Edgar Filing: NATIONAL OILWELL VARCO INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)


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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010


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

Commission File Number 1-12317

NATIONAL OILWELL VARCO, INC.

(Exact name of registrant as specified in its charter)


Delaware		76-0475815

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

7909 Parkwood Circle Drive
Houston, Texas
77036-6565

(Address of principal executive offices)

(713) 346-7500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

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


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

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

As of November 1, 2010 the registrant had 419,635,478 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)


	September 30,		December 31,
	2010		2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	3,070	$	2,622
Receivables, net		2,408		2,187
Inventories, net		3,562		3,490
Costs in excess of billings		769		740
Deferred income taxes		232		290
Prepaid and other current assets		285		269

Total current assets		10,326		9,598

Property, plant and equipment, net		1,808		1,836
Deferred income taxes		269		92
Goodwill		5,525		5,489
Intangibles, net		3,877		4,052
Investment in unconsolidated affiliate		365		393
Other assets		61		72

Total assets	$	22,231	$	21,532


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	585	$	584
Accrued liabilities		2,289		2,267
Billings in excess of costs		293		1,090
Current portion of long-term debt and short-term borrowings		354		7
Accrued income taxes		351		226

Total current liabilities		3,872		4,174

Long-term debt		516		876
Deferred income taxes		2,197		2,091
Other liabilities		242		163

Total liabilities		6,827		7,304


Commitments and contingencies

Stockholders’ equity:
Common stock — par value $.01; 419,167,762 and 418,451,731 shares issued and outstanding at September 30, 2010 and December 31, 2009		4		4
Additional paid-in capital		8,267		8,214
Accumulated other comprehensive income		109		90
Retained earnings		6,906		5,805

Total Company stockholders’ equity		15,286		14,113
Noncontrolling interests		118		115

Total stockholders’ equity		15,404		14,228

Total liabilities and stockholders’ equity	$	22,231	$	21,532

See notes to unaudited consolidated financial statements.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenue	$	3,011		$	3,087		$	8,984		$	9,578
Cost of revenue		2,066			2,196			6,149			6,773

Gross profit		945			891			2,835			2,805
Selling, general and administrative		349			279			1,012			932
Intangible asset impairment		—			—			—			147
Transaction and restructuring costs		—			11			—			19

Operating profit		596			601			1,823			1,707
Interest and financial costs		(12	)		(14	)		(38	)		(40	)
Interest income		4			4			9			8
Equity income in unconsolidated affiliate		8			1			22			45
Other income (expense), net		(23	)		(13	)		(42	)		(87	)

Income before income taxes		573			579			1,774			1,633
Provision for income taxes		169			192			552			551

Net income		404			387			1,222			1,082
Net income (loss) attributable to noncontrolling interests		—			2			(5	)		7

Net income attributable to Company	$	404		$	385		$	1,227		$	1,075


Net income attributable to Company per share:
Basic	$	0.97		$	0.93		$	2.94		$	2.58

Diluted	$	0.96		$	0.92		$	2.93		$	2.58


Cash dividends per share	$	0.10		$	—		$	0.30		$	—


Weighted average shares outstanding:
Basic		417			416			417			416

Diluted		419			418			419			417

See notes to unaudited consolidated financial statements.

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


	Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities:
Net income	$	1,222		$	1,082
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		378			364
Equity income in unconsolidated affiliate		(22	)		(45	)
Dividend from unconsolidated affiliate		17			86
Intangible asset impairment		—			147
Other, net		29			(53	)
Change in operating assets and liabilities, net of acquisitions:
Receivables		(238	)		979
Inventories		(101	)		103
Costs in excess of billings		(29	)		7
Prepaid and other current assets		(15	)		(122	)
Accounts payable		1			(384	)
Billings in excess of costs		(797	)		(545	)
Other assets/liabilities, net		290			350

Net cash provided by operating activities		735			1,969


Cash flows from investing activities:
Purchases of property, plant and equipment		(140	)		(186	)
Business acquisitions, net of cash acquired		(69	)		(392	)
Business divestitures, net of cash disposed		—			251
Dividend from unconsolidated affiliate		16			8
Other		23			—

Net cash used in investing activities		(170	)		(319	)


Cash flows from financing activities:
Borrowings against lines of credit and other debt		2			7
Repayments on debt		(13	)		(35	)
Cash dividends paid		(126	)		—
Other, net		14			3

Net cash used in financing activities		(123	)		(25	)
Effect of exchange rates on cash		6			24

Increase in cash equivalents		448			1,649
Cash and cash equivalents, beginning of period		2,622			1,543

Cash and cash equivalents, end of period	$	3,070		$	3,192


Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	38		$	37
Income taxes	$	344		$	603

See notes to unaudited consolidated financial statements.

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

1. Basis of Presentation

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

The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (the “Company”) present information in accordance with GAAP in the United States for interim financial information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not include all information or footnotes required by GAAP in the United States for complete consolidated financial statements and should be read in conjunction with our 2009 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 nine months ended September 30, 2010 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):


	September 30,		December 31,
	2010		2009
Raw materials and supplies	$	671	$	704
Work in process		1,184		1,307
Finished goods and purchased products		1,707		1,479

Total	$	3,562	$	3,490

3. Accrued Liabilities

Accrued liabilities consist of (in millions):


	September 30,		December 31,
	2010		2009
Compensation	$	344	$	272
Customer prepayments and billings		396		500
Warranty		220		217
Interest		14		11
Taxes (non income)		83		95
Insurance		52		58
Accrued purchase orders		869		853
Fair value of derivatives		42		61
Other		269		200

Total	$	2,289	$	2,267

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, 2009	$	217

Net provisions for warranties issued during the year		43
Amounts incurred		(31	)
Foreign currency translation and other		(9	)

Balance at September 30, 2010	$	220

4. Costs and Estimated Earnings on Uncompleted Contracts

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


	September 30,			December 31,
	2010			2009
Costs incurred on uncompleted contracts	$	7,114		$	6,276
Estimated earnings		4,858			3,735

		11,972			10,011
Less: Billings to date		11,496			10,361

	$	476		$	(350	)


Costs and estimated earnings in excess of billings on uncompleted contracts	$	769		$	740
Billings in excess of costs and estimated earnings on uncompleted contracts		(293	)		(1,090	)

	$	476		$	(350	)

5. Comprehensive Income

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010			2009
Net income	$	404	$	387	$	1,222		$	1,082
Currency translation adjustments, net of tax		92		22		16			79
Changes in derivative financial instruments, net of tax		84		69		3			174
Changes in defined benefit plans, net of tax		—		1		—			—

Comprehensive income		580		479		1,241			1,335
Comprehensive income (loss) attributable to noncontrolling interest		—		2		(5	)		7

Comprehensive income attributable to Company	$	580	$	477	$	1,246		$	1,328

The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in Other Comprehensive Income in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three months ended September 30, 2010, a majority of these local currencies strengthened against the U.S. dollar resulting in a net increase to Other Comprehensive Income of $92 million upon the translation of their financial statements from their local currency to the U.S. dollar.

During the first quarter of 2010, the Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar. As a result the Company converted its Venezuela ledgers to U.S. dollar functional currency, devalued monetary assets resulting in a $27 million charge, and wrote-down certain accounts receivable in view of deteriorating business conditions in Venezuela, resulting in an additional $11 million charge. The Company’s net investment in Venezuela was $34 million at September 30, 2010.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of accumulated Other Comprehensive Income related to the fair value of derivatives that have settled in the current or prior periods. The accumulated effect is an increase in Other Comprehensive Income of $84 million (net of tax of $33 million) for the three months ended September 30, 2010.

6. Business Segments

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenue:
Rig Technology	$	1,650		$	2,000		$	5,208		$	6,116
Petroleum Services & Supplies		1,089			882			3,045			2,809
Distribution Services		424			306			1,123			1,019
Elimination		(152	)		(101	)		(392	)		(366	)

Total Revenue	$	3,011		$	3,087		$	8,984		$	9,578


Operating Profit:
Rig Technology	$	478		$	577		$	1,564		$	1,717
Petroleum Services & Supplies		164			82			415			195
Distribution Services		24			7			48			42
Unallocated expenses and eliminations		(70	)		(54	)		(204	)		(228	)
Transaction costs		—			(11	)		—			(19	)

Total Operating Profit	$	596		$	601		$	1,823		$	1,707


Operating Profit %:
Rig Technology		29.0	%		28.9	%		30.0	%		28.1	%
Petroleum Services & Supplies		15.1	%		9.3	%		13.6	%		6.9	%
Distribution Services		5.7	%		2.3	%		4.3	%		4.1	%
Total Operating Profit %		19.8	%		19.5	%		20.3	%		17.8	%

The Company had revenues of 14% and 17% of total revenue from one of its customers for the three and nine months ended September 30, 2010, respectively, and revenues of 19% and 17% of total revenue from one of its customers for the three and nine months ended September 30, 2009, respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.

7. Debt

Debt consists of (in millions):


	September 30,		December 31,
	2010		2009
Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011	$	150	$	150

Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011		202		205

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

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

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

Other		16		26

Total debt		870		883
Less current portion		354		7

Long-term debt	$	516	$	876

Revolving Credit Facilities

On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2 billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility which was terminated early in February 2009. At September 30, 2010, there were no borrowings against the remaining credit facility, and there were $517 million in outstanding letters of credit issued under this facility, resulting in $1,483 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% subject to a ratings-based grid, or the prime rate.

The Company also had $1,213 million of additional outstanding letters of credit at September 30, 2010, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. The Company was in compliance with all covenants at September 30, 2010.

8. Tax

The effective tax rate for the three and nine months ended September 30, 2010 was 29.5% and 31.1%, respectively, compared to 33.2% and 33.7% for the same period in 2009. The effective tax rate was positively impacted by earnings taxed at lower rates in foreign jurisdictions, and the reversal of reserves associated with uncertain tax positions related to prior years for which the statute of limitations expired during the period.

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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Federal income tax at U.S. federal statutory rate	$	201		$	203		$	621		$	572

Foreign income tax rate differential		(28	)		(23	)		(86	)		(81	)
State income tax, net of federal benefit		3			4			10			12
Foreign dividends, net of foreign tax credits		2			3			9			10
Benefit of U.S. Manufacturing Deduction		(8	)		(6	)		(14	)		(13	)
Change in tax reserves, including interest		(5	)		7			(19	)		4
Prior year tax on revaluation gains in Norway		—			—			—			21
Other		4			4			31			26

Provision for income taxes	$	169		$	192		$	552		$	551

The Company accounts for uncertainty in income taxes in accordance with ASC Topic 740, “Income Taxes” (“ASC Topic 740”). ASC Topic 740 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a return. Under ASC Topic 740, the impact of an uncertain income tax position, in management’s opinion, on the income tax return must be recognized at the largest amount that is more-likely-than-not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has a less than 50% likelihood of being sustained. The balance of unrecognized tax benefits at September 30, 2010 was $121 million. Included in the change in the balance of unrecognized tax benefits was an increase of $73 million associated with a foreign tax position previously evaluated as more-likely-than-not to be sustained upon audit. Based on new information obtained in the first quarter of 2010, we now believe it is more-likely-than-not this foreign tax position will not be sustained. Tax payments for this liability can be claimed as a U.S. foreign tax credit due to sufficient excess limitation in prior years to cover the potential exposure. Accordingly, the Company has recorded a corresponding deferred tax asset of $73 million, resulting in no impact to earnings.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):


Balance at December 31, 2009	$	58


Additions for tax positions of prior years		80
Reductions for lapse of applicable statutes of limitations		(17	)


Balance at September 30, 2010	$	121

The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The Company has significant operations in the U.S., Canada, the U.K., the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdiction vary by legal entity, but are generally open in the U.S. for the tax years after 2006 and outside the U.S. for tax years ending after 2002.

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

9. Stock-Based Compensation

The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights. The number of shares authorized under the Plan is 25.5 million. As of September 30, 2010, 8,120,958 shares remain available for future grants under the Plan, all of which are available for grants of stock options, performance-based share awards, restricted stock awards, phantom shares, stock payments and stock appreciation rights. Total stock-based compensation for all share-based compensation arrangements under the Plan was $17 million and $50 million for the three and nine months ended September 30, 2010, respectively, and $15 million and $46 million for the three and nine months ended September 30, 2009, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $5 million and $15 million for the three and nine months ended September 30, 2010, respectively, and $5 million and $17 million for the three and nine months ended September 30, 2009, respectively.

During the nine months ended September 30, 2010, the Company granted 3,485,283 stock options and 558,531 restricted stock awards, which includes 171,400 performance-based restricted stock awards. Out of the total number of stock options granted, 3,443,107 were granted on February 16, 2010 with an exercise price of $44.07, 10,844 were granted on May 12, 2010 with an exercise price of $41.09 and the remaining 31,332 options were granted May 12, 2010 to the non-employee members of the Board of Directors at an exercise price of $41.09. These options generally vest over a three-year period from the grant date. Out of the total number of restricted stock awards granted, 543,035 were granted on February 16, 2010 and 1,440 were granted on May 12, 2010 and vest on the third anniversary of the date of grant. In addition, on May 12, 2010, 14,056 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 of 171,400 were granted on February 16, 2010. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s average operating income growth, measured on a percentage basis, from January 1, 2010 through December 31, 2012 exceeding the median operating income level growth of a designated peer group over the same period.

10. Derivative Financial Instruments

ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires companies to recognize all of its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.

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

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 two and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog. The Company may also use interest rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt issuances.

At September 30, 2010, the Company has determined that its financial assets of $84 million and liabilities of $43 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At September 30, 2010, the net fair value of the Company’s foreign currency forward contracts totaled an asset of $41 million.

As of September 30, 2010, 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

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.

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

As of September 30, 2010, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and costs:


	Currency
Foreign Currency	Denomination
	(in millions)
British Pound Sterling	£	11
Danish Krone	DKK	48
Euro	€	107
Norwegian Krone	NOK	5,231
U.S. Dollar	$	244

Fair Value Hedging Strategy

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

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

As of September 30, 2010, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency fair values of firm commitments of revenues and costs:


	Currency
Foreign Currency	Denomination
	(in millions)
U.S. Dollar	$	10
Korean Won	KRW	5,479

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.

As of September 30, 2010, the Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts:


	Currency
Foreign Currency	Denomination
	(in millions)
British Pound Sterling	£	14
Danish Krone	DKK	136
Euro	€	56
Norwegian Krone	NOK	2,072
U.S. Dollar	$	447

As of September 30, 2010, 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
		September 30,		December 31,		Balance Sheet	September 30,		December 31,
	Balance Sheet	2010		2009		Location	2010		2009
Derivatives designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	55	$	56	Accrued liabilities	$	14	$	39
Foreign exchange contracts	Other Assets		13		17	Other Liabilities		3		7


Total derivatives designated as hedging instruments under ASC Topic 815		$	68	$	73		$	17	$	46


Derivatives not designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	16	$	30	Accrued liabilities	$	26	$	8
Foreign exchange contracts	Other Assets		—		1	Other Liabilities		—		1


Total derivatives not designated as hedging instruments under ASC Topic 815		$	16	$	31		$	26	$	9


Total derivatives		$	84	$	104		$	43	$	55

The Effect of Derivative Instruments on the Consolidated Statement of Income
($ in millions)

Location of Gain (Loss)

Recognized in Income on

Amount of Gain (Loss)

Location of Gain (Loss)

Derivative (Ineffective

Recognized in Income on

Reclassified from

Amount of Gain (Loss)

Portion and Amount

Derivative (Ineffective

Derivatives in ASC Topic 815

Amount of Gain (Loss)

Accumulated OCI into

Reclassified from

Excluded from

Portion and Amount

Cash Flow Hedging

Recognized in OCI on

Income

Accumulated OCI into

Effectiveness

Excluded from

Relationships

Derivative (Effective Portion) (a)

(Effective Portion)

Income (Effective Portion)

Testing)

Effectiveness Testing) (b)

Nine Months Ended

September 30,

2010

2009

2010

2009

2010

2009

Revenue

Foreign exchange contracts

(14

)

162

Cost of revenue

(26

)

(51

)

Other income (expense), net

(27

)

Total

(14

)

162

(20

)

(33

)

(27

)

Derivatives in ASC Topic 815

Location of Gain (Loss)

Amount of Gain (Loss)

ASC Topic 815

Location of Gain (Loss)

Recognized in Income on

Fair Value

Recognized in Income

Recognized in Income on

Fair Value Hedge

Recognized in Income on

Related Hedged

Hedging Relationships

on Derivative

Derivative

Relationships

Related Hedged Item

Items

Nine Months Ended

September 30,

2010

2009

2010

2009

Foreign exchange contracts

Revenue

)

Firm commitments

Revenue

Foreign exchange contracts

Cost of revenue

—

Firm commitments

Cost of revenue

—

)

Total

)

Derivatives Not Designated as

Location of Gain (Loss)

Amount of Gain (Loss)

Hedging Instruments under

Recognized in Income

Recognized in Income on

ASC Topic 815

on Derivative

Derivative

Nine Months Ended

September 30,

2010

2009

Foreign exchange contracts

Other income (expense), net

(14

)

Total

(14

)


(a)		The Company expects that ($35) 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 $5 million and $(27) million related to the ineffective portion of the hedging relationships for the nine months ended September 30, 2010 and 2009, respectively, and $8 million and $2 million related to the amount excluded from the assessment of the hedge effectiveness for the nine months ended September 30, 2010 and 2009, respectively.

11. Net Income Attributable to Company Per Share

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Numerator:
Net income attributable to Company	$	404	$	385	$	1,227	$	1,075

Denominator:
Basic—weighted average common shares outstanding		417		416		417		416
Dilutive effect of employee stock options and other unvested stock awards		2		2		2		1

Diluted outstanding shares		419		418		419		417


Net income attributable to Company per share:
Basic	$	0.97	$	0.93	$	2.94	$	2.58

Diluted	$	0.96	$	0.92	$	2.93	$	2.58

Cash dividends per share	$	0.10	$	—	$	0.30	$	—

In addition, the Company had stock options outstanding that were anti-dilutive totaling 6 million shares for both the three and nine months ended September 30, 2010, and 4 million and 6 million for the three and nine months ending September 30, 2009, respectively.

12. Cash Dividends

On August 18, 2010, the Company’s Board of Directors approved a cash dividend of $0.10 per share. The cash dividend was paid on September 24, 2010 to each stockholder of record on September 10, 2010. Cash dividends aggregated $42 million and $126 million for the three and nine months ended September 30, 2010, respectively, and nil for both the three and nine months ended September 30, 2009. 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. Recently Issued Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06 “Improving Disclosures about Fair Value Measurements” (“ASU No. 2010-06”) as an update to Accounting Standards Codification Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASU No. 2010-06 requires additional disclosures about transfers between Levels 1 and 2 of the fair value hierarchy and disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements. ASU No. 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Company adopted the required provisions of ASU No. 2010-06 in the first quarter of 2010. There was no significant impact to the Company’s Consolidated Financial Statements from the adopted provisions of ASU No. 2010-06.

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

Introduction

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

Rig Technology

Our Rig Technology segment designs, manufactures, sells and services complete systems for the drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line of highly-engineered equipment that automates complex well construction and management operations, such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly systems; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; wireline trucks; and cranes. Demand for Rig Technology products is primarily dependent on capital spending plans by drilling contractors, oilfield service companies, and oil and gas companies; and secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts for the segment’s large installed base of equipment. We have made strategic acquisitions and other investments during the past several years in an effort to expand our product offering and our global manufacturing capabilities, including adding operations in the United States, Canada, Norway, the United Kingdom, China, Belarus, India, Turkey, the Netherlands, Singapore, Brazil, 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 pipelines, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer pumps, solids control systems, drilling motors, 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 composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including adding operations in the United States, Canada, the United Kingdom, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, Brazil, and the United Arab Emirates.

Distribution Services

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

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2009, we identified our most critical accounting policies. In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are most critical in nature which are related to revenue recognition under long-term construction contracts; allowance for doubtful accounts; inventory reserves; impairments of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets; service and product warranties and income taxes. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. The combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates and those differences may be material.

EXECUTIVE SUMMARY

National Oilwell Varco generated $404 million in net income attributable to the Company, or $0.96 per fully diluted share, on $3.0 billion in revenue in its third quarter ended September 30, 2010. Compared to the second quarter of 2010 revenue increased two percent and net income attributable to the Company increased one percent. Compared to the third quarter of 2009 revenue decreased two percent and net income attributable to the Company increased five percent.

Operating profit excluding transaction charges of $2 million was $598 million or 19.9 percent of sales in the third quarter of 2010, compared to $594 million or 20.2 percent of sales in the second quarter of 2010 excluding transaction charges of $4 million. Operating profit excluding transaction and restructuring charges was $618 million or 20.0 percent of sales for the third quarter of 2009.

Revenues, operating profit and operating margins increased both sequentially and year-over-year for the Company’s Petroleum Services & Supplies and Distribution Services segments. The Company’s Rig Technology segment posted one percent lower revenues sequentially and 18 percent lower revenues compared to the prior year third quarter, due primarily to lower revenues from the segment’s backlog of capital equipment orders. The Company generally benefitted from initiatives undertaken throughout all three segments to reduce operating costs in view of depressed market conditions during 2009.

A moratorium on deepwater drilling in the Gulf of Mexico was enacted during the second quarter of 2010 following the Macondo well blowout and oil spill, which continued through the third quarter of 2010. We estimate that the drilling moratorium reduced earnings by approximately two cents per fully diluted share, with most of the impact affecting the Petroleum Services & Supplies segment. We expect a similar impact in the fourth quarter of 2010. The Distribution Services segment posted higher sales in the Gulf Coast as it helped outfit the response effort with basic supplies during the third quarter, but it has seen these incremental Gulf Coast sales decline significantly during the fourth quarter. We are hopeful that the on-going rebound in U.S. drilling activity will offset this decline to some degree. The Rig Technology group saw modestly higher purchases of spares and consumables among the affected rigs, which appear to be utilizing this period of low drilling activity in the Gulf of Mexico to conduct upgrade and maintenance activities. Although the moratorium has been lifted, some offshore drilling contractors appear to be pausing to see the ultimate resolution of new pressure control equipment requirements, and as a result some specific purchases, such as drill pipe and conductor pipe connections, are at risk pending the outcome of this pause.

Oil & Gas Equipment and Services Market

Worldwide, developed economies turned down sharply 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 continues to dampen economic growth in many developed economies. As a result asset and commodity prices, including oil and gas prices, declined. After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to average $42.91 per barrel (West Texas Intermediate Crude Prices) during the first quarter of 2009, but recovered into the $70 to $80 per barrel range by the end of 2009 where they are holding steady (the third quarter of 2010 averaged $76.05 per barrel). North American gas prices declined to $3.17 per mmbtu in the third quarter of 2009 but recovered to average $4.28 per mmbtu in the third quarter of 2010. 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.

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 has since increased to 1,672 in late October 2010, and averaged 1,622 rigs during the third quarter of 2010. 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 firmed above $4.00 per mmbtu and, more recently, as operators began to drill unconventional shale plays targeting oil, rather than gas. Oil drilling has risen to 42 percent of the total domestic drilling effort.

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 has exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 947 in August 2009, but recently climbing back to 1,120 in September 2010.

During 2009 the Company saw its Petroleum Services & Supplies and its Distribution Services margins affected most acutely by a drilling downturn, through both volume and price declines; nevertheless, both of these segments saw pricing stabilize and revenues recover modestly since the third quarter of 2009. The Company’s Rig Technology segment was less impacted owing to its high level of contracted backlog which it executed on very well since the economic downturn.

The recent 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, 71 percent of the existing 459 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, employing recent advancements in deepwater drilling to exploit unexplored deepwater basins. We believe the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet, and declining dayrates may accelerate the retirement of older rigs.

As a result of these trends the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at March 31, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders have declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $4.9 billion by June 30, 2010. The decline was halted during the third quarter, when orders of $1.2 billion modestly exceeded revenue out of backlog. Approximately $1.2 billion of contracted backlog is scheduled to flow out as revenue during the fourth quarter of 2010; $3.3 billion in 2011, and the balance of $0.4 billion thereafter. The land rig backlog comprised 19 percent and equipment destined for offshore operations comprised 81 percent of the total backlog as of September 30, 2010. Equipment destined for international markets totaled 85 percent of the backlog. The Company experienced relatively minor levels of order cancellations since 2008 (less than four percent), and does not expect additional material cancellation of contracts or abandonment of major projects; however, there can be no assurance that such discontinuance of projects will not occur.

Segment Performance

The Rig Technology segment revenues of $1,650 million in the third quarter of 2010 declined one percent sequentially and declined 17 percent compared to the third quarter of 2009. Segment operating profit was $478 million and operating margins were 29.0 percent during the third quarter. Compared to the second quarter of 2010, revenue declined $22 million and operating profit declined $29 million. Compared to the third quarter of 2009 decremental operating leverage or flow-through (the decrease in operating profit divided by the decrease in revenue) was 28 percent. Despite sequentially lower project revenue, project margins increased slightly as favorable cost experience on completed rig construction projects was applied to remaining estimated costs on ongoing projects, resulting in margins rising above original expectations. Many of these projects were contracted at high prices in 2007 and 2008, and are now being manufactured in much lower cost environments, and benefitting from greater project execution experience within the group. Additionally, downsizing in certain portions of our Rig Technology manufacturing infrastructure in the second half of 2009 contributed to the segment’s overall margin performance in the third quarter of 2010, which was modestly higher than the third quarter of 2009 despite lower volumes. Sequentially, operating margin declined 130 basis points due to mix and slightly lower volumes. Non-backlog revenue improved 17 percent from the second quarter to the third quarter of 2010, led by higher sales of capital spares. Orders for stimulation equipment, top drives, handling and lifting equipment, complete land rig packages for both domestic and international markets, and an order for two deepwater rig drilling equipment packages for Brazil led to $1,175 million in orders booked into the backlog during the third quarter. Revenue out of backlog of $1,157 million declined 8 percent sequentially. Large shale play fracture stimulation jobs in North America are consuming equipment at a more rapid pace owing to the upturn in oilfield activity and higher equipment intensity in these types of jobs. Additionally, demand is shifting to larger diameter coiled tubing strings to stimulate wells and drill out plugs, which led to demand for the Company’s well-intervention equipment in the quarter. Interest in offshore rig construction appears to be ascending, and the Company submitted tenders for up to 28 deepwater rigs for Petrobras to shipyards and drilling contractors during June and July 2010. The Company does not expect to book many orders from this tender until 2011. The orders from this tender will require a high and rising level of local Brazilian content in the construction of new rigs. Customer inquiries for pressure control equipment are also trending higher, and orders for pressure control components, spares, repair and services rose during the third quarter, in response to the Macondo blowout.

The Petroleum Services & Supplies segment generated total sales of $1,089 million in the third quarter of 2010, up five percent from the second quarter of 2010 and up 23 percent from the third quarter of 2009. Operating profit was $164 million or 15.1 percent of sales during the third quarter of 2010, compared to 13.4 percent in the second quarter and 9.8 percent in the third quarter of 2009. Operating leverage or flow-through was 46 percent from the second quarter of 2010 to the third quarter of 2010, and 38 percent from the third quarter of 2009 to the third quarter of 2010. Helped by seasonal recovery out of breakup in Canada, and unconventional shale development targeting oil production, rig counts across North America improved 19 percent sequentially. This lifted the mix of North American sales for the segment to 56 percent for the quarter, compared to 54 percent in the preceding quarter, and drove sequentially higher sales overall. Most products and services within the segment posted single-digit sequential sales gains, with drill pipe sales improving the most, up about 10 percent sequentially due to higher demand for premium drill pipe for shale drilling in the U.S. The backlog of drill pipe orders also increased again sequentially, and coiled tubing sales increased on rising demand from pressure pumping customers in North America. Sales of pumps, bits, downhole tools, pipe inspection and coating services, solids control equipment, and waste management services also posted sequential increases largely due to higher domestic activity.

The Distribution Services segment generated $424 million in revenue during the third quarter of 2010, increasing 16 percent from the second quarter and increasing 39 percent from the third quarter of 2009. Operating profit was $24 million, and operating margin was 5.7 percent of sales, up 210 basis points from the second quarter of 2010. Operating leverage or flow-through was 19 percent sequentially and 14 percent year-over-year for the third quarter. The segment posted 13 percent revenue growth sequentially in the U.S., led by higher sales into unconventional shale plays, higher sales of consumables to outfit newly constructed land rigs, and higher sales into the Gulf of Mexico cleanup effort. Canadian sales increased 37 percent due to the seasonal recovery out of breakup, and International sales increased 11 percent sequentially on higher sales of capital spares and Mono products, partly offset by lower sales in Mexico and Australia.

Outlook

While the credit market downturn, global recession, and lower commodity prices presented challenges to our business in 2009, we believe we are seeing signs of stabilization and recovery in many of our markets. Specifically we are encouraged by higher drilling activity in North America, and steadily higher international drilling activity. Order levels for new drilling rigs declined significantly in 2009 as compared to 2008 due to credit market conditions and softer rig activity, but we were able to secure an order for one Brazil deepwater rig during the second quarter of 2010 and two more during the third quarter of 2010. We also continue to bid up to 28 new offshore floating rigs to be built in Brazil, which we hope will translate into orders in 2011. We expect lower backlogs to lead to modest declines in Rig Technology revenues and margins over the next few quarters before new offshore rig construction projects can translate into higher revenues.

Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution Services segment remains closely tied to the rig count, particularly in North America. If the rig count continues to increase we expect these segments to benefit from higher demand for the services, consumables and capital items they supply. Certain products are seeing higher steel, alloy, resin and fiberglass costs impacting their business while others have seen costs decline. Continuing tight iron ore supplies to the steel mills could adversely affect margins as the year unfolds.

The Company believes it is well positioned to continue to manage through this recession, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders which are expected to continue to generate earnings during the remainder of the year. The Company has a long history of cost-control and downsizing in response to depressed market conditions, and of executing strategic acquisitions during difficult periods. Such a period may present opportunities to the Company to effect new organic growth and acquisition initiatives.

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 third quarter of 2010 and 2009, and the second quarter of 2010 include the following:


							%			%
							3Q10 v			3Q10 v
	3Q10*		2Q10*		3Q09*		2Q10			3Q09
Active Drilling Rigs:
U.S.		1,622		1,508		974		7.6	%		66.5	%
Canada		361		166		187		117.5	%		93.0	%
International		1,110		1,088		969		2.0	%		14.6	%

Worldwide		3,093		2,762		2,130		12.0	%		45.2	%

West Texas Intermediate Crude Prices (per barrel)	$	76.05	$	77.79	$	68.20		(2.2	%)		11.5	%

Natural Gas Prices ($/mmbtu)	$	4.28	$	4.32	$	3.17		(0.9	%)		35.0	%


*		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 September 30, 2010 on a quarterly basis:

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

The worldwide and U.S. quarterly average rig count increased 12% (from 2,762 to 3,093) and 8% (from 1,508 to 1,622), respectively, in the third quarter compared to the second quarter of 2010. The average per barrel price of West Texas Intermediate Crude decreased 2% (from $77.79 per barrel to $76.05 per barrel) and natural gas prices decreased 1% (from $4.32 per mmbtu to $4.28 per mmbtu) in the third quarter compared to the second quarter of 2010.

U.S. rig activity at October 22, 2010 was 1,669 rigs compared to the third quarter average of 1,622 rigs, increasing 3%. The price for West Texas Intermediate Crude was at $81.69 per barrel as of October 22, 2010, increasing 7% from the third quarter 2010 average. The price for natural gas was at $3.33 per mmbtu as of October 22, 2010, decreasing 22% from the third quarter 2010 average.

Results of Operations

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenue:
Rig Technology	$	1,650		$	2,000		$	5,208		$	6,116
Petroleum Services & Supplies		1,089			882			3,045			2,809
Distribution Services		424			306			1,123			1,019
Elimination		(152	)		(101	)		(392	)		(366	)

Total Revenue	$	3,011		$	3,087		$	8,984		$	9,578


Operating Profit:
Rig Technology	$	478		$	577		$	1,564		$	1,717
Petroleum Services & Supplies		164			82			415			195
Distribution Services		24			7			48			42
Unallocated expenses and eliminations		(70	)		(54	)		(204	)		(228	)
Transaction costs		—			(11	)		—			(19	)

Total Operating Profit	$	596		$	601		$	1,823		$	1,707


Operating Profit %:
Rig Technology		29.0	%		28.9	%		30.0	%		28.1	%
Petroleum Services & Supplies		15.1	%		9.3	%		13.6	%		6.9	%
Distribution Services		5.7	%		2.3	%		4.3	%		4.1	%
Total Operating Profit %		19.8	%		19.5	%		20.3	%		17.8	%

Rig Technology

Three Months Ended September 30, 2010 and 2009. Rig Technology revenue in the third quarter of 2010 was $1,650 million, a decrease of $350 million (17.5%) compared to the same period in 2009, primarily due to the decrease of revenue out of backlog of $442 million as total backlog declined 34% to $4.9 billion.

Operating profit from Rig Technology was $478 million for the third quarter ended September 30, 2010, a decrease of $99 million (17.2%) over the same period of 2009. Operating profit percentage increased to 29.0%, up from 28.9% for the same prior year period primarily due to declining costs resulting in estimate revisions on large rig projects and improved manufacturing efficiencies.

Nine Months ended September 30, 2010 and 2009. Rig Technology revenue for the first nine months of 2010 was $5,208 million, a decrease of $908 million (14.9%) compared to the same period in 2009, primarily due to the decrease of revenue out of backlog of $807 million. Non-backlog revenue decreased 7.2% primarily due to lower small capital equipment shipments in 2010.

Operating profit from Rig Technology for the first nine months of 2010 was $1,564 million, a decrease of $153 million (8.9%) over the same period of 2009. Operating profit percentage increased to 30.0%, up from 28.1% for the same prior year period primarily due to declining costs resulting in estimate revisions on large rig projects as well as improved manufacturing efficiencies.

Petroleum Services & Supplies

Three Months Ended September 30, 2010 and 2009. Revenue from Petroleum Services & Supplies was $1,089 million for the third quarter of 2010 compared to $882 million for the third quarter of 2009, an increase of $207 million (23.5%). The increase was primarily attributable to shale plays leading to a strong U.S. market with a 67% increase in rig activity compared to the third quarter of 2009.

Operating profit from Petroleum Services & Supplies was $164 million for the third quarter ended September 30, 2010, an increase of $82 million (100.0%) over the same period of 2009. Operating profit percentage increased to 15.1%, up from 9.3% for the same prior year period primarily due to strong domestic demand fueled by an increase in rig count.

Nine Months ended September 30, 2010 and 2009. Revenue from Petroleum Services & Supplies was $3,045 million for the first nine months of 2010 compared to $2,809 million for the first nine months of 2009, an increase of $236 million (8.4%). The increase was primarily attributable to a higher level of rig activity in the U.S. market.

Operating profit from Petroleum Services & Supplies was $415 million for the first nine months of 2010 compared to $195 million for the same period in 2009, an increase of $220 million (112.8%), and operating profit percentage increased to 13.6% up from 6.9% in the same period of 2009. The first nine months of 2009 results included a $147 million impairment charge on the carrying value of a trade name associated with this segment. In addition, strong domestic demand fueled by an increase in domestic rig count contributed to the increase in operating profit.

Distribution Services

Three Months Ended September 30, 2010 and 2009. Revenue from Distribution Services was $424 million for the third quarter of 2010 compared to $306 million for the third quarter of 2009, an increase of $118 million (38.6%). This increase was primarily attributable to increased U.S. rig count activity and sales into the Gulf of Mexico cleanup effort.

Operating profit from Distribution Services was $24 million for the third quarter ended September 30, 2010, an increase of $17 million (242.9%) over the same period of 2009. Operating profit percentage increased to 5.7%, up from 2.3% for the same prior year period primarily due to increased volume in the quarter.

Nine Months ended September 30, 2010 and 2009. Revenue from Distribution Services was $1,123 million for the first nine months of 2010 compared to $1,019 million for the first nine months of 2009, an increase of $104 million (10.2%). This increase was primarily attributable to increased U.S. rig count activity in general and due to the oil-spill in the Gulf of Mexico, which drove significant emergency project work during the first nine months of 2010.

Operating profit from Distribution Services was $48 million for the first nine months of 2010 compared to $42 million for the same period in 2009, an increase of $6 million (14.3%), and operating profit percentage increased to 4.3% up from 4.1% for the same prior year period primarily due to increased volume in the quarter.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $70 million and $204 million for the three and nine months ended September 30, 2010, respectively, compared to $54 million and $228, respectively, for the same periods in 2009. The increase for the three months comparison is primarily due to higher intercompany profit elimination related to sales between the segments. The decrease in the nine months comparison is primarily due to $46 million of voluntary retirement costs that were taken in the nine months ended September 30, 2009. This was slightly offset by higher intercompany profit elimination related to sales between the segments and an $11 million write-down of certain accounts receivable in Venezuela during the first nine months of 2010.

Interest and financial costs

Interest and financial costs were $12 million and $38 million for the three and nine months ended September 30, 2010, respectively, compared to $14 million and $40 million, respectively, for the same periods in 2009. The decrease in interest and financial costs was due to an overall decrease in debt levels for the three and nine months ended September 30, 2010 compared to the same periods in 2009.

Other income (expense), net

Other income (expense), net were expenses, net of $23 million and $42 million for the three and nine months ended September 30, 2010, respectively, compared to $13 million and $87 million, respectively for the same periods in 2009. The increase for the three months ended September 30, 2010, was mainly due to higher foreign exchange losses during the third quarter of 2010 as a result of exchange rate movements, primarily related to the weakening of the U.S. dollar. The decrease for the nine months ended September 30, 2010 was mainly due to lower foreign exchange losses during the first nine months of 2010 as a result of exchange rate movements, primarily related to the strength of the U.S. dollar in the first half of the year, inclusive of a $27 million charge relating to the devaluation of monetary assets the Company has in Venezuela. The charge was a result of the Venezuela bolivar being officially devalued against the U.S. dollar.

Provision for income taxes

Liquidity and Capital Resources

Overview

At September 30, 2010, the Company had cash and cash equivalents of $3,070 million, and total debt of $870 million. At December 31, 2009, cash and cash equivalents were $2,622 million and total debt was $883 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. Rather than repatriating this cash, the Company may choose to borrow against its credit facility. The Company’s outstanding debt at September 30, 2010 consisted of $200 million of 5.65% Senior Notes due 2012, $200 million of 7.25% Senior Notes due 2011, $150 million of 6.5% Senior Notes due 2011, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $19 million.

There were no borrowings against the Company’s unsecured revolving credit facility, and there were $517 million in outstanding letters of credit issued under the facility, resulting in $1,483 million of funds available under the Company’s unsecured revolving credit facility at September 30, 2010.

The Company had $1,213 million of additional outstanding letters of credit at September 30, 2010, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. The Company was in compliance with all covenants at September 30, 2010.

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


	Nine Months Ended
	September 30,
	2010			2009
Net cash provided by operating activities	$	735		$	1,969
Net cash used in investing activities		(170	)		(319	)
Net cash used in financing activities		(123	)		(25	)

Operating Activities

For the first nine months of 2010, cash provided by operating activities decreased by $1,234 million to $735 million compared to cash provided by operating activities of $1,969 million in the same period of 2009. The primary reason for the decrease is the reduction of customer financing on projects during the first nine months of 2010, as backlog declined $1,532 million from $6,406 million to $4,874 million during this period. Customer financing, as the net of prepayments, billings in excess of costs, less costs in excess of billings, was down approximately $930 million from December 31, 2009. Also, increased business activity in the first nine months of 2010 resulted in higher working capital and lower cash balance as accounts receivable increased $238 million and inventory increased $101 million.

Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations during the first nine months of 2010 primarily through net income of $1,222 million plus depreciation and amortization of $378 million. Dividends from the Company’s unconsolidated affiliate were $17 million less $22 million in equity income from the Company’s unconsolidated affiliate. During the first nine months of 2010, net changes in operating assets and liabilities, net of acquisitions, decreased cash provided by operating activities by $1,277 million.

The Company received $33 million and $94 million in dividends from its unconsolidated affiliate in the first nine months of 2010 and 2009, respectively. The portion included in operating activities in the first nine months of 2010 and 2009 was $17 million and $86 million, respectively. The remainder of $16 million and $8 million was included in investing activities in the first nine months of 2010 and 2009, respectively.

Investing Activities

For the first nine months of 2010, cash used in investing activities was $170 million compared to cash used in investing of $319 million for the same period of 2009. The primary reason for the decrease in cash used in investing activities for the first nine months of 2010 related to a decrease in business acquisitions to approximately $69 million compared to $392 million used in the same period of 2009, offset by $251 million in business divestitures. Capital expenditures decreased to approximately $140 million compared to $186 million used in the same period of 2009. The decreases in cash used in investing activities were offset by an increase in the portion of a dividend received by the Company’s unconsolidated affiliate during the first nine months of 2010 that related to investing activities.

Financing Activities

For the first nine months of 2010, cash used in financing activities was $123 million compared to cash used in financing activities of $25 million for the same period of 2009. The increase in cash used in financing activities for the first nine months of 2010 primarily related to $126 million in cash dividends paid. No such dividends were paid in the same period of 2009. This increase was partially offset by a decrease in payments on debt to approximately $13 million for the first nine months of 2010 compared to $35 million for the same period in 2009. For the first nine months of 2010, the Company used its cash on hand to fund its acquisitions.

The effect of the change in exchange rates on cash flows was a positive $6 million and $24 million for the nine months ended September 30, 2010 and 2009, respectively.

We believe that cash on hand, cash generated from operations and amounts available under the credit facilities and from other sources of debt will be sufficient to fund operations, working capital needs, capital expenditure requirements, dividends and financing obligations.

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

Recently Issued Accounting Standards

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, 2009, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that do impact income. We recorded a foreign exchange loss in our income statement of approximately $29 million in the first nine months of 2010, compared to a $62 million foreign exchange loss in the same period of the prior year. The gains/losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of the current economic environment. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

Some of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. Similarly some of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also 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 as of September 30, 2010 (in millions, except contract rates):


	As of September 30, 2010										December 31,
Functional Currency	2010			2011		2012		Total			2009
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		298			—		—		298			291
Average CAD to USD contract rate		1.0396			—		—		1.0396			1.0418
Fair Value at September 30, 2010 in U.S. dollars		(3	)		—		—		(3	)		2

Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		52			14		—		66			69
Average CAD to USD contract rate		1.0540			1.0466		—		1.0524			1.1109
Fair Value at September 30, 2010 in U.S. dollars		1			—		—		1			4

EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		47			—		—		47			98
Average USD to EUR contract rate		1.2890			—		—		—			1.4356
Fair Value at September 30, 2010 in U.S. dollars		(3	)		—		—		(3	)		—

Sell USD/Buy EUR:
Notional amount to buy (in euros)		15			55		—		70			91
Average USD to EUR contract rate		1.4559			1.2935		—		1.3279			1.3896
Fair Value at September 30, 2010 in U.S. dollars		(1	)		4		—		3			4

KRW Sell EUR/Buy KRW:
Notional amount to buy (in South Korean won)		1,364			273		—		1,637			5,050
Average KRW to EUR contract rate		1,742.53			1,742.53		—		1,742.53			1,639.00
Fair Value at September 30, 2010 in U.S. dollars		—			—		—		—			—


	As of September 30, 2010												December 31,
Functional Currency	2010			2011			2012			Total			2009
Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)		24,658			61,779			3,265			89,702			153,226
Average KRW to USD contract rate		1,021.13			1,083.50			1,118.05			1,066.79			1,046.00
Fair Value at September 30, 2010 in U.S. dollars		(3	)		(3	)		—			(6	)		(18	)

GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		2			—			—			2			11
Average USD to GBP contract rate		1.4605			—			—			1.4605			1.5880
Fair Value at September 30, 2010 in U.S. dollars		—			—			—			—			—

Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		38			26			—			64			2
Average USD to GBP contract rate		1.5227			1.4435			—			1.4903			1.5313
Fair Value at September 30, 2010 in U.S. dollars		2			4			—			6			—

USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		19			4			—			23			44
Average DKK to USD contract rate		5.5160			5.8409			—			5.5672			5.1219
Fair Value at September 30, 2010 in U.S. dollars		—			—			—			—			(1	)

Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		77			107			—			184			382
Average USD to EUR contract rate		1.2981			1.2913			—			1.2942			1.4578
Fair Value at September 30, 2010 in U.S. dollars		4			6			—			10			(7	)

Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		26			4			—			30			76
Average USD to GBP contract rate		1.5562			1.5531			—			1.5558			1.6348
Fair Value at September 30, 2010 in U.S. dollars		—			—			—			—			(2	)

Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		957			396			223			1,576			1,094
Average NOK to USD contract rate		6.2977			6.2345			6.2479			6.2748			6.2269
Fair Value at September 30, 2010 in U.S. dollars		73			20			11			104			67

Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		10			—			—			10			6
Average DKK to USD contract rate		5.8694			—			—			5.8694			5.0009
Fair Value at September 30, 2010 in U.S. dollars		(1	)		—			—			(1	)		—

Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		19			5			—			24			56
Average USD to EUR contract rate		1.3263			1.2780			—			1.3155			1.4324
Fair Value at September 30, 2010 in U.S. dollars		—			—			—			—			—

Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		943			104			5			1,052			408
Average NOK to USD contract rate		6.2398			6.2501			6.2539			6.2409			5.8307
Fair Value at September 30, 2010 in U.S. dollars		(62	)		(6	)		—			(68	)		—

DKK Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		82			—			—			82			—
Average DKK to USD contract rate		5.7872			—			—			5.7872			—
Fair Value at September 30, 2010 in U.S. dollars		1			—			—			1			—

Other Currencies
Fair Value at September 30, 2010 in U.S. dollars		(1	)		(1	)		(1	)		(3	)		—

Total Fair Value at September 30, 2010 in U.S. dollars		7			24			10			41			49

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $357 million and translation exposures totaling $458 million as of September 30, 2010 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 $23 million and the transactional exposures financial market risk sensitive instruments could affect the future fair value by $46 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 September 30, 2010 our long term borrowings consisted of $150 million in 6.5% Senior Notes, $200 million in 7.25% Senior Notes, $200 million in 5.65% Senior Notes, $150 million in 5.5% Senior Notes and $151 million in 6.125% Senior Notes. We occasionally have borrowings under our credit facility, and a portion of these borrowings could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to six months. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.

Item 4. Controls and Procedures

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

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

PART II — OTHER INFORMATION

Item 1A. Risk Factors

As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in Part I, Item 1A “Risk Factors” in our 2009 Annual Report on Form 10-K, as well as the following risk factor:

The recent moratorium on deepwater drilling in the U.S. Gulf of Mexico and its consequences could have a material adverse effect on our business.

A moratorium on deepwater drilling in the U.S. Gulf of Mexico was enacted during the second quarter of 2010 following the Macondo well blowout and oil spill. Even though such moratorium has been recently lifted, any prolonged reduction in oil and natural gas drilling and production activity as a result of such moratorium could result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition.

The following risk factor has been updated from our 2009 Annual Report on Form 10-K:

There are risks associated with our presence in international markets, including political or economic instability, currency restrictions, and trade and economic sanctions.

Approximately 73% of our revenues in 2009 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in Canada, Europe, the Middle East, Africa, Southeast Asia, Latin America and other international markets. Our revenues and operations are subject to the risks normally associated with conducting business in foreign countries, including uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which we operate have adopted policies, or are subject to governmental policies, giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of these policies, we may rely on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationships between us and government-owned petroleum companies.

Our operations outside the United States could also expose us to trade and economic sanctions or other restrictions imposed by the United States or other governments or organizations. The U.S. Department of Justice (“DOJ”), the U.S. Securities and Exchange Commission and other federal agencies and authorities have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of trading sanctions laws, the Foreign Corrupt Practices Act and other federal statutes. Under trading sanctions laws, the DOJ may seek to impose modifications to business practices, including cessation of business activities in sanctioned countries, and modifications to compliance programs, which may increase compliance costs. If any of the risks described above materialize, it could adversely impact our operating results and financial condition.

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. 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 or results of operations.

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: November 5, 2010	By:	/s/ Clay C. Williams
	Clay C. Williams
	Executive Vice President and Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer)

INDEX TO EXHIBITS

(a) Exhibits


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

10.15		First Amendment to National Oilwell Varco Long-Term Incentive Plan. (12)*

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) (13)

10.17		Third Amendment to Executive Agreement, dated as of December 31, 2009, of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (13)

10.18		Second Amendment to Employment Agreement dated as of December 31, 2009 between Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (13)


10.19		Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (13)

10.20		First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (13)

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.

101		The following materials from our Quarterly Report on Form 10-Q for the period ended September 30, 2010 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. (14)


*		Compensatory plan or arrangement for management or others.


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

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

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

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

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

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

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

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

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

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

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

(12)		Filed as Appendix I to our Proxy Statement filed on April 1, 2009.

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

(14)		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.