes		1,847		1,852
Other liabilities		316		360

Total liabilities		7,767		7,787

Commitments and contingencies

Stockholders’ equity:
Common stock - par value $.01; 426,184,373 and 423,900,601 shares issued and outstanding at March 31, 2012 and December 31, 2011		4		4
Additional paid-in capital		8,650		8,535
Accumulated other comprehensive income (loss)		104		(23	)
Retained earnings		9,658		9,103

Total Company stockholders' equity		18,416		17,619
Noncontrolling interests		104		109

Total stockholders’ equity		18,520		17,728

Total liabilities and stockholders’ equity	$	26,287	$	25,515

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,
	2012			2011
Revenue	$	4,303		$	3,146
Cost of revenue		3,036			2,171

Gross profit		1,267			975
Selling, general and administrative		390			366

Operating profit		877			609
Interest and financial costs		(8	)		(14	)
Interest income		3			4
Equity income in unconsolidated affiliates		17			13
Other income (expense), net		(16	)		(19	)

Income before income taxes		873			593
Provision for income taxes		269			189

Net income		604			404
Net loss attributable to noncontrolling interests		(2	)		(3	)

Net income attributable to Company	$	606		$	407

Net income attributable to Company per share:
Basic	$	1.43		$	0.97

Diluted	$	1.42		$	0.96

Cash dividends per share	$	0.12		$	0.11

Weighted average shares outstanding:
Basic		423			420

Diluted		426			423

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(In millions)


	Three Months Ended March 31,
	2012			2011
Net income	$	604		$	404
Currency translation adjustments		65			64
Changes in derivative financial instruments, net of tax		63			37

Comprehensive income		732			505
Comprehensive loss attributable to noncontrolling interest		(2	)		(3	)

Comprehensive income attributable to Company	$	734		$	508

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In millions)


	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income	$	604		$	404
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		148			135
Deferred income taxes		119			95
Equity income in unconsolidated affiliates		(17	)		(13	)
Other, net		—			12
Change in operating assets and liabilities, net of acquisitions:
Receivables		(40	)		(321	)
Inventories		(492	)		(200	)
Costs in excess of billings		(217	)		70
Prepaid and other current assets		(99	)		(51	)
Accounts payable		102			15
Billings in excess of costs		100			60
Other assets/liabilities, net		(272	)		(231	)

Net cash used in operating activities		(64	)		(25	)

Cash flows from investing activities:
Purchases of property, plant and equipment		(113	)		(79	)
Business acquisitions, net of cash acquired		(58	)		(51	)
Other		11			7

Net cash used in investing activities		(160	)		(123	)

Cash flows from financing activities:
Repayments on debt		(1	)		(170	)
Cash dividends paid		(51	)		(46	)
Proceeds from stock options exercised		88			58
Other		22			14

Net cash provided by (used in) financing activities		58			(144	)
Effect of exchange rates on cash		21			19

Decrease in cash and cash equivalents		(145	)		(273	)
Cash and cash equivalents, beginning of period		3,535			3,333

Cash and cash equivalents, end of period	$	3,390		$	3,060

Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	6		$	12
Income taxes	$	224		$	266

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 2011 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, 2012 are not necessarily indicative of the results to be expected for the full year.

Fair Value of Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, receivables, and payables approximated fair value because of the relatively short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase. The carrying values of other financial instruments approximate their respective fair values.

2. Inventories, net

Inventories consist of (in millions):


	March 31,		December 31,
	2012		2011
Raw materials and supplies	$	993	$	907
Work in process		993		852
Finished goods and purchased products		2,542		2,271

Total	$	4,528	$	4,030

3. Accrued Liabilities

Accrued liabilities consist of (in millions):


	March 31,		December 31,
	2012		2011
Customer prepayments and billings	$	632	$	686
Accrued vendor costs		439		280
Compensation		269		468
Warranty		209		211
Insurance		106		103
Taxes (non income)		81		119
Fair value of derivatives		32		83
Interest		9		7
Other		395		419

Total	$	2,172	$	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 Accounting Standards Codification (“ASC”) Topic 450 “Contingencies” (“ASC Topic 450”). 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 at December 31, 2011	$	211

Net provisions for warranties issued during the year		7
Amounts incurred		(10	)
Currency translation adjustments and other		1

Balance at March 31, 2012	$	209

4. Costs and Estimated Earnings on Uncompleted Contracts

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


	March 31,			December 31,
	2012			2011
Costs incurred on uncompleted contracts	$	5,868		$	5,839
Estimated earnings		3,630			3,775

		9,498			9,614
Less: Billings to date		9,653			9,886

	$	(155	)	$	(272	)

Costs and estimated earnings in excess of billings on uncompleted contracts	$	810		$	593
Billings in excess of costs and estimated earnings on uncompleted contracts		(965	)		(865	)

	$	(155	)	$	(272	)

5. Comprehensive Income

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, currency 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 ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three months ended March 31, 2012 and 2011, a majority of these local currencies strengthened against the U.S. dollar resulting in a net increase to Other Comprehensive Income of $65 million and $64 million, respectively, upon the translation from local currencies to the U.S. dollar.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of Other Comprehensive Income related to cumulative changes in the fair value of derivatives that have settled in the current or prior periods. The accumulated effect is an increase in Other Comprehensive Income of $63 million (net of tax of $25 million) and $37 million (net of tax of $14 million) for the three months ended March 31, 2012 and 2011, respectively.

6. Business Segments

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


	Three Months Ended March 31,
	2012			2011
Revenue:
Rig Technology	$	2,259		$	1,608
Petroleum Services & Supplies		1,704			1,265
Distribution & Transmission		564			410
Elimination		(224	)		(137	)

Total Revenue	$	4,303		$	3,146

Operating Profit:
Rig Technology	$	547		$	419
Petroleum Services & Supplies		388			231
Distribution & Transmission		43			27
Unallocated expenses and eliminations		(101	)		(68	)

Total Operating Profit	$	877		$	609

Operating Profit %:
Rig Technology		24.2	%		26.1	%
Petroleum Services & Supplies		22.8	%		18.3	%
Distribution & Transmission		7.6	%		6.6	%
Total Operating Profit %		20.4	%		19.4	%

The Company had revenues of 11% and 12% of total revenue from one of its customers for the three months ended March 31, 2012 and 2011, respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.

7. Debt

Debt consists of (in millions):


	March 31,		December 31,
	2012		2011
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		150		150

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

Other		9		9

Total debt		510		510
Less current portion		351		351

Long-term debt	$	159	$	159

Revolving Credit Facilities

The Company has a $2 billion, five-year revolving credit facility which expires April 21, 2013. At March 31, 2012 there were no borrowings against the credit facility, and there were $985 million in outstanding letters of credit issued under the credit facility, resulting in $1,015 million of funds available under this revolving credit facility. 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. The credit facility contains a financial covenant regarding maximum debt to capitalization and the Company was in compliance at March 31, 2012.

The Company also had $1,893 million of additional outstanding letters of credit at March 31, 2012, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds.

8. Tax

The effective tax rate for the three months ended March 31, 2012 was 30.8%, compared to 31.9% for the same period in 2011. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the period by the effect of foreign exchange loss for tax reporting in Norway.

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,
	2012			2011
Federal income tax at U.S. federal statutory rate	$	306		$	208
Foreign income tax rate differential		(23	)		(24	)
State income tax, net of federal benefit		8			6
Nondeductible expenses		13			10
Tax benefit of manufacturing deduction		(9	)		(6	)
Foreign dividends, net of foreign tax credits		6			5
Tax impact of foreign exchange		(30	)		—
Tax rate change on temporary differences		—			(13	)
Other		(2	)		3

Provision for income taxes	$	269		$	189

The balance of unrecognized tax benefits at March 31, 2012 was $131 million, of which $58 million would be recorded as a reduction of income tax expense if ultimately realized. The Company recognized no material changes in the balance of unrecognized tax benefits for the three months ended March 31, 2012.

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 tax years after 2007 and outside the U.S. for tax years ending after 2005.

The Company does not anticipate that its 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.

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.

9. 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 25.5 million. At March 31, 2012, 3,408,779 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. During the three months ended March 31, 2012, the Company concluded that the performance conditions relating to the performance-based restricted stock awards granted on February 20, 2009 were not met. As a result, the Company reversed $8 million in previously recognized stock-based compensation expense related to performance-based restricted stock awards that did not vest. Total stock-based compensation for all stock-based compensation arrangements under the Plan was $12 million and $17 million for the three months ended March 31, 2012 and 2011, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $3 million and $5 million for the three months ended March 31, 2012 and 2011, respectively.

During the three months ended March 31, 2012, the Company granted 2,239,088 stock options and 464,270 shares of restricted stock and restricted stock units, which includes 148,550 performance-based restricted stock awards. The stock options were granted February 21, 2012 with an exercise price of $84.58. The restricted stock and restricted stock units were granted February 21, 2012 and vest on the third anniversary of the date of grant. The performance-based restricted stock awards were granted February 21, 2012. 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 operating income growth, measured on a percentage basis, from January 1, 2012 through December 31, 2014 exceeding the median operating income growth for the designated peer group over the same period.

10. Derivative Financial Instruments

ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires companies to recognize all of its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The accounting for 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 revenues 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.

The Company records all derivative financial instruments at their fair value in its Consolidated Balance Sheet. Except for certain non-designated hedges discussed below, all derivative financial instruments that the Company holds 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 2 and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog. The Company may also use interest rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt issuances.

At March 31, 2012, the Company has determined that its derivative financial instruments representing assets of $78 million and liabilities of $33 million (primarily currency related derivatives) are level 2 (Inputs other than quoted prices in active markets for identical assets and liabilities that are observable either directly or indirectly for substantially the full term of the asset or liability) in the fair value hierarchy as the fair value is based on publicly available foreign exchange and interest rates at each financial reporting date. At March 31, 2012, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $45 million.

At March 31, 2012, the Company did not have any interest rate swaps and its financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

To protect against the volatility of forecasted foreign currency cash flows resulting from forecasted revenues 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 revenues and expenses 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.

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 ineffective portion), or hedge components excluded from the assessment of effectiveness, are recognized in the Consolidated Statements of Income during the current period.

The Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and expenses (in millions):


	Currency Denomination
Foreign Currency	March 31, 2012		December 31, 2011
Norwegian Krone	NOK	5,813	NOK	6,639
Euro	€	405	€	456
U.S. Dollar	$	381	$	402
Mexican Peso	MXN	306	MXN	—
Danish Krone	DKK	95	DKK	98
British Pound Sterling	£	17	£	2
Singapore Dollar	SGD	7	SGD	10

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 other income (expense), net 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.

The Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts (in millions):


	Currency Denomination
Foreign Currency	March 31, 2012		December 31, 2011
Norwegian Krone	NOK	4,293	NOK	2,310
Russian Ruble	RUB	984	RUB	786
U.S. Dollar	$	440	$	483
Euro	€	213	€	161
Singapore Dollar	SGD	135	SGD	5
Danish Krone	DKK	121	DKK	67
British Pound Sterling	£	12	£	9
Swedish Krone	SEK	8	SEK	4

The Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions):


	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet	March 31,		December 31,		Balance Sheet	March 31,		December 31,
	Location	2012		2011		Location	2012		2011
Derivatives designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	40	$	16	Accrued liabilities	$	19	$	62
Foreign exchange contracts	Other Assets		11		1	Other Liabilities		1		13

Total derivatives designated as hedging instruments under ASC Topic 815		$	51	$	17		$	20	$	75

Derivatives not designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	27	$	9	Accrued liabilities	$	13	$	21

Total derivatives not designated as hedging instruments under ASC Topic 815		$	27	$	9		$	13	$	21

Total derivatives		$	78	$	26		$	33	$	96

The Effect of Derivative Instruments on the Consolidated Statements of Income

($ in millions)


Derivatives in ASC Topic 815 Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion) (a)				Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)					Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (b)
	Three Months Ended March 31,					Three Months Ended March 31,						Three Months Ended March 31,
	2012		2011			2012			2011			2012			2011
					Revenue		(4	)		1
Foreign exchange contracts		78		55	Cost of revenue		(6	)		4	Other income (expense), net		(1	)		(3	)

Total		78		55			(10	)		5			(1	)		(3	)


Derivatives Not Designated as Hedging Instruments under ASC Topic 815	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		Three Months Ended March 31,
		2012		2011
Foreign exchange contracts	Other income (expense), net		16		(11	)

Total			16		(11	)

(a)	The Company expects that $(6) 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 transactions resulting in no impact to earnings or cash flow.

(b)

The amount of gain recognized in income represents $(1) million and $(3) million related to the ineffective portion of the hedging relationships for the three months ended March 31, 2012 and 2011, respectively, and $(1) million and $(4) million related to the amount excluded from the assessment of the hedge effectiveness for the three months ended March 31, 2012 and 2011, respectively.

11. 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,
	2012		2011
Numerator:
Net income attributable to Company	$	606	$	407

Denominator:
Basic—weighted average common shares outstanding		423		420
Dilutive effect of employee stock options and other unvested stock awards		3		3

Diluted outstanding shares		426		423

Net income attributable to Company per share:
Basic	$	1.43	$	0.97

Diluted	$	1.42	$	0.96

Cash dividends per share	$	0.12	$	0.11

ASC Topic 260, “Earnings Per Share” (“ASC Topic 260”) requires companies with unvested participating securities to utilize a two-class method for the computation of Net income attributable to Company per share. The two-class method requires a portion of Net income attributable to Company to be allocated to participating securities, which are unvested awards of share-based payments with non-forfeitable rights to receive dividends or dividend equivalents, if declared. Net income attributable to Company allocated to these participating securities was immaterial for three months ended March 31, 2012 and 2011 and therefore not excluded from Net income attributable to Company per share calculation.

In addition, the Company had stock options outstanding that were anti-dilutive totaling 6 million and 3 million shares for the three months ended March 31, 2012 and 2011, respectively.

12. Cash Dividends

On February 23, 2012 the Company’s Board of Directors approved a cash dividend of $0.12 per share. The cash dividend was paid on March 30, 2012 to each stockholder of record on March 16, 2012. Cash dividends aggregated $51 million and $46 million for the three months ended March 31, 2012 and 2011, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.

13. Subsequent Events

On April 4, 2012, the Company completed its previously announced acquisition of NKT Flexibles I/S (“NKT”) for approximately $0.7 billion in cash. Prior to acquisition, NKT was a joint venture between NKT Holding and Subsea 7 S.A. and is based in Denmark. The company designs and manufactures flexible pipe products and systems for the offshore oil and gas industry, including products associated with Floating Production, Storage and Offloading vessels and other offshore vessels, as well as subsea production systems including flowlines and flexible risers. The Company will report the NKT results within its Rig Technology segment.

On April 10, 2012, the Company entered into an agreement with Schlumberger Limited to purchase its Wilson distribution business segment for approximately $0.8 billion in cash. Wilson is a leading distributor of pipe, valves and fittings as well as mill, tool and safety products and services to the international energy business and to other industrial customers. This transaction is subject to customary closing conditions, including approval from the relevant competition authorities. Upon closing, the Company expects to report the Wilson results within its Distribution & Transmission segment.

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.

Unless indicated otherwise, results of operations data are presented in accordance with accounting principles generally accepted in the United States (“GAAP”). In an effort to provide investors with additional information regarding our results of operations, certain non-GAAP financial measures, including operating profit excluding other costs, operating profit percentage excluding other costs and diluted earnings per share excluding other costs, are provided. See Non-GAAP Financial Measures and Reconciliations in Results of Operations for an explanation of our use of non-GAAP financial measures and reconciliations to their corresponding measures calculated in accordance with GAAP.

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; wireline trucks; cranes; and turret mooring systems and other products for floating production, storage and offloading vessels (“FPSOs”) and other offshore vessels and terminals. 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, Brazil, China, Belarus, India, Turkey, the Netherlands, Singapore, and South Korea.

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 drill pipe, tubing, casing, 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, drilling fluids, 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 fiberglass 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 additional operations in the United States, Canada, the United Kingdom, Brazil, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, Oman, and the United Arab Emirates.

Distribution & Transmission

Our Distribution & Transmission 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 operations for all the major oil and gas producing regions throughout the world. The segment employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe. The segment also has a global reach in oil and gas, waste water treatment, chemical, food and beverage, paper and pulp, mining, agriculture, and a variety of municipal markets and is a leading producer of water transmission pipe and fabricated steel products, such as wind towers, and specialized materials and products used in infrastructure projects. Demand for the segment’s services is determined primarily by the level of drilling, servicing, and oil and gas production activities and is also influenced by the domestic economy in general, housing starts and government policies. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including additional operations in the United States, Canada, the United Kingdom, Kazakhstan, Singapore, Russia, and Malaysia.

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2011, 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; service and product warranties 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.

EXECUTIVE SUMMARY

For its first quarter ended March 31, 2012, the Company generated $606 million in net income attributable to Company, or $1.42 per fully diluted share, on $4.3 billion in revenue. Compared to the fourth quarter of 2011 revenue increased $44 million or one percent and net income attributable to the Company increased six percent. Compared to the first quarter of 2011, revenue increased 37 percent and net income attributable to Company increased 49 percent.

The first quarter of 2012 included pre-tax transaction charges of $7 million, the fourth quarter of 2011 included pre-tax transaction charges of $12 million, and the first quarter of 2011 included pre-tax transaction and devaluation charges of $19 million. Excluding transaction and devaluation charges from all periods, first quarter 2012 earnings were $1.44 per fully diluted share, compared to $1.37 per fully diluted share in the fourth quarter of 2011 and $1.00 per fully diluted share in the first quarter of 2011.

Operating profit excluding transaction charges was $881 million or 20.5 percent of sales in the first quarter of 2012, compared to $860 million or 20.2 percent of sales in the fourth quarter of 2011 excluding transaction charges. Operating profit excluding transaction and devaluation charges was $628 million or 20.0 percent of sales for the first quarter of 2011.

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 responded vigorously through 2009, but a credit-driven worldwide economic recession developed nonetheless. Developed economies struggled to recover throughout 2010 and 2011, facing additional economic weakness related to potential sovereign debt defaults in Europe. As a result, commodity prices, including oil and gas prices, have been volatile. After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to average $43 per barrel (West Texas Intermediate Crude Prices) during the first quarter of 2009, but slowly recovered into the $100 per barrel range by the end of 2010 where they held relatively steady since (the first quarter of 2012 averaged $103 per barrel). After averaging $6 to $9 per mmbtu 2004-2008, North American gas prices declined to average $3.17 per mmbtu in the third quarter of 2009. Gas prices recovered modestly, trading up above $5 per mmbtu six months later, but then slowly settled into the $3 to $4 per mmbtu through 2011, before turning down sharply in early 2012 (first quarter 2012 averaged $2.45 per mmbtu). The recent gas price collapse appears to be a direct result of rising gas supply out of unconventional shale reservoir development across North America.

The steadily rising oil and gas prices seen between 2003 and 2008 led to high levels of exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit availability. Strengthening oil prices since then have led to steadily rising oil-drilling activity over the past two years.

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 decreased to a low of 876 in June, 2009. U.S. rig count increased steadily to 2,026 by late 2011, but began to decline with lower gas prices to average 1,991 rigs during the first quarter of 2012 (and had fallen to 1,945 by late April 2012). Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity in 2009, but drilling recovered across North America as gas prices improved. Recently low gas prices have caused operators to trim drilling, driving the U.S. gas rig count down 30 percent to 613 in the past year. However, with high and stabilizing oil prices many redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. Oil drilling has risen to 68 percent of the total domestic drilling effort, and, at 1,328 rigs drilling, is at the highest levels in the U.S. since the early 1980’s.

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, but the international rig count exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 947 in August 2009. Recently international drilling rebounded due to high oil prices, climbing back to 1,192 in March 2012.

During 2009 the Company saw its Petroleum Services & Supplies and its Distribution & Transmission margins affected most acutely by a drilling downturn, through both volume and price declines. Resumption of drilling activity since enabled both of these segments to gain volume, stabilize and lift pricing, and improve margins since the third quarter of 2009. The Company’s Rig Technology segment was less impacted by the 2009 downturn owing to its high level of contracted backlog which it executed on very well. It posted higher revenues in 2009 than 2008 as a result. Its revenues declined in 2010 as its backlog declined, but increased 12 percent in 2011 as orders for new offshore rigs began to increase.

The economic decline beginning in late 2008 followed an extended period of high drilling activity which fueled strong demand for oilfield services between 2003 and 2008. Incremental drilling activity through the upswing shifted toward harsh environments, employing increasingly sophisticated technology to find and produce reserves. Higher utilization of drilling rigs 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 was 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 1.) retool the existing fleet of jackup rigs (according to Offshore Data Services, 70 percent of the existing 476 jackup rigs are more than 25 years old); 2.) replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and 3.) build out additional deepwater 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.

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 declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $4.9 billion by June 30, 2010. The backlog increased steadily since as drillers began ordering more than the Company shipped out of backlog, and finished the first quarter of 2012 at $10.4 billion. Approximately $5.2 billion of these orders are scheduled to flow out as revenue during the remainder of 2012; $2.9 billion are scheduled to flow out as revenue during 2013; and the balance thereafter. The land rig backlog comprised 16 percent and equipment destined for offshore operations comprised 84 percent of the total backlog as of March 31, 2012. Equipment destined for international markets totaled 86 percent of the backlog.

Segment Performance

The Rig Technology segment generated $2.3 billion in revenues and $547 million in operating profit or 24.2 percent of sales during the first quarter of 2012. Compared to the prior quarter, revenues declined $57 million and operating profit declined $50 million. Margins declined sequentially due to a long term adverse mix shift in the segment, but are expected to stabilize in the mid-twenty percent range. The mix shift arises from offshore projects contracted at high prices in 2007 and 2008, which were subsequently manufactured in low cost environments in 2009 and 2010, resulting in high margins for the group which peaked in the first quarter of 2010. As these projects have been completed and replaced with lower priced projects, margins have gradually declined. Compared to the first quarter of 2011, segment revenues grew 40 percent, and operating leverage or flow-through (the change in operating profit divided by the change in revenue) was 20 percent. Revenue out of backlog declined four percent sequentially but increased 52 percent year-over-year. Non-backlog revenue, which is predominantly aftermarket spares and services, increased one percent sequentially and increased 13 percent from the first quarter of 2011. Orders for four deepwater floating rigs, one jackup drilling package, one floating well intervention vessel package, and several individual subsea blowout preventer stacks contributed to total order additions to backlog of $1,911 million during the first quarter, yielding backlog growth of $199 million through the first quarter. Interest in offshore rig construction has remained strong as announced dayrates for deepwater offshore rigs appear to be increasing, rig building costs have stabilized at attractive levels, and financing appears to be available for most established drillers. The Company booked an order for seven drillships for Brazil in the third quarter of 2011, and continues to tender additional new offshore rig projects for Petrobras to shipyards and drilling contractors, which are to be built in Brazil. However, further potential bookings of any additional offshore rigs for Brazil may continue to be subject to delays.

The Petroleum Services & Supplies segment generated $1.7 billion in revenue and $388 million in operating profit, or 22.8 percent of sales, for the first quarter of 2012. Compared to the fourth quarter of 2011, revenue increased 9 percent, and operating leverage or flow-through was 65 percent. Year-over-year operating leverage or flow-through was 32 percent on the segment’s 35 percent sales growth. The group completed its acquisition of Ameron on October 5, 2011 and its composite pipe segment is being integrated into the group’s fiberglass and composite pipe products. Sequential margin improvements were due in part to specific integration activities of this business to improve efficiency, along with margin improvements in the segment’s downhole tools, Mission pumps and drill pipe products. Russia and Brazil posted good sequential revenue improvements, partly offset by lower sales in the U.A.E., and Europe, due to inclement weather. Revenues in the U.S. and Canada improved sequentially due in part to rising activity in liquids-rich shale plays like the Bakken and the Eagle Ford. Drill pipe margins improved due to sourcing more low-cost green tubes from the Company’s joint venture supplier, as compared to the fourth quarter. Approximately 63 percent of the segment’s first quarter sales were into North American markets, and 37 percent of sales were into international markets.

The Distribution & Transmission segment generated $564 million in revenue and $43 million in operating profit or 7.6 percent of sales during the first quarter of 2012. Revenues grew $4 million from the fourth quarter of 2011, but operating profit declined $2 million. Compared to the first quarter of 2011, revenues increased 38 percent and flow-through or operating leverage was 10 percent, due in part to the addition of Ameron’s Water Transmission and Infrastructure Products segments from October 5, 2011 onward. The

distribution portion of the segment benefited from high drilling and completion activity in shale plays across North America, leading to sequential gains, while sales of water transmission products and wind towers declined. Approximately 72 percent of the group’s first quarter sales were into North American markets and 28 percent into international markets.

Outlook

Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher drilling activity in North America and slowly improving international drilling activity. Order levels for new drilling rigs has rebounded sharply, and the Rig Technology segment continues to experience a high level of interest in new capital equipment. Rig dayrates appear to be improving for certain classes of newer technology rigs, and appear to be trending higher for deepwater offshore rigs. While lower pricing in our backlog led to modest declines in Rig Technology margins in the first quarter of 2012, recently won offshore rig construction orders at modestly higher margins are expected to lead to slightly higher margin levels in the second half of the year. Additionally, sales of pressure pumping equipment by the group may experience declines later in the year, as some customers have been discussing curtailing their capital equipment expenditures in view of lower gas prices.

Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution & Transmission segment remains closely tied to the rig count, particularly in North America. The oil rig count growth seen over the past few quarters is now only partly offsetting gas rig declines, leading to slightly declining rig count levels overall. As a result, pricing and volumes may come under pressure later in the year. Strong oil prices are expected to underpin high demand and strong results for the segments through the remainder of 2012.

The Company believes it is well positioned, 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 during 2012. 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. 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.

Still the recovery of the world economy continues to move forward with a great deal of uncertainty as the world watches the sovereign debt crises in several European countries unfold, market turbulence and general global economic worries. If such global economic uncertainties develop adversely, world oil and gas prices could be impacted, which in turn could negatively impact the worldwide rig count and the Company’s future financial results.

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, and worldwide oil and gas inventory levels. Key industry indicators for the first quarter of 2012 and 2011, and the fourth quarter of 2011 include the following:


							%			%
							1Q12 v			1Q12 v
	1Q12*		1Q11*		4Q11*		1Q11			4Q11
Active Drilling Rigs:
U.S.		1,991		1,717		2,010		16.0	%		(0.9	%)
Canada		592		587		475		0.9	%		24.6	%
International		1,189		1,166		1,188		2.0	%		0.1	%

Worldwide		3,772		3,470		3,673		8.7	%		2.7	%

West Texas Intermediate Crude Prices (per barrel)	$	102.88	$	93.54	$	93.99		10.0	%		9.5	%

Natural Gas Prices ($/mmbtu)	$	2.45	$	4.18	$	3.32		(41.4	%)		(26.2	%)

*	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, 2012 on a quarterly basis:

LOGO

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 quarterly average rig count increased 3% (from 3,673 to 3,772) and while the U.S. decreased 1% (from 2,010 to 1,991), in the first quarter of 2012 compared to the fourth quarter of 2011. The average per barrel price of West Texas Intermediate Crude increased 10% (from $93.99 per barrel to $102.88 per barrel) and natural gas prices decreased 26% (from $3.32 per mmbtu to $2.45 per mmbtu) in the first quarter of 2012 compared to the fourth quarter of 2011.

U.S. rig activity at April 27, 2012 was 1,945 rigs compared to the first quarter average of 1,991 rigs, decreasing 2%. The price for West Texas Intermediate Crude was at $104.93 per barrel at April 27, 2012, increasing 2% from the first quarter average of 2012. The price for natural gas was at $2.19 per mmbtu at April 27, 2012, decreasing 11% from the first quarter average of 2012.

Results of Operations

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


	Three Months Ended March 31,
	2012			2011
Revenue:
Rig Technology	$	2,259		$	1,608
Petroleum Services & Supplies		1,704			1,265
Distribution & Transmission		564			410
Elimination		(224	)		(137	)

Total Revenue	$	4,303		$	3,146

Operating Profit:
Rig Technology	$	547		$	419
Petroleum Services & Supplies		388			231
Distribution & Transmission		43			27
Unallocated expenses and eliminations		(101	)		(68	)

Total Operating Profit	$	877		$	609

Operating Profit %:
Rig Technology		24.2	%		26.1	%
Petroleum Services & Supplies		22.8	%		18.3	%
Distribution & Transmission		7.6	%		6.6	%
Total Operating Profit %		20.4	%		19.4	%

Rig Technology

Three Months Ended March 31, 2012 and 2011. Revenue from Rig Technology was $2,259 million for the first quarter of 2012 compared to $1,608 million for the first quarter of 2011, an increase of $651 million (40.5%). Deepwater offshore drilling worldwide and active shale plays in the U.S. continue to be the driving force for the increase in revenue for this segment resulting in both increased rig construction as well as demand for aftermarket spare parts and services.

Operating profit from Rig Technology was $547 million in the first quarter of 2012 compared to $419 million for the first quarter of 2011, an increase of $128 million (30.5%). Operating profit percentage decreased to 24.2%, from 26.1% in 2011 primarily due to decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. This decrease in margins was partially offset by the increase in demand for aftermarket spare parts and services.

The Rig Technology segment monitors its capital equipment backlog to plan its business. New orders are added to backlog only when the Company receives a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $10.4 billion at March 31, 2012, an increase of $4.2 billion (67.7%) from backlog of $6.2 billion at March 31, 2011.

Petroleum Services & Supplies

Three Months Ended March 31, 2012 and 2011. Revenue from Petroleum Services & Supplies was $1,704 million for the first quarter of 2012 compared to $1,265 million for the first quarter of 2011, an increase of $439 million (34.7%). The increase was primarily attributable to shale plays leading to a strong North American market with a 16% increase in U.S. rig activity compared to the first quarter of 2011. North American shale plays continue to be a driving force in the increase in revenues across most business units within this segment. In addition, full quarter results of strategic acquisitions made during 2011 in the U.S., the U.K., the Netherlands, Singapore, Malaysia and Brazil contributed to the increase in revenue for this segment.

Operating profit from Petroleum Services & Supplies was $388 million for the first quarter of 2012 compared to $231 million for the first quarter of 2011, an increase of $157 million (68.0%). Operating profit percentage increased to 22.8% up from 18.3% in first quarter of 2011. This increase is primarily due to increased volume, continued favorable pricing and cost reductions within most business units within the segment.

Distribution & Transmission

Three Months Ended March 31, 2012 and 2011. Revenue from Distribution & Transmission totaled $564 million for the first quarter of 2012 compared to $410 million for the first quarter of 2011, an increase of $154 million (37.6%). This increase was primarily attributable to increased rig count activity in the U.S. In addition, full quarter results of strategic acquisitions made during 2011 in the U.S. and the U.K. contributed to the increase in revenue for this segment.

Operating profit from Distribution & Transmission was $43 million in the first quarter of 2012 compared to $27 million in the first quarter of 2011, an increase of $16 million (59.3%). Operating profit percentage increased to 7.6% in the first quarter of 2012 from 6.6% in the first quarter of 2011 primarily due to increased volume, greater cost efficiencies and continued favorable pricing related to strong demand.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $101 million and $68 million for the three months ended March 31, 2012 and 2011, respectively. This increase is primarily due to higher intersegment eliminations as a result of increased market activity.

Interest and financial costs

Interest and financial costs were $8 million and $14 million for the three months ended March 31, 2012 and 2011, respectively. The decrease in interest and financial costs was due to an overall decrease in debt levels for the three months ended March 31, 2012 compared to the same period in 2011.

Provision for income taxes

Non-GAAP Financial Measures and Reconciliations

In an effort to provide investors with additional information regarding our results as determined by GAAP, we disclose various non-GAAP financial measures in our quarterly earnings press releases and other public disclosures. The primary non-GAAP financial measures we focus on are: (i) operating profit excluding other costs, (ii) operating profit percentage excluding other costs, and (iii) diluted earnings per share excluding other costs. Each of these financial measures excludes the impact of certain other costs and therefore has not been calculated in accordance with GAAP. A reconciliation of each of these non-GAAP financial measures to its most comparable GAAP financial measure is included below.

We use these non-GAAP financial measures because we believe it provides useful supplemental information regarding the Company’s on-going economic performance and, therefore, use these non-GAAP financial measures internally to evaluate and manage the Company’s operations. We have chosen to provide this information to investors to enable them to perform more meaningful comparisons of operating results and as a means to emphasize the results of on-going operations.

The following tables set forth the reconciliations of these non-GAAP financial measures to their most comparable GAAP financial measures (in millions, except per share data):


	Three Months Ended
	March 31,						December 31,
	2012			2011			2011
Reconciliation of operating profit:
GAAP operating profit	$	877		$	609		$	848
Other costs:
Transaction costs		4			2			12
Libya asset write-down		—			17			—

Operating profit excluding other costs	$	881		$	628		$	860


	Three Months Ended
	March 31,						December 31,
	2012			2011			2011
Reconciliation of operating profit %:
GAAP operating profit %		20.4	%		19.4	%		19.9	%
Other costs %		0.1	%		0.6	%		0.3	%

Operating profit % excluding other costs		20.5	%		20.0	%		20.2	%


	Three Months Ended
	March 31,						December 31,
	2012			2011			2011
Reconciliation of diluted earnings per share:
GAAP earnings per share	$	1.42		$	0.96		$	1.35
Other costs		0.02			0.04			0.02

Earnings per share excluding other costs	$	1.44		$	1.00		$	1.37

Liquidity and Capital Resources

Overview

The Company assesses liquidity in terms of its ability to generate cash to fund operating, investing and financing activities. The Company continues to generate substantial cash from its operating activities and remains in a strong financial position, with resources available to reinvest in existing businesses, strategic acquisitions and capital expenditures to meet short- and long-term objectives. The Company believes that cash on hand, cash generated from expected results of operations and amounts available under its revolving credit facility will be sufficient to fund operations, anticipated working capital needs and other cash requirements such as capital expenditures, debt and interest payments and dividend payments for the foreseeable future.

At March 31, 2012, the Company had cash and cash equivalents of $3,390 million, and total debt of $510 million. At December 31, 2011, cash and cash equivalents were $3,535 million and total debt was $510 million. A significant 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. Of the $3,390 million of cash and cash equivalents at March 31, 2012, approximately $3,110 million is held outside the U.S. If opportunities to invest in the U.S. are greater than available cash balances, rather than repatriating this cash, the Company may choose to borrow against its revolving credit facility.

The Company’s outstanding debt at March 31, 2012 consisted of $200 million of 5.65% Senior Notes due 2012, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $9 million. The Company has a $2 billion, five-year revolving credit facility which expires April 21, 2013. At March 31, 2012 there were no borrowings against the credit facility, and there were $985 million in outstanding letters of credit issued under the credit facility, resulting in $1,015 million of funds available under this revolving credit facility. 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. The credit facility contains a financial covenant regarding maximum debt to capitalization and the Company was in compliance at March 31, 2012.

The following table summarizes our net cash used in operating activities, net cash used in investing activities and net cash provided by (used in) financing activities for the periods presented (in millions):


	Three Months Ended March 31,
	2012			2011
Net cash used in operating activities	$	(64	)	$	(25	)
Net cash used in investing activities		(160	)		(123	)
Net cash provided by (used in) financing activities		58			(144	)

Operating Activities

For the first three months of 2012, cash used in operating activities was $64 million, an increase of $39 million compared to cash used in operating activities of $25 million in the same period of 2011. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $604 million plus non-cash charges of $267 million less $17 million in equity income from the Company’s unconsolidated affiliates.

Net changes in operating assets and liabilities, net of acquisitions, used $918 million for the first three months of 2012 compared to $658 million used in the same period in 2011. Due to an increase in market activity during the first three months of 2012 compared to the same period in 2011, revenue and backlog increased which is reflected in increased accounts receivable coupled with a buildup in inventory. Increased market activity during the first three months of 2012 also resulted in higher accounts payable and an increase in both costs in excess of billings and billings in excess of costs with costs incurred on major rig projects outpacing milestone invoicing.

Investing Activities

For the first three months of 2012, net cash used in investing activities was $160 million compared to net cash used in investing activities of $123 million for the same period of 2011. Net cash used in investing activities continued to primarily be the result of capital expenditures and acquisition activity both of which increased in the first three months of 2012 compared to the first three months of 2011. Due to the continued growth in the Company worldwide both internally and through acquisition, the Company used $113 million during the first three months of 2012 for capital expenditure compared to $79 million for the same period of 2011. In addition, the Company used $58 million for the purpose of strategic acquisitions during the first three months of 2012 compared to $51 million for the same period of 2011. During the first three months of 2012, the Company used its cash on hand to fund its acquisitions and capital expenditures.

Financing Activities

For the first three months of 2012, net cash provided by financing activities was $58 million compared to cash used in financing activities of $144 million for the same period of 2011. The $202 million change primarily related to the lower repayments on debt during the first three months of 2012 compared to the same period of 2011 as well as increased proceeds from stock options exercised. Repayments on debt during the first three months of 2012 were $1 million compared to $170 million for the same period of 2011. Proceeds from stock options exercised were $88 million during the first three months of 2012 compared to $58 million for the same period of 2011. The Company also increased its dividend slightly to $51 million during the first three months of 2012 compared to $46 million for the same period of 2011.

The effect of the change in exchange rates on cash flows was a positive $21 million and $19 million for the three months ended March 31, 2012 and 2011, respectively.

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, dividends and financing obligations.

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.

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, 2011, 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 impact income. We recorded a foreign exchange loss in our income statement of approximately $5 million in the first three months of 2012, compared to a $14 million foreign exchange loss in the same period of the prior year. The gains and 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 changes in foreign currency exchange rates. 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 give 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 at March 31, 2012 (in millions, except contract rates):


	As of March 31, 2012										December 31, 2011
Functional Currency	2012			2013		2014		Total			December 31, 2011
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		284			—		—		284			274
Average USD to CAD contract rate		0.9967			—		—		0.9967			1.0315
Fair Value at March 31, 2012 in U.S. dollars		1			—		—		1			(3	)
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		126			82		—		208			157
Average USD to CAD contract rate		1.0071			1.0395		—		1.0196			1.0095
Fair Value at March 31, 2012 in U.S. dollars		1			3		—		4			(2	)
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		4			—		—		4			10
Average USD to EUR contract rate		1.3748			—		—		1.3748			1.4035
Fair Value at March 31, 2012 in U.S. dollars		—			—		—		—			1
Sell USD/Buy EUR:
Notional amount to buy (in euros)		80			20		—		100			105
Average USD to EUR contract rate		1.3916			1.3365		—		1.3806			1.3888
Fair Value at March 31, 2012 in U.S. dollars		(5	)		—		—		(5	)		(10	)
KRW Buy USD/Sell KRW:
Notional amount to buy (in South Korean won)		123			261		—		384			124
Average USD to KRW contract rate		923.7000			918.8186		—		920.3811			923.7000
Fair Value at March 31, 2012 in U.S. dollars		—			—		—		—			—
Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)		2,130			639		58		2,827			53,128
Average USD to KRW contract rate		1,132.7969			1,020.2488		940.5000		1,100.7441			1,153.6186
Fair Value at March 31, 2012 in U.S. dollars		—			—		—		—			—
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		44			—		—		44			45
Average USD to GBP contract rate		1.5853			—		—		1.5853			1.5499
Fair Value at March 31, 2012 in U.S. dollars		(1	)		—		—		(1	)		—


	As of March 31, 2012											December 31, 2011
Functional Currency	2012			2013			2014		Total			December 31, 2011
GBP Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		54			9			—		63			42
Average USD to GBP contract rate		1.5581			1.5514			—		1.5572			1.5821
Fair Value at March 31, 2012 in U.S. dollars		2			—			—		2			(2	)
USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		28			3			—		31			27
Average DKK to USD contract rate		5.4338			5.5893			—		5.4484			5.4213
Fair Value at March 31, 2012 in U.S. dollars		(1	)		—			—		(1	)		(1	)
Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		580			116			—		696			636
Average EUR to USD contract rate		1.3569			1.3486			—		1.3555			1.3796
Fair Value at March 31, 2012 in U.S. dollars		(9	)		(1	)		—		(10	)		(37	)
Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		39			—			—		39			15
Average GBP to USD contract rate		1.5840			—			—		1.5840			1.5737
Fair Value at March 31, 2012 in U.S. dollars		—			—			—		—			—
Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		1,059			394			25		1,478			964
Average NOK to USD contract rate		5.9665			5.9531			6.1256		5.9657			5.9359
Fair Value at March 31, 2012 in U.S. dollars		44			9			1		54			(14	)
Buy MXN/Sell USD:
Notional amount to buy (in U.S. dollars)		22			—			—		22			—
Average MXN to USD contract rate		13.8051			—			—		13.8051			—
Fair Value at March 31, 2012 in U.S. dollars		1			—			—		1			—
Buy SGD/Sell USD:
Notional amount to buy (in U.S. dollars)		101			—			—		101			10
Average SGD to USD contract rate		1.2631			—			—		1.2631			1.3022
Fair Value at March 31, 2012 in U.S. dollars		1			—			—		1			—
Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		8			—			—		8			3
Average DKK to USD contract rate		5.6194			—			—		5.6194			5.5036
Fair Value at March 31, 2012 in U.S. dollars		—			—			—		—			—
Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		191			2			—		193			135
Average EUR to USD contract rate		1.3326			1.4019			—		1.3333			1.3509
Fair Value at March 31, 2012 in U.S. dollars		—			—			—		—			5
Sell GBP/Buy USD:
Notional amount to sell (in U.S. dollars)		—			—			—		—			1
Average GBP to USD contract rate		—			—			—		—			1.5622
Fair Value at March 31, 2012 in U.S. dollars		—			—			—		—			—
Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		222			1			—		223			172
Average NOK to USD contract rate		5.7732			5.9030			—		5.7743			5.8168
Fair Value at March 31, 2012 in U.S. dollars		(2	)		—			—		(2	)		6
Sell SGD/Buy USD:
Notional amount to sell (in U.S. dollars)		12			—			—		12			2
Average SGD to USD contract rate		0.7869			—			—		0.7869			0.7674
Fair Value at March 31, 2012 in U.S. dollars		—			—			—		—			—
Sell RUB/Buy USD:
Notional amount to sell (in U.S. dollars)		33			—			—		33			24
Average RUB to USD contract rate		29.8112			—			—		29.8112			32.7613
Fair Value at March 31, 2012 in U.S. dollars		—			—			—		—			—
DKK Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		95			—			—		95			96
Average DKK to USD contract rate		5.6135			—			—		5.6135			5.67
Fair Value at March 31, 2012 in U.S. dollars		—			—			—		—			—
Other Currencies
Fair Value at March 31, 2012 in U.S. dollars		1			—			—		1			(1	)

Total Fair Value at March 31, 2012 in U.S. dollars		33			11			1		45			(58	)

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $502 million and translation exposures totaling $584 million as of March 31, 2012 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 the transactional exposures financial market risk sensitive instruments could affect net income by $33 million and the transactional exposures financial market risk sensitive instruments could affect the future fair value by $58 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, 2012 our long term borrowings consisted of $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 credit facility, 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 facility, 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 six 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 4. Mine Safety Disclosures

Information regarding mine safety and other regulatory actions at our mines is included in Exhibit 95 to this Form 10-Q.

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.

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		Fifth Amended and Restated Certificate of Incorporation of National Oilwell Varco, 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, as amended and restated. (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)

10.16		Second Amendment to Employment Agreement dated as of December 31, 2009 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (12)

10.17		Third Amendment to Executive Agreement, dated as of December 31, 2009, of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (12)

10.18		Second Amendment to Employment Agreement dated as of December 31, 2009 between Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (12)

10.19		Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (12)



10.20		First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (12)

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.

95		Mine Safety Information pursuant to Section 1503 of the Dodd-Frank Act.

101		The following materials from our Quarterly Report on Form 10-Q for the period ended March 31, 2012 formatted in eXtensible Business Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (13)

*	Compensatory plan or arrangement for management or others.

(1)	Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 5, 2011.

(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 an Exhibit to our Current Report on Form 8-K filed on February 24, 2012.

(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 August 17, 2011.

(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.

(12)	Filed as an Exhibit to our Current Report on Form 8-K filed on January 5, 2010.

(13)	As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.

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.