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 JUNE 30, 2012

OR

¨ 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  þ    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  þ    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):

Large accelerated filer	þ	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	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  ¨    No  þ

As of August 2, 2012 the registrant had 426,422,229 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)

	June 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,917		$	3,535
Receivables, net		3,860			3,291
Inventories, net		5,501			4,030
Costs in excess of billings		953			593
Deferred income taxes		284			336
Prepaid and other current assets		499			325
Total current assets		13,014			12,110
Property, plant and equipment, net		2,700			2,445
Deferred income taxes		238			267
Goodwill		6,917			6,151
Intangibles, net		4,512			4,073
Investment in unconsolidated affiliates		365			391
Other assets		87			78
Total assets	$	27,833		$	25,515
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,265		$	901
Accrued liabilities		2,421			2,376
Billings in excess of costs		1,075			865
Current portion of long-term debt and short-term borrowings		1,289			351
Accrued income taxes		207			709
Deferred income taxes		224			214
Total current liabilities		6,481			5,416
Long-term debt		159			159
Deferred income taxes		1,935			1,852
Other liabilities		327			360
Total liabilities		8,902			7,787
Commitments and contingencies
Stockholders’ equity:
Common stock—par value $.01; 1 billion shares authorized; 426,371,654 and 423,900,601 shares issued and outstanding at June 30, 2012 and December 31, 2011		4			4
Additional paid-in capital		8,673			8,535
Accumulated other comprehensive loss		(69	)		(23	)
Retained earnings		10,212			9,103
Total Company stockholders' equity		18,820			17,619
Noncontrolling interests		111			109
Total stockholders’ equity		18,931			17,728
Total liabilities and stockholders’ equity	$	27,833		$	25,515

See notes to unaudited consolidated financial statements.

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NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(In millions, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenue	$	4,734		$	3,513		$	9,037		$	6,659
Cost of revenue		3,428			2,430			6,464			4,601
Gross profit		1,306			1,083			2,573			2,058
Selling, general and administrative		427			375			817			741
Operating profit		879			708			1,756			1,317
Interest and financial costs		(9	)		(9	)		(17	)		(23	)
Interest income		3			4			6			8
Equity income in unconsolidated affiliates		19			10			36			23
Other income (expense), net		(5	)		(7	)		(21	)		(26	)
Income before income taxes		887			706			1,760			1,299
Provision for income taxes		285			226			554			415
Net income		602			480			1,206			884
Net loss attributable to noncontrolling interests		(3	)		(1	)		(5	)		(4	)
Net income attributable to Company	$	605		$	481		$	1,211		$	888
Net income attributable to Company per share:
Basic	$	1.42		$	1.14		$	2.85		$	2.11
Diluted	$	1.42		$	1.13		$	2.84		$	2.10
Cash dividends per share	$	0.12		$	0.11		$	0.24		$	0.22
Weighted average shares outstanding:
Basic		425			422			424			421
Diluted		427			425			426			424

See notes to unaudited consolidated financial statements.

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NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(In millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income	$	602		$	480		$	1,206		$	884
Currency translation adjustments		(121	)		28			(56	)		92
Changes in derivative financial instruments, net of tax		(53	)		5			10			42
Comprehensive income		428			513			1,160			1,018
Comprehensive loss attributable to noncontrolling interest		(3	)		(1	)		(5	)		(4	)
Comprehensive income attributable to Company	$	431		$	514		$	1,165		$	1,022

See notes to unaudited consolidated financial statements.

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NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In millions)

	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	1,206		$	884
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		305			273
Deferred income taxes		51			(9	)
Equity income in unconsolidated affiliate		(36	)		(23	)
Dividend from unconsolidated affiliate		61			45
Other, net		43			33
Change in operating assets and liabilities, net of acquisitions:
Receivables		(162	)		(379	)
Inventories		(785	)		(363	)
Costs in excess of billings		(360	)		316
Prepaid and other current assets		(168	)		(110	)
Accounts payable		107			88
Billings in excess of costs		210			267
Income taxes payable		(557	)		(245	)
Other assets/liabilities, net		(232	)		110
Net cash provided by (used in) operating activities		(317	)		887
Cash flows from investing activities:
Purchases of property, plant and equipment		(253	)		(192	)
Business acquisitions, net of cash acquired		(2,014	)		(259	)
Dividend from unconsolidated affiliate		—			13
Other		17			14
Net cash used in investing activities		(2,250	)		(424	)
Cash flows from financing activities:
Borrowings against lines of credit and other debt		939			—
Repayments on debt		(2	)		(372	)
Cash dividends paid		(102	)		(93	)
Proceeds from stock options exercised		93			71
Other		27			16
Net cash provided by (used in) financing activities		955			(378	)
Effect of exchange rates on cash		(6	)		22
Increase (decrease) in cash and cash equivalents		(1,618	)		107
Cash and cash equivalents, beginning of period		3,535			3,333
Cash and cash equivalents, end of period	$	1,917		$	3,440
Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	12		$	30
Income taxes	$	1,021		$	712

See notes to unaudited consolidated financial statements.

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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 and six months ended June 30, 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):

	June 30, 2012		December 31, 2011
Raw materials and supplies	$	1,167	$	907
Work in process		1,100		852
Finished goods and purchased products		3,234		2,271
Total	$	5,501	$	4,030

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3. Accrued Liabilities

Accrued liabilities consist of (in millions):

	June 30,		December 31,
	2012		2011
Customer prepayments and billings	$	755	$	686
Accrued vendor costs		428		280
Compensation		321		468
Warranty		216		211
Insurance		105		103
Taxes (non income)		102		119
Fair value of derivatives		68		83
Interest		7		7
Other		419		419
Total	$	2,421	$	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		30
Amounts incurred		(26	)
Currency translation adjustments and other		1
Balance at June 30, 2012	$	216

4. Costs and Estimated Earnings on Uncompleted Contracts

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

	June 30,			December 31,
	2012			2011
Costs incurred on uncompleted contracts	$	6,102		$	5,839
Estimated earnings		3,372			3,775
		9,474			9,614
Less: Billings to date		9,596			9,886
	$	(122	)	$	(272	)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	953		$	593
Billings in excess of costs and estimated earnings on uncompleted contracts		(1,075	)		(865	)
	$	(122	)	$	(272	)

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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 or Loss in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three and six months ended June 30, 2012, a majority of these local currencies weakened against the U.S. dollar resulting in net Other Comprehensive Loss of $121 million and $56 million, respectively, upon the translation from local currencies to the U.S. dollar. For the three and six months ended June 30, 2011, a majority of these local currencies strengthened against the U.S. dollar resulting in net Other Comprehensive Income of $28 million and $92 million, respectively.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in Other Comprehensive Income or Loss, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income or Loss 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 or Loss related to cumulative changes in the fair value of derivatives that have settled in the current or prior periods. The accumulated effect resulted in Other Comprehensive Loss of $53 million (net of tax of $22 million) for the three months ended June 30, 2012 and Other Comprehensive Income of $10 million (net of tax of $4 million) for the six months ended June 30, 2012. The accumulated effect was Other Comprehensive Income of $5 million (net of tax of $2 million) and $42 million (net of tax of $16 million) for the three and six months ended June 30, 2011, respectively.

6. Business Segments

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenue:
Rig Technology	$	2,405		$	1,894		$	4,664		$	3,502
Petroleum Services & Supplies		1,776			1,359			3,480			2,624
Distribution & Transmission		780			423			1,344			833
Elimination		(227	)		(163	)		(451	)		(300	)
Total Revenue	$	4,734		$	3,513		$	9,037		$	6,659
Operating Profit:
Rig Technology	$	554		$	514		$	1,101		$	933
Petroleum Services & Supplies		390			249			778			480
Distribution & Transmission		46			25			89			52
Unallocated expenses and eliminations		(111	)		(80	)		(212	)		(148	)
Total Operating Profit	$	879		$	708		$	1,756		$	1,317
Operating Profit %:
Rig Technology		23.0	%		27.1	%		23.6	%		26.6	%
Petroleum Services & Supplies		22.0	%		18.3	%		22.4	%		18.3	%
Distribution & Transmission		5.9	%		5.9	%		6.6	%		6.2	%
Total Operating Profit %		18.6	%		20.2	%		19.4	%		19.8	%

The Company had revenues of 10% of total revenue from one of its customers for each of the three and six months ended June 30, 2012 and 12% of total revenue from one of its customers for each of the three and six months ended June 30, 2011. 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.

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7. Debt

Debt consists of (in millions):

	June 30,		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
Revolving Credit Facility		935		—
Other		12		9
Total debt		1,448		510
Less current portion		1,289		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 June 30, 2012, there were $935 million in borrowings against the credit facility, and there were $980 million in outstanding letters of credit issued under the credit facility, resulting in $85 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.22% 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 June 30, 2012.

The Company also had $2,054 million of additional outstanding letters of credit at June 30, 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.

The fair value of the Company’s debt is estimated using Level 2 inputs based on quoted prices for those or similar instruments. At June 30, 2012, the carrying value of the Company’s debt approximated its fair value.

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8. Tax

The effective tax rate for the three and six months ended June 30, 2012 was 32.1% and 31.5%, respectively, compared to 32.0% and 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 lower tax rates on income earned in foreign jurisdictions.

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Federal income tax at U.S. federal statutory rate	$	310		$	247		$	616		$	455
Foreign income tax rate differential		(57	)		(41	)		(80	)		(65	)
State income tax, net of federal benefit		9			5			17			11
Nondeductible expenses		10			14			23			24
Tax benefit of manufacturing deduction		(9	)		(6	)		(18	)		(12	)
Foreign dividends, net of foreign tax credits		14			5			20			10
Tax impact of foreign exchange		12			—			(18	)		—
Tax rate change on temporary differences		—			—			—			(13	)
Other		(4	)		2			(6	)		5
Provision for income taxes	$	285		$	226		$	554		$	415

The balance of unrecognized tax benefits at June 30, 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 and six months ended June 30, 2012.

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.

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 after 2005.

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.

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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 June 30, 2012, 3,496,443 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 six months ended June 30, 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 $22 million and $34 million for the three and six months ended June 30, 2012, respectively, and $19 million and $36 million for the three and six months ended June 30, 2011, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $8 million and $11 million for the three and six months ended June 30, 2012, respectively, and $6 million and $11 million for the three and six months ended June 30, 2011, respectively.

During the six months ended June 30, 2012, the Company granted 2,239,088 stock options and 482,428 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. Out of the total number of restricted stock and restricted stock units, 464,270 were granted February 21, 2012 and vest on the third anniversary of the date of grant. On May 16, 2012, 18,158 restricted stock awards were granted to the non-employee members of the board of directors. These restricted stock awards vest in equal thirds over three years on the anniversary of the grant date. 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 risk managed by using derivative instruments is foreign currency exchange 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).

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 June 30, 2012, the Company has determined that the fair value of its derivative financial instruments representing assets of $17 million and liabilities of $74 million (primarily currency related derivatives) are determined using level 2 inputs (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 June 30, 2012, the net fair value of the Company’s foreign currency forward contracts totaled a net liability of $57 million.

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At June 30, 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	June 30, 2012		December 31, 2011
Norwegian Krone	NOK	7,019	NOK	6,639
U.S. Dollar	$	424	$	402
Euro	€	414	€	456
Mexican Peso	MXN	204	MXN	—
Danish Krone	DKK	63	DKK	98
Singapore Dollar	SGD	15	SGD	10
British Pound Sterling	£	14	£	2

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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	June 30, 2012		December 31, 2011
Norwegian Krone	NOK	2,168	NOK	2,310
Russian Ruble	RUB	1,144	RUB	786
U.S. Dollar	$	605	$	483
Euro	€	376	€	161
Danish Krone	DKK	125	DKK	67
Brazilian Real	BRL	73	BRL	—
Singapore Dollar	SGD	36	SGD	5
British Pound Sterling	£	8	£	9
Canadian Dollar	CAD	2	CAD	—
Swedish Krone	SEK	—	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	June 30,		December 31,		Balance Sheet	June 30,		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	$	10	$	16	Accrued liabilities	$	44	$	62
Foreign exchange contracts	Other Assets		1		1	Other Liabilities		6		13
Total derivatives designated as hedging instruments under ASC Topic 815		$	11	$	17		$	50	$	75
Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts	Prepaid and other current assets	$	6	$	9	Accrued liabilities	$	24	$	21
Total derivatives not designated as hedging instruments under ASC Topic 815		$	6	$	9		$	24	$	21
Total derivatives		$	17	$	26		$	74	$	96

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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) ,
	Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30
	2012			2011			2012			2011			2012		2011
						Revenue		(6	)		21
Foreign exchange contracts		(5	)		87	Cost of revenue		(11	)		9	Other income (expense), net		4		(2	)
Total		(5	)		87			(17	)		30			4		(2	)

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
		Six Months Ended June 30,
		2012		2011
Foreign exchange contracts	Other income (expense), net		13		(15	)
Total			13		(15	)

(a) The Company expects that $(33) 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 (loss) recognized in income represents $(1) million and $2 million related to the ineffective portion of the hedging relationships for the six months ended June 30, 2012 and 2011, respectively, and $5 million and $(4) million related to the amount excluded from the assessment of the hedge effectiveness for the six months ended June 30, 2012 and 2011, respectively.

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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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Numerator:
Net income attributable to Company	$	605	$	481	$	1,211	$	888
Denominator:
Basic—weighted average common shares outstanding		425		422		424		421
Dilutive effect of employee stock options and other unvested stock awards		2		3		2		3
Diluted outstanding shares		427		425		426		424
Net income attributable to Company per share:
Basic	$	1.42	$	1.14	$	2.85	$	2.11
Diluted	$	1.42	$	1.13	$	2.84	$	2.10
Cash dividends per share	$	0.12	$	0.11	$	0.24	$	0.22

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 and six months ended June 30, 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 5 million shares for each of the three and six months ended June 30, 2012, and 2 million and 3 million shares for the three and six months ended June 30, 2011, respectively.

12. Cash Dividends

On May 16, 2012 the Company’s Board of Directors approved a cash dividend of $0.12 per share. The cash dividend was paid on June 29, 2012 to each stockholder of record on June 15, 2012. Cash dividends aggregated $51 million and $102 million for the three and six months ended June 30, 2012, respectively, and $47 million and $93 million for the three and six months ended June 30, 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. Commitments and Contingencies

We have received federal grand jury subpoenas and subsequent inquiries from governmental agencies requesting records related to our compliance with export trade laws and regulations. We have cooperated fully with agents from the Department of Justice, the Bureau of Industry and Security, the Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcement in responding to the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange Commission in connection with the inquiries previously made by the aforementioned federal agencies. We have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters.

In 2011, the Company acquired Ameron. On or about November 21, 2008, the United States Department of Treasury, Office of Foreign Assets Control (“OFAC”) sent a Requirement to Furnish Information to Ameron. Ameron retained counsel and conducted an internal investigation. In 2009, Ameron, through its counsel, responded to OFAC. On or about January 21, 2011, OFAC issued an administrative subpoena to Ameron. OFAC and Ameron have entered into Tolling Agreements. All of the conduct under review occurred before acquisition of Ameron by the Company. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.

In addition, we are involved in various other claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. As of June 30, 2012, the Company recorded an immaterial amount for contingent liabilities representing all contingencies believed to be probable. The Company has also assessed the potential for additional losses above the amounts accrued as well as potential losses for matters that are not probable but are reasonably possible. The total potential loss on these matters cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for and except for the specific cases referred to above, will not materially affect our financial position, cash flow or results of operations. As it relates to the specific cases referred to above we currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position, cash flow or results of operations. These estimated liabilities are based on the Company’s assessment of the nature of these matters, their progress toward resolution, the advice of legal counsel and outside experts as well as management’s intention and experience.

Our business is affected both directly and indirectly by governmental laws and regulations relating to the oilfield service industry in general, as well as by environmental and safety regulations that specifically apply to our business. Although we have not incurred material costs in connection with our compliance with such laws, there can be no assurance that other developments, such as new environmental laws, regulations and enforcement policies hereunder may not result in additional, presently unquantifiable, costs or liabilities to us.

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14. Acquisitions

In the six months ended June 30, 2012, the Company completed nine acquisitions for an aggregate purchase price of $2,014 million, net of cash acquired. These acquisitions included:

• The shares of NKT Flexibles I/S (“NKT”), a Denmark-based designer and manufacturer of flexible pipe products and systems for the offshore oil and gas industry, acquired on April 4, 2012.

• The shares of Enerflow Industries Inc. (U.S.) and certain assets of Enerflow Industries Inc. (Canada) (“Enerflow”), a Canada-based fabricator and manufacturer of pressure pumping, blending, and cementing equipment for use primarily in Canada and the U.S., acquired on May 16, 2012.

• The shares of Wilson Distribution Holdings (“Wilson”), a U.S.-based distributor of pipe, valves and fittings as well as mill, tool and safety products and services, acquired on May 31, 2012.

The following table displays the total preliminary purchase price allocation for the 2012 acquisitions. The purchase price allocation remains preliminary due to the timing of the acquisitions. The table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. (in millions):

Current assets, net of cash acquired	$	1,132
Property, plant and equipment		151
Intangible assets		602
Goodwill		801
Total assets acquired		2,686
Current liabilities		495
Long-term debt		1
Other liabilities		176
Total liabilities		672
Cash consideration, net of cash acquired	$	2,014

From the dates of acquisition, the results of operations from NKT and Enerflow are included in the Rig Technology segment and the results of operations from Wilson are included in the Distribution & Transmission segment. The intangible assets are expected to be amortizable. In addition, the goodwill resulting from the NKT acquisition is not expected to be deductible for tax purposes.

15. Subsequent Event

On July 19, 2012, the Company completed its previously announced acquisition of CE Franklin for approximately $235 million in cash. CE Franklin has been a leading supplier of products and services to the energy industry. CE Franklin distributes pipe, valves, flanges, fittings, production equipment, tubular products and other general oilfield supplies to oil and gas producers in Canada as well as to the oil sands, refining, heavy oil, petrochemical, forestry and mining industries. These products are distributed through its 39 branches, which are situated in towns and cities serving particular oil and gas fields of the western Canadian sedimentary basin. The Company will report the CE Franklin results within its Distribution & Transmission segment.

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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, Denmark, 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 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.

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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.

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EXECUTIVE SUMMARY

For its second quarter ended June 30, 2012 the Company generated $605 million in Net income attributable to Company, or $1.42 per fully diluted share, on $4.7 billion in revenue. Compared to the first quarter of 2012, revenue increased $431 million or 10 percent and Net income attributable to Company decreased $1 million. Compared to the second quarter of 2011, revenue increased $1.2 billion or 35 percent and Net income attributable to Company increased $124 million or 26 percent.

The second quarter of 2012 included pre-tax transaction charges of $28 million, the first quarter of 2012 included pre-tax transaction charges of $7 million, and the second quarter of 2011 included pre-tax transaction charges of $4 million. Excluding transaction charges from all periods, second quarter 2012 earnings were $1.46 per fully diluted share, compared to $1.44 per fully diluted share in the first quarter of 2012 and $1.14 per fully diluted share in the second quarter of 2011.

Operating profit excluding transaction charges was $907 million or 19.2 percent of sales in the second quarter of 2012, compared to $881 million or 20.5 percent of sales in the first quarter of 2012, and $712 million or 20.3 percent of sales in the second quarter of 2011. Second quarter 2012 results include a partial quarter for six businesses acquired during the period. These, together with the second quarter seasonal downturn in Canada, resulted in sequentially lower margins from the first quarter. Operating leverage or flow-through (the change in operating profit divided by the change in revenue) was six percent on the sequential revenue increase, and 16 percent on the year-over-year second quarter sales increase.

Oil & Gas Equipment and Services Market

Worldwide developed economies turned down in late 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 (West Texas Intermediate Crude Prices) earlier in 2008, oil prices collapsed back to average $43 per barrel 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 second quarter of 2012 dipped slightly to average $93 per barrel). After trading in the range of $6 to $9 an mmbtu from 2004 to 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 (second quarter 2012 averaged $2.28 per mmbtu). The recent gas price collapse appears to be a direct result of rising gas supply out of unconventional shale reservoir developments across North America, including gas associated with liquids production from shales.

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 1,970 rigs during the second quarter of 2012 (and had fallen to 1,924 by late July 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 42 percent to 505 in the past year. However, with high oil prices many redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. Oil drilling has risen to 74 percent of the total domestic drilling effort, and, at 1,416 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 1,285 in June 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 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.

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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, nearly 70 percent of the existing 485 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 second quarter of 2012 at $11.3 billion. Approximately $3.9 billion of these orders are scheduled to flow out as revenue during the remainder of 2012; $4.9 billion are scheduled to flow out as revenue during 2013; and the balance thereafter. The land rig backlog comprised 14 percent and equipment destined for offshore operations comprised 86 percent of the total backlog as of June 30, 2012. Equipment destined for international markets totaled 92 percent of the backlog.

Segment Performance

The Rig Technology segment generated $2.4 billion in revenues and $554 million in operating profit or 23.0 percent of sales, during the second quarter of 2012. Compared to the prior quarter, revenues increased $146 million and operating profit increased $7 million. Margins declined sequentially due to two acquisitions made during the quarter. Compared to the second quarter of 2011 segment revenues grew 27 percent, margins declined 410 basis points, and operating leverage or flow-through was eight percent. In addition to the acquisition effect, margins have moved down steadily since mid-2010 due to an 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 second quarter of 2010. As these projects have been completed and replaced with lower priced projects, margins have gradually declined. Revenue out of backlog increased six percent sequentially and increased 31 percent year-over-year. Non-backlog revenue, which is predominantly aftermarket spares and services, increased seven percent sequentially and increased 17 percent from the second quarter of 2011. Orders for six deepwater floating rig equipment packages, five jackup packages and backlog additions from the segment’s two acquisitions ($511 million) contributed to total order additions to backlog of $2,733 million during the second quarter. Interest in offshore rig construction has remained strong as announced dayrates for deepwater offshore rigs are 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 an additional semi-submersible drilling equipment package for Brazil in the second quarter of 2012. The Company 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 $1.8 billion in revenue and $390 million in operating profit, or 22.0 percent of sales, for the second quarter of 2012. Compared to the prior quarter revenue increased four percent, and operating leverage or flow-through was three percent. Year-over-year operating leverage or flow-through was 34 percent on the segment’s 31 percent sales growth. The segment acquired two small businesses during the second quarter, but the contribution from these was not significant. Margins declined 80 basis points sequentially due to the seasonal breakup in Canada, which led to a 71 percent sequential decline in rigs drilling in that region. Second quarter Canadian revenue declines carried high decremental operating leverage, but higher sequential sales and margins within drill pipe, fiberglass pipe sales, XL Systems and Tuboscope tubular inspection and coating more than offset the Canadian operating profit declines. Drill pipe achieved record production levels during the second quarter, but saw orders decline through the quarter. Generally international markets remain strong, but certain business units in North America within

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the segment began to see signs of reduced spending during the quarter. Approximately 62 percent of the segment’s second quarter sales were into North American markets, and 38 percent of sales were into international markets.

The Distribution & Transmission segment generated $780 million in revenue and $46 million in operating profit or 5.9 percent of sales during the second quarter of 2012. Revenues grew $216 million or 38 percent from the first quarter of 2012, and operating profit leverage or flow-through was one percent. Compared to the second quarter of 2011 revenues increased $357 million or 84 percent and flow-through or operating leverage was six percent, due mostly to the acquisitions of the Wilson and Engco, made during the second quarter, and Ameron Water Transmission and Infrastructure Products, made during the fourth quarter of 2011. The distribution services portion of the segment saw Canadian sales decline 26 percent sequentially, but this was fully offset by revenue gains in the U.S. and international markets. Transmission posted higher sales of infrastructure products, which were partly offset by lower sequential sales of Mono industrial pumps and artificial lift products. Approximately 79 percent of the group’s second quarter sales were into North American markets and 21 percent into international markets. Subsequent to the close of the second quarter the segment completed its previously announced acquisition of CE Franklin, a leading Canadian oilfield distribution business.

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 deepwater drilling rigs have rebounded sharply, and the Rig Technology segment continues to experience a high level of interest as dayrates are improving for deepwater offshore rigs. While lower pricing led to declines in Rig Technology margins since mid-2010, we expect margins to stabilize in the mid-20 percent range. Recently won offshore rig construction orders at higher margins flowing in are likely to be offset by lower-margin contributions from recent subsea production equipment acquisitions, and a softening outlook for land drilling, workover and pressure pumping equipment markets in North America, in view of low gas and natural gas liquids 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 are likely to come under pressure through the second half of 2012. Additionally, economic weakness may pressure oil prices, which could lead to further activity declines, particularly among North American operators which may rely on cash flows from gas production and/or external financing to fund their drilling operations.

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. The Company has a long history of cost-control and downsizing in response to slowing 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.

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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 second quarter of 2012 and 2011, and the first quarter of 2012 include the following:

	2Q12*		2Q11*		1Q12*		% 2Q12 v 2Q11			% 2Q12 v 1Q12
Active Drilling Rigs:
U.S.		1,970		1,829		1,991		7.7	%		(1.1	%)
Canada		173		188		592		(8.0	%)		(70.8	%)
International		1,229		1,147		1,189		7.1	%		3.4	%
Worldwide		3,372		3,164		3,772		6.6	%		(10.6	%)
West Texas Intermediate Crude Prices (per barrel)	$	93.42	$	102.23	$	102.88		(8.6	%)		(9.2	%)
Natural Gas Prices ($/mmbtu)	$	2.28	$	4.36	$	2.45		(47.7	%)		(6.9	%)

* 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 June 30, 2012 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).

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The worldwide quarterly average rig count decreased 11% (from 3,772 to 3,372) and the U.S. decreased 1% (from 1,991 to 1,970), in the second quarter of 2012 compared to the first quarter of 2012. The average per barrel price of West Texas Intermediate Crude decreased 9% (from $102.88 per barrel to $93.42 per barrel) and natural gas prices decreased 7% (from $2.45 per mmbtu to $2.28 per mmbtu) in the second quarter of 2012 compared to the first quarter of 2012.

U.S. rig activity at July 27, 2012 was 1,924 rigs compared to the second quarter average of 1,970 rigs, decreasing 1%. The price for West Texas Intermediate Crude was at $90.13 per barrel at July 27, 2012, decreasing 4% from the second quarter average. The price for natural gas was at $3.01 per mmbtu at July 27, 2012, increasing 32% from the second quarter average.

Results of Operations

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenue:
Rig Technology	$	2,405		$	1,894		$	4,664		$	3,502
Petroleum Services & Supplies		1,776			1,359			3,480			2,624
Distribution & Transmission		780			423			1,344			833
Elimination		(227	)		(163	)		(451	)		(300	)
Total Revenue	$	4,734		$	3,513		$	9,037		$	6,659
Operating Profit:
Rig Technology	$	554		$	514		$	1,101		$	933
Petroleum Services & Supplies		390			249			778			480
Distribution & Transmission		46			25			89			52
Unallocated expenses and eliminations		(111	)		(80	)		(212	)		(148	)
Total Operating Profit	$	879		$	708		$	1,756		$	1,317
Operating Profit %:
Rig Technology		23.0	%		27.1	%		23.6	%		26.6	%
Petroleum Services & Supplies		22.0	%		18.3	%		22.4	%		18.3	%
Distribution & Transmission		5.9	%		5.9	%		6.6	%		6.2	%
Total Operating Profit %		18.6	%		20.2	%		19.4	%		19.8	%

Rig Technology

Three and Six Months Ended June 30, 2012 and 2011. Revenue from Rig Technology was $2,405 million for the three months ended June 30, 2012 compared to $1,894 million for the three months ended June 30, 2011, an increase of $511 million (27.0%). For the six months ended June 30, 2012, revenue from Rig Technology was $4,664 million compared to $3,502 million for the six months ending June 30, 2011, an increase of $1,162 million (33.2%). Deepwater offshore drilling worldwide and active shale plays in North America continue to be the driving force for the increase in revenue for this segment resulting in increased rig construction as well as demand for well intervention and stimulation equipment and aftermarket spare parts and services. In addition, the acquisitions of NKT and Enerflow, occurring towards the beginning of the second quarter of 2012, contributed to the increase in revenue for Rig Technology.

Operating profit from Rig Technology was $554 million for the three months ended June 30, 2012 compared to $514 million for the three months ended June 30, 2011, an increase of $40 million (7.8%). Operating profit percentage decreased in the three months ended June 30, 2012 to 23.0%, from 27.1% in the three months ended June 30, 2011. For the six months ended June 30, 2012, operating profit from Rig Technology was $1,101 million compared to $933 million for the six months ended June 30, 2011, an increase of $168 million (18.0%). Operating profit percentage decreased to 23.6% in the six months ended June 30, 2012, from 26.6% in the six months ended June 30, 2011. The decrease in operating profit percentage was 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. The integration of the NKT and Enerflow acquisitions made during the second quarter of 2012 also contributed to lower operating profit percentages. This decrease in operating profit percentage was partially offset by the increase in demand for well intervention and stimulation equipment containing higher operating profit percentages.

23

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 $11.3 billion at June 30, 2012, an increase of $3.6 billion (46.8%) from backlog of $7.7 billion at June 30, 2011.

Petroleum Services & Supplies

Three and Six Months Ended June 30, 2012 and 2011. Revenue from Petroleum Services & Supplies was $1,776 million for the three months ended June 30, 2012 compared to $1,359 million for the three months ended June 30, 2011, an increase of $417 million (30.7%). For the six months ended June 30, 2012, revenue from Petroleum Services & Supplies was $3,480 million compared to $2,624 million for the six months ended June 30, 2011, an increase of $856 million (32.6%). The increase was primarily attributable to shale plays leading to a stronger North American market with an 8% increase in U.S. rig activity compared to the second 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 period results of Ameron as well as other 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 $390 million for the three months ended June 30, 2012 compared to $249 million for the three months ended June 30, 2011, an increase of $141 million (56.6%). Operating profit percentage increased to 22.0% in the three months ended June 30, 2012, up from 18.3% in the three months ended June 30, 2011. For the six months ended June 30, 2012, operating profit from Petroleum Services & Supplies was $778 million compared to $480 million for the six months ended June 30, 2011, an increase of $298 million (62.1%). Operating profit percentage increased to 22.4% in the six months ended June 30, 2012, up from 18.3% in the six months ended June 30, 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 and Six Months Ended June 30, 2012 and 2011. Revenue from Distribution & Transmission was $780 million for the three months ended June 30, 2012 compared to $423 million for the three months ended June 30, 2011, an increase of $357 million (84.4%). For the six months ended June 30, 2012, revenue from Distribution & Transmission totaled $1,344 million compared to $833 million for the six months ended June 30, 2011, an increase of $511 million (61.3%). This increase was primarily attributable to the acquisition of Wilson during the second quarter of 2012. In addition, CE Franklin, a leading Canadian supplier of products and services to the energy industry, was acquired by the Company on July 19, 2012. For the third quarter of 2012, the incremental impact on revenue related to full quarter results for Wilson and almost full quarter results for CE Franklin is expected to add approximately $500 million to revenue at approximately 5% operating profit.

Operating profit from Distribution & Transmission was $46 million for the three months ended June 30, 2012 compared to $25 million for the three months ended June 30, 2011, an increase of $21 million (84.0%). Operating profit percentage was 5.9% for each of the three months ended June 30, 2012 and 2011. For the six months ended June 30, 2012, operating profit from Distribution & Transmission was $89 million compared to $52 million for the six months ended June 30, 2011, an increase of $37 million (71.2%). Operating profit percentage increased to 6.6% in the six months ended June 30, 2012 from 6.2% in the six months ended June 30, 2011. Increased volume, greater cost efficiencies and continued favorable pricing which related to strong demand for this segment contributed to an increase in operating profit percentages for this segment. However, much of the increase was offset by the integration of acquired, slightly lower operating profit percentage, businesses made during the second quarter of 2012.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $111 million and $212 million for the three and six months ended June 30, 2012, respectively, compared to $80 million and $148 million, respectively, for the same periods in 2011. 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 $9 million and $17 million for the three and six months ended June 30, 2012, respectively, compared to $9 million and $23 million, respectively, for the same periods in 2011. The decrease in interest and financial costs, for the six months ended June 30, 2012, was due to an overall decrease in average debt levels for the six months ended June 30, 2012 compared to the same period in 2011.

24

Provision for income taxes

The effective tax rate for the three and six months ended June 30, 2012 was 32.1% and 31.5%, respectively, compared to 32.0% and 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 lower tax rates on income earned in foreign jurisdictions.

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									Six Months Ended June 30,
	June 30,						March 2012
	2012			2011						2012			2011
Reconciliation of operating profit:
GAAP operating profit	$	879		$	708		$	877		$	1,756		$	1,317
Other costs:
Transaction costs		28			4			4			32			6
Libya asset write-down		—			—			—			—			17
Operating profit excluding other costs	$	907		$	712		$	881		$	1,788		$	1,340
	Three Months Ended									Six Months Ended June 30,
	June 30,						March 2012
	2012			2011						2012			2011
Reconciliation of operating profit %:
GAAP operating profit %		18.6	%		20.2	%		20.4	%		19.4	%		19.8	%
Other costs %		0.6	%		0.1	%		0.1	%		0.4	%		0.3	%
Operating profit % excluding other costs		19.2	%		20.3	%		20.5	%		19.8	%		20.1	%
	Three Months Ended									Six Months Ended June 30,
	June 30,						March 2012
	2012			2011						2012			2011
Reconciliation of diluted earnings per share:
GAAP earnings per share	$	1.42		$	1.13		$	1.42		$	2.84		$	2.10
Other costs		0.04			0.01			0.02			0.06			0.05
Earnings per share excluding other costs	$	1.46		$	1.14		$	1.44		$	2.90		$	2.15

25

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 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 June 30, 2012, the Company had cash and cash equivalents of $1,917 million, and total debt of $1,448 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 $1,917 million of cash and cash equivalents at June 30, 2012, approximately $1,712 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 June 30, 2012 was $1,448 million and 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, $935 million in borrowings against its credit facility and other debt of $12 million. The Company has a $2 billion, five-year revolving credit facility which expires April 21, 2013. At June 30, 2012 there were $935 million in borrowings against the credit facility, and there were $980 million in outstanding letters of credit issued under the credit facility, resulting in $85 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.22% 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 June 30, 2012.

The following table summarizes our net cash provided by (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):

	Six Months Ended June 30,
	2012			2011
Net cash provided by (used in) operating activities	$	(317	)	$	887
Net cash used in investing activities		(2,250	)		(424	)
Net cash provided by (used in) financing activities		955			(378	)

Operating Activities

For the first six months of 2012, cash used in operating activities was $317 million compared to cash provided by operating activities of $887 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 $1,206 million plus non-cash charges of $356 million and $61 million in a dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $36 million in equity income.

Net changes in operating assets and liabilities, net of acquisitions, used $1,947 million for the first six months of 2012 compared to $316 million used in the same period in 2011. Due to an increase in market activity during the first six 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 six months of 2012 also resulted in higher taxes paid, 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.

26

Investing Activities

For the first six months of 2012, net cash used in investing activities was $2,250 million compared to net cash used in investing activities of $424 million for the same period of 2011. Net cash used in investing activities continued to primarily be the result of acquisition activity and capital expenditures both of which increased in the first six months of 2012 compared to the first six months of 2011. The Company used $2,014 million for the purpose of strategic acquisitions during the first six months of 2012 compared to $259 million for the same period of 2011. In addition, due to the continued growth in the Company worldwide both organically and through acquisition, the Company used $253 million during the first six months of 2012 for capital expenditure compared to $192 million for the same period of 2011. During the first six months of 2012, the Company used a combination of its cash on hand as well as borrowings from its revolving credit facility to fund its acquisitions and capital expenditures.

Financing Activities

For the first six months of 2012, net cash provided by financing activities was $955 million compared to cash used in financing activities of $378 million for the same period of 2011. The change related to a shift from the Company primarily repaying its Senior Notes during the first six months of 2011 to the Company borrowing on its revolving credit facility during the first six months of 2012. Credit facility borrowings were approximately $935 million during the first six months of 2012 with the majority of funds received used to finance acquisitions and make tax payments. Repayments on debt during the first six months of 2012 were $2 million compared to $372 million for the same period of 2011. In addition, proceeds from stock options exercised were $93 million during the first six months of 2012 compared to $71 million for the same period of 2011. The Company also increased its dividend slightly to $102 million during the first six months of 2012 compared to $93 million for the same period of 2011.

The effect of the change in exchange rates on cash flows was a negative $6 million and a positive $22 million for the six months ended June 30, 2012 and 2011, respectively.

We believe that cash on hand, cash generated from operations and amounts available under our 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 continue to 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.

27

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 $3 million in the first six months of 2012, compared to a $16 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 June 30, 2012 (in millions, except contract rates):

	As of June 30, 2012											December 31,
Functional Currency	2012			2013			2014		Total			2011
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		284			—			—		284			274
Average USD to CAD contract rate		1.0278			—			—		1.0278			1.0315
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			(3	)
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		114			178			—		292			239
Average USD to CAD contract rate		1.0195			1.0350			—		1.0289			1.0196
Fair Value at June 30, 2012 in U.S. dollars		(1	)		1			—		—			(1	)
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		2			2			—		4			10
Average USD to EUR contract rate		1.2861			1.2946			—		1.2901			1.4035
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			1
Sell USD/Buy EUR:
Notional amount to buy (in euros)		71			47			—		118			120
Average USD to EUR contract rate		1.3477			1.3225			—		1.3336			1.3846
Fair Value at June 30, 2012 in U.S. dollars		(6	)		(2	)		—		(8	)		(11	)
KRW Buy USD/Sell KRW:
Notional amount to buy (in South Korean won)		58,220			261			—		58,481			385
Average USD to KRW contract rate		1,164.4000			918.8186			—		1,163.0130			920.3811
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)		1,025			639			58		1,722			53,825
Average USD to KRW contract rate		1,167.0461			1,020.2488			940.5000		1,099.4438			1,151.5509
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		43			—			—		43			45
Average USD to GBP contract rate		1.5537			—			—		1.5537			1.5499
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—

28

	As of June 30, 2012											December 31,
Functional Currency	2012			2013			2014		Total			2011
GBP Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		38			9			—		47			44
Average USD to GBP contract rate		1.5562			1.5514			—		1.5553			1.5818
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			(2	)
USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		24			3			—		27			27
Average DKK to USD contract rate		5.5578			5.6081			—		5.5637			5.4213
Fair Value at June 30, 2012 in U.S. dollars		(2	)		—			—		(2	)		(1	)
Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		474			263			2		739			710
Average EUR to USD contract rate		1.3286			1.3248			1.2931		1.3272			1.3783
Fair Value at June 30, 2012 in U.S. dollars		(25	)		(12	)		—		(37	)		(40	)
Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		29			2			—		31			15
Average GBP to USD contract rate		1.5901			1.5644			—		1.5883			1.5737
Fair Value at June 30, 2012 in U.S. dollars		(1	)		—			—		(1	)		—
Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		525			590			160		1,275			1,336
Average NOK to USD contract rate		5.9693			5.9864			6.1366		5.9982			5.9427
Fair Value at June 30, 2012 in U.S. dollars		(4	)		(8	)		—		(12	)		(22	)
Buy MXN/Sell USD:
Notional amount to buy (in U.S. dollars)		15			—			—		15			—
Average MXN to USD contract rate		13.8602			—			—		13.8602			—
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Buy SGD/Sell USD:
Notional amount to buy (in U.S. dollars)		27			8			—		35			10
Average SGD to USD contract rate		1.2751			1.2715			—		1.2743			1.3022
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Sell CAD/Buy USD:
Notional amount to buy (in U.S. dollars)		2			—			—		2			—
Average CAD to USD contract rate		1.0125			—			—		1.0125			—
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		7			—			—		7			3
Average DKK to USD contract rate		5.8030			—			—		5.8030			5.5036
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		286			10			—		296			137
Average EUR to USD contract rate		1.2652			1.3529			—		1.2679			1.3517
Fair Value at June 30, 2012 in U.S. dollars		1			1			—		2			5
Sell GBP/Buy USD:
Notional amount to sell (in U.S. dollars)		4			—			—		4			—
Average GBP to USD contract rate		1.5931			—			—		1.5931			—
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		235			22			1		258			173
Average NOK to USD contract rate		5.9770			6.0791			6.1610		5.9861			5.8173
Fair Value at June 30, 2012 in U.S. dollars		6			—			—		6			6
Sell SGD/Buy USD:
Notional amount to sell (in U.S. dollars)		6			—			—		6			2
Average SGD to USD contract rate		1.2516			—			—		1.2516			0.7674
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Sell RUB/Buy USD:
Notional amount to sell (in U.S. dollars)		34			—			—		34			24
Average RUB to USD contract rate		33.6400			—			—		33.6400			32.7613
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
DKK Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		71			—			—		71			96
Average DKK to USD contract rate		5.9228			—			—		5.9228			5.6717
Fair Value at June 30, 2012 in U.S. dollars		—			—			—		—			—
Other Currencies
Fair Value at June 30, 2012 in U.S. dollars		(4	)		(1	)		—		(5	)		(2	)
Total Fair Value at June 30, 2012 in U.S. dollars		(36	)		(21	)		—		(57	)		(70	)

29

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $412 million and translation exposures totaling $489 million as of June 30, 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 $27 million and the transactional exposures financial market risk sensitive instruments could affect the future fair value by $49 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 June 30, 2012 our 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, and $935 million in borrowings under our revolving credit facility. Occasionally a portion of borrowings under our credit facility 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.

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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 32.

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: August 6, 2012	By:	/s/ Clay C. Williams
		Clay C. Williams
		Executive Vice President and Chief Financial Officer
		(Duly Authorized Officer, Principal Financial and Accounting Officer)

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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)

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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 June 30, 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.

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