NOV Inc. - Quarter Report: 2011 September (Form 10-Q)

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)


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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011


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

7909 Parkwood Circle Drive
Houston, Texas
77036-6565
(Address of principal executive offices)

(713) 346-7500
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No 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 (Do not check if a smaller reporting company)		Smaller reporting company o

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

As of November 1, 2011 the registrant had 423,842,605 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,
	2011		2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	3,870	$	3,333
Receivables, net		3,109		2,425
Inventories, net		3,907		3,388
Costs in excess of billings		531		815
Deferred income taxes		282		316
Prepaid and other current assets		339		258

Total current assets		12,038		10,535

Property, plant and equipment, net		1,967		1,840
Deferred income taxes		194		341
Goodwill		5,942		5,790
Intangibles, net		3,995		4,103
Investment in unconsolidated affiliate		371		386
Other assets		37		55

Total assets	$	24,544	$	23,050


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	802	$	628
Accrued liabilities		2,154		2,105
Billings in excess of costs		1,117		511
Current portion of long-term debt and short-term borrowings		2		373
Accrued income taxes		399		468
Deferred income taxes		270		451

Total current liabilities		4,744		4,536

Long-term debt		510		514
Deferred income taxes		1,776		1,885
Other liabilities		275		253

Total liabilities		7,305		7,188


Commitments and contingencies

Stockholders’ equity:
Common stock — par value $.01; 423,817,646 and 421,141,751 shares issued and outstanding at September 30, 2011 and December 31, 2010		4		4
Additional paid-in capital		8,513		8,353
Accumulated other comprehensive income		37		91
Retained earnings		8,580		7,300

Total Company stockholders’ equity		17,134		15,748
Noncontrolling interests		105		114

Total stockholders’ equity		17,239		15,862

Total liabilities and stockholders’ equity	$	24,544	$	23,050

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,
	2011			2010			2011			2010
Revenue	$	3,740		$	3,011		$	10,399		$	8,984
Cost of revenue		2,576			2,066			7,177			6,149

Gross profit		1,164			945			3,222			2,835
Selling, general and administrative		392			349			1,133			1,012

Operating profit		772			596			2,089			1,823
Interest and financial costs		(8	)		(12	)		(31	)		(38	)
Interest income		5			4			13			9
Equity income in unconsolidated affiliate		11			8			34			22
Other income (expense), net		—			(23	)		(26	)		(42	)

Income before income taxes		780			573			2,079			1,774
Provision for income taxes		252			169			667			552

Net income		528			404			1,412			1,222
Net loss attributable to noncontrolling interests		(4	)		—			(8	)		(5	)

Net income attributable to Company	$	532		$	404		$	1,420		$	1,227


Net income attributable to Company per share:
Basic	$	1.26		$	0.97		$	3.37		$	2.94

Diluted	$	1.25		$	0.96		$	3.35		$	2.93


Cash dividends per share	$	0.11		$	0.10		$	0.33		$	0.30


Weighted average shares outstanding:
Basic		422			417			421			417

Diluted		425			419			424			419

See notes to unaudited consolidated financial statements.

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


	Nine Months Ended
	September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	1,412		$	1,222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		413			378
Deferred income taxes		(179	)		(87	)
Equity income in unconsolidated affiliate		(34	)		(22	)
Dividend from unconsolidated affiliate		45			17
Other, net		70			116
Change in operating assets and liabilities, net of acquisitions:
Receivables		(646	)		(238	)
Inventories		(530	)		(101	)
Costs in excess of billings		284			(29	)
Prepaid and other current assets		(78	)		(15	)
Accounts payable		146			1
Billings in excess of costs		606			(797	)
Other assets/liabilities, net		12			290

Net cash provided by operating activities		1,521			735


Cash flows from investing activities:
Purchases of property, plant and equipment		(317	)		(140	)
Business acquisitions, net of cash acquired		(315	)		(69	)
Dividend from unconsolidated affiliate		13			16
Other		43			23

Net cash used in investing activities		(576	)		(170	)


Cash flows from financing activities:
Borrowings against lines of credit and other debt		—			2
Repayments on debt		(374	)		(13	)
Cash dividends paid		(140	)		(126	)

Other		116			14

Net cash used in financing activities		(398	)		(123	)
Effect of exchange rates on cash		(10	)		6

Increase in cash and cash equivalents		537			448
Cash and cash equivalents, beginning of period		3,333			2,622

Cash and cash equivalents, end of period	$	3,870		$	3,070


Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	34		$	38
Income taxes	$	805		$	344

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 2010 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, 2011 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,
	2011		2010
Raw materials and supplies	$	823	$	661
Work in process		833		953
Finished goods and purchased products		2,251		1,774

Total	$	3,907	$	3,388

3. Accrued Liabilities

Accrued liabilities consist of (in millions):


	September 30,		December 31,
	2011		2010
Customer prepayments and billings	$	638	$	387
Accrued purchase orders		405		597
Compensation		358		403
Warranty		232		215
Taxes (non income)		89		93
Insurance		70		49
Fair value of derivatives		47		22
Interest		8		11
Other		307		328

Total	$	2,154	$	2,105

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, 2010	$	215

Net provisions for warranties issued during the year		44
Amounts incurred		(28	)
Foreign currency translation and other		1

Balance at September 30, 2011	$	232

4. Costs and Estimated Earnings on Uncompleted Contracts

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


	September 30,			December 31,
	2011			2010
Costs incurred on uncompleted contracts	$	7,570		$	6,676
Estimated earnings		5,280			4,665

		12,850			11,341
Less: Billings to date		13,436			11,037

	$	(586	)	$	304


Costs and estimated earnings in excess of billings on uncompleted contracts	$	531		$	815
Billings in excess of costs and estimated earnings on uncompleted contracts		(1,117	)		(511	)

	$	(586	)	$	304

5. Comprehensive Income

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011			2010		2011			2010
Net income	$	528		$	404	$	1,412		$	1,222
Currency translation adjustments		(117	)		92		(25	)		16
Changes in derivative financial instruments, net of tax		(71	)		84		(29	)		3

Comprehensive income		340			580		1,358			1,241
Comprehensive loss attributable to noncontrolling interest		(4	)		—		(8	)		(5	)

Comprehensive income attributable to Company	$	344		$	580	$	1,366		$	1,246

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, 2011, a majority of these local currencies weakened against the U.S. dollar resulting in a net decrease to Other Comprehensive Income of $117 million upon the translation of their financial statements from their local currency to the U.S. dollar. For the nine months ended September 30, 2011, foreign exchange movements have been insignificant with the majority of the local currencies strengthening slightly, offset by a slightly weaker Canadian dollar, resulting in a net decrease to Other Comprehensive Income of $25 million.

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 a decrease in Other Comprehensive Income of $71 million (net of tax of $28 million) and $29 million (net of tax of $12 million) for the three and nine months ended September 30, 2011, respectively.

6. Business Segments

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Revenue:
Rig Technology	$	1,970		$	1,650		$	5,472		$	5,208
Petroleum Services & Supplies		1,460			1,089			4,084			3,045
Distribution Services		480			424			1,313			1,123
Elimination		(170	)		(152	)		(470	)		(392	)

Total Revenue	$	3,740		$	3,011		$	10,399		$	8,984


Operating Profit:
Rig Technology	$	523		$	478		$	1,456		$	1,564
Petroleum Services & Supplies		298			164			777			415
Distribution Services		37			24			90			48
Unallocated expenses and eliminations		(86	)		(70	)		(234	)		(204	)

Total Operating Profit	$	772		$	596		$	2,089		$	1,823


Operating Profit %:
Rig Technology		26.5	%		29.0	%		26.6	%		30.0	%
Petroleum Services & Supplies		20.4	%		15.1	%		19.0	%		13.6	%
Distribution Services		7.7	%		5.7	%		6.9	%		4.3	%
Total Operating Profit %		20.6	%		19.8	%		20.1	%		20.3	%

The Company had revenues of 13% and 12% of total revenue from one of its customers for the three and nine months ended September 30, 2011, respectively, and revenues of 14% and 17% of total revenue from one of its customers for the three and nine months ended September 30, 2010, 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,
	2011		2010
Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011	$	—	$	150

Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011		—		201

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

Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012		150		151

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

Other		11		34

Total debt		512		887
Less current portion		2		373

Long-term debt	$	510	$	514

Senior Notes

On March 15, 2011, the Company repaid $150 million of its 6.5% unsecured Senior Notes using available cash balances and on May 1, 2011, the Company repaid $200 million of its 7.25% unsecured Senior Notes using available cash balances. The remaining Senior Notes contain reporting covenants, and the Company was in compliance at September 30, 2011.

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, 2011 there were no borrowings against the remaining credit facility, and there were $731 million in outstanding letters of credit issued under this facility, resulting in $1,269 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% subject to a ratings-based grid, or the prime rate. The credit facility contains a financial covenant regarding maximum debt to capitalization and the Company was in compliance at September 30, 2011.

The Company also had $1,773 million of additional outstanding letters of credit at September 30, 2011, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds.

8. Tax

The effective tax rate for the three and nine months ended September 30, 2011 was 32.3% and 32.1%, respectively, compared to 29.5% and 31.1% for the same period in 2010. The effective tax rate was positively impacted in the period by the effect of tax rate reductions on timing differences in foreign jurisdictions, an increase in the benefit of the manufacturing deduction as a result of increasing income in the U.S., plus the recognition of reduced tax expense related to prior periods. This was offset by additional current and prior period taxes on foreign dividends. The impact of these prior period discrete items is not material to any individual prior 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,
	2011			2010			2011			2010
Federal income tax at U.S. federal statutory rate	$	273		$	201		$	728		$	621
Foreign income tax rate differential		(29	)		(28	)		(94	)		(86	)
State income tax, net of federal benefit		6			3			17			10
Nondeductible expenses		9			6			33			30
Tax benefit of manufacturing deduction		(14	)		(8	)		(26	)		(14	)
Foreign dividends, net of foreign tax credits		33			2			43			9
Tax rate change on temporary differences		(5	)		—			(18	)		—
Other		(21	)		(7	)		(16	)		(18	)

Provision for income taxes	$	252		$	169		$	667		$	552

The balance of unrecognized tax benefits at September 30, 2011 was $117 million. The Company recognized no material changes in the balance of unrecognized tax benefits for the three and nine months ended September 30, 2011.

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 2007 and outside the U.S. for tax years ending after 2004.

The Company does not anticipate that its total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within 12 months of this reporting date.

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

9. Stock-Based Compensation

The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights. The number of shares authorized under the Plan is 25.5 million. As of September 30, 2011, 5,702,740 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 stock-based compensation arrangements under the Plan was $19 million and $55 million for the three and nine months ended September 30, 2011, respectively, and $17 million and $50 million for the three and nine months ended September 30, 2010, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $6 million and $17 million for the three and nine months ended September 30, 2011, respectively, and $5 million and $15 million for the three and nine months ended September 30, 2010, respectively.

During the nine months ended September 30, 2011, the Company granted 2,277,946 stock options and 374,425 shares of restricted stock and restricted stock units, which includes 131,300 performance-based restricted stock awards. Out of the total number of stock options granted, 2,255,322 were granted February 22, 2011 with an exercise price of $79.80. These options generally vest over a three-year period from the grant date. The remaining 22,624 options were granted May 19, 2011 to the non-employee members of the board of directors at an exercise price of $67.93. These options generally vest over a three-year period from the grant date. Out of the total number of restricted stock and restricted stock units, 234,620 were granted February 22, 2011 and vest on the third anniversary of the date of grant. On May 19, 2011, 8,505 restricted stock awards were granted to the non-employee members of the board of directors. These restricted stock awards vest in equal thirds over three years on the anniversary of the grant date. The performance-based restricted stock awards were granted February 22, 2011. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s operating income growth, measured on a percentage basis, from January 1, 2011 through December 31, 2013 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, 2011, the Company has determined that its financial assets of $42 million and liabilities of $55 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At September 30, 2011, the net fair value of the Company’s foreign currency forward contracts totaled a liability of $13 million.

As of September 30, 2011, 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.

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 (in millions):


	Currency Denomination
	September 30,		December 31,
Foreign Currency	2011		2010
British Pound Sterling	£	6	£	4
Danish Krone	DKK	65	DKK	31
Euro	€	304	€	122
Norwegian Krone	NOK	5,527	NOK	4,983
U.S. Dollar	$	389	$	247
Japanese Yen	¥	122	¥	-
Singapore Dollar	SGD	3	SGD	-
Swedish Krone	SEK	2	SEK	-

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.

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 (in millions):


	Currency Denomination
	September 30,		December 31,
Foreign Currency	2011		2010
U.S. Dollar	$	—	$	1

Non-designated Hedging Strategy

For derivative instruments that are non-designated, the gain or loss on the derivative instrument subject to the hedged risk (i.e. nonfunctional currency monetary accounts) are recognized in other income (expense), net in current earnings.

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

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


	Currency Denomination
	September 30,		December 31,
Foreign Currency	2011		2010
British Pound Sterling	£	8	£	8
Danish Krone	DKK	120	DKK	115
Euro	€	97	€	97
Norwegian Krone	NOK	1,544	NOK	1,442
U.S. Dollar	$	561	$	328
Swedish Krone	SEK	19	SEK	—
Russian Ruble	RUB	683	RUB	780
Brazilian Real	BRL	—	BRL	—
Japanese Yen	¥	351	¥	—
Singapore Dollar	SGD	4	SGD	—

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


	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet	September 30,		December 31,		Balance Sheet	September 30,		December 31,
	Location	2011		2010		Location	2011		2010
Derivatives designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	23	$	28	Accrued liabilities	$	37	$	12
Foreign exchange contracts	Other Assets		5		12	Other Liabilities		8		1


Total derivatives designated as hedging instruments under ASC Topic 815		$	28	$	40		$	45	$	13


Derivatives not designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	14	$	7	Accrued liabilities	$	10	$	10


Total derivatives not designated as hedging instruments under ASC Topic 815		$	14	$	7		$	10	$	10


Total derivatives		$	42	$	47		$	55	$	23

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,

2011

2010

2011

2010

2011

2010

Revenue

Foreign exchange contracts

(14

)

Cost of revenue

(26

)

Other income (expense), net

Total

(14

)

(20

)

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,

2011

2010

2011

2010

Foreign exchange contracts

Revenue

—

)

Firm commitments

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,

2011

2010

Foreign exchange contracts

Other income (expense), net

(20

)

Total

(20

)


(a)		The Company expects that ($18) million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow.

(b)		The amount of gain recognized in income represents $11 million and $5 million related to the ineffective portion of the hedging relationships for the nine months ended September 30, 2011 and 2010, respectively, and $13 million and $8 million related to the amount excluded from the assessment of the hedge effectiveness for the nine months ended September 30, 2011 and 2010, 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,
	2011		2010		2011		2010
Numerator:
Net income attributable to Company	$	532	$	404	$	1,420	$	1,227

Denominator:
Basic—weighted average common shares outstanding		422		417		421		417
Dilutive effect of employee stock options and other unvested stock awards		3		2		3		2

Diluted outstanding shares		425		419		424		419

Net income attributable to Company per share:
Basic	$	1.26	$	0.97	$	3.37	$	2.94

Diluted	$	1.25	$	0.96	$	3.35	$	2.93

Cash dividends per share	$	0.11	$	0.10	$	0.33	$	0.30

In addition, the Company had stock options outstanding that were anti-dilutive totaling 2 million and 3 million shares for the three and nine months ended September 30, 2011, respectively, and 6 million shares for each of the three and nine months ended September 30, 2010, respectively.

12. Cash Dividends

On August 17, 2011 the Company’s Board of Directors approved a cash dividend of $0.11 per share. The cash dividend was paid on September 23, 2011 to each stockholder of record on September 9, 2011. Cash dividends aggregated $47 million and $140 million for the three and nine months ended September 30, 2011, respectively, and $42 million and $126 million for the three and nine months ended September 30, 2010, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.

13. Subsequent Event

On October 5, 2011, the Company completed its previously announced acquisition of Ameron International Corporation (“Ameron”) for approximately $777 million. Under the agreement, Ameron’s stockholders received $85.00 per share in cash in return for each of the approximately 9.1 million shares outstanding.

14. Recently Issued Accounting Standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs” (“ASU No. 2011-04”), which provides guidance about how fair value should be applied where it is already required or permitted under U.S. GAAP. The ASU does not extend the use of fair value or require additional fair value measurements, but rather provides explanations about how to measure fair value. ASU No. 2011-04 requires prospective application and will be effective for interim and annual reporting periods beginning after December 15, 2011. The Company is currently assessing the impact ASU No. 2011-04 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.

In June 2011, the FASB issued ASU No. 2011-05 “Presentation of Comprehensive Income” (“ASU No. 2011-05”), which eliminates the option to present components of other comprehensive income as part of the statement of changes in equity and requires that all nonowner changes in equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU No. 2011-05 requires retrospective application and will be effective for interim and annual reporting periods beginning after December 15, 2011. The Company is currently assessing the impact ASU No. 2011-05 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.

In September 2011, the FASB issued ASU No. 2011-8 “Intangibles-Goodwill and Other” (“ASU No. 2011-08”), which amends its guidance on the testing of goodwill for impairment allowing entities to perform a qualitative assessment on goodwill impairment to determine whether it is more likely than not (defined as having a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. This guidance is effective for goodwill impairment tests performed in interim and annual periods for fiscal years beginning after December 15, 2011, with early adoption permitted. The Company is currently assessing the impact ASU No. 2011-08 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.

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

Introduction

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

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

Rig Technology

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

Petroleum Services & Supplies

Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service 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, and casing; 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 additional operations in the United States, Canada, the United Kingdom, Brazil, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, and the United Arab Emirates.

Distribution Services

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

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2010, 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 $532 million in net income attributable to Company, or $1.25 per fully diluted share, on $3.74 billion in revenue in its third quarter ended September 30, 2011. Compared to the second quarter of 2011 revenue increased six percent and net income attributable to Company increased 11 percent. Compared to the third quarter of 2010 revenue increased 24 percent and net income attributable to Company increased 32 percent.

The third quarter of 2011 included pre-tax transaction charges of $6 million, the second quarter of 2011 included pre-tax transaction charges of $4 million, and the third quarter of 2010 included pre-tax transaction charges of $2 million. Excluding transaction charges from all periods, third quarter 2011 earnings were $1.26 per fully diluted share, compared to $1.14 per fully diluted share last quarter and $0.97 per fully diluted share a year ago. Operating profit excluding transaction charges was $778 million or 20.8 percent of sales in the third quarter of 2011, compared to $712 million or 20.3 percent of sales last quarter, and $598 million or 19.9 percent of sales a year ago.

Revenues and operating profit increased both sequentially and year-over-year for all three of the Company’s segments. The Rig Technology segment received a record level of orders for capital equipment totaling over $3.9 billion, including the largest order ever in the history of the Company, during the third quarter of 2011. Demand for offshore rigs and well stimulation equipment were particularly strong. The Petroleum Services & Supplies segment generated record quarterly revenues, and pushed operating margins above the 20 percent level, due to rising rig activity associated with unconventional plays in the U.S., and seasonal increases in activity in Canada. Distribution Services posted its third highest quarterly sales ever, at very strong operating margins of 7.7 percent.

Oil & Gas Equipment and Services Market

Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks responded vigorously through 2009, but economic growth in many developed economies continues to be weak. As a result asset and commodity prices, including oil and gas prices, declined in 2009. After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to average $43 per barrel (West Texas Intermediate Crude Prices) during the first quarter of 2009, but recovered to $76 per barrel range by the end of 2009 and increased to average about $90 per barrel by the third quarter of 2011, partly due to unrest in the Middle East. North American gas prices declined to $3.17 per mmbtu in the third quarter of 2009 but recovered to average $4.12 per mmbtu in the third quarter of 2011. 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. However, higher commodity prices led to a recovery in drilling activity through the past two years.

The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a low of 876 in June, 2009. U.S. rig count has since increased to 2,013 in late October 2011, and averaged 1,945 rigs during the third quarter of 2011. 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 per mmbtu and, more recently, as operators began to drill unconventional shale plays targeting oil, rather than gas. Oil drilling has risen to over 50 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 1,174 in September 2011.

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 since third quarter 2009 lows. The Company’s Rig Technology segment increased revenues and margins through 2009 owing to its high level of contracted backlog which it executed on very well since the economic downturn. In the first half of 2010 the segment posted operating margins of more than 30 percent, but saw its margins decline modestly since then, due to a declining mix of higher margin sales made in the 2007-2008 timeframe, and a rising mix of more recent sales made at lower pricing.

The economic decline beginning in late 2008 followed an extended period of high drilling activity which fueled strong demand for oilfield services between 2003 and 2008. Incremental drilling activity through the upswing shifted toward harsh environments, employing increasingly sophisticated technology to find and produce reserves. Higher utilization of drilling rigs tested the capability of the world’s fleet of rigs, much of which is old and of limited capability. Technology has advanced significantly since most of the existing rig fleet was built. The industry invested little during the late 1980’s and 1990’s on new drilling equipment, but drilling technology progressed steadily nonetheless, as the Company and its competitors continued to invest in new and better ways of drilling. As a consequence, the safety, reliability, and efficiency of new, modern rigs surpass the performance of most of the older rigs at work today. Drilling rigs are now being pushed to drill deeper wells, more complex wells, highly deviated wells and horizontal wells, tasks which require larger rigs with more capabilities. The drilling process effectively consumes the mechanical components of a rig, which wear out and need periodic repair or replacement. This process was accelerated by very high rig utilization and wellbore complexity. Drilling consumes rigs; more complex and challenging drilling consumes rigs faster.

The industry responded by launching many new rig construction projects since 2005, to 1.) retool the existing fleet of jackup rigs (according to Offshore Data Services, 70 percent of the existing 476 jackup rigs are more than 25 years old); 2.) replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and 3.) build out additional deepwater floating drilling rigs, including semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet.

As a result of these trends the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at March 31, 2005, to $11.8 billion at September 30, 2008. The credit crisis and slowing drilling activity led to lower orders in 2009, causing the backlog to decline to $4.9 billion by June 30, 2010. Orders have risen sharply since then, lifting the segment’s backlog to $10.3 billion as of September 30, 2011. Orders totaled $3.9 billion for the third quarter of 2011, more than double the revenue out of backlog, and representing a record level for the Rig Technology segment’s capital equipment sales. Approximately $1.5 billion of these orders are scheduled to flow out as revenue during the fourth quarter of 2011; $6.4 billion in 2012, and the balance thereafter. The land rig backlog comprised 15 percent and equipment destined for offshore operations comprised 85 percent of the total backlog as of September 30, 2011. Equipment destined for international markets totaled 87 percent of the backlog.

Segment Performance

The Rig Technology segment revenues of $1,970 million in the third quarter of 2011 increased four percent sequentially and increased 19 percent compared to the third quarter of 2010. Segment operating profit was $523 million and operating margins were 26.5 percent during the third quarter. Compared to the second quarter of 2011 incremental operating leverage or flow-through (the increase in operating profit divided by the increase in revenue) was 12 percent, and compared to the third quarter of 2010 incremental operating leverage was 14 percent. The reason for the lower than average incremental leverage was a mix shift away from higher margin offshore projects won a few years ago, toward lower-priced offshore work, and more land business, which typically carries lower margins. Many offshore projects were contracted at high prices in 2007 and 2008 and subsequently manufactured in much lower cost environments in 2009 and 2010. Year-over-year operating margin declined 250 basis points, and sequentially margins declined 60 basis points, due to this mix effect. Sequentially, revenue out of backlog improved one percent and aftermarket spares and services revenues improved 18 percent, helped partly by the Company’s acquisition of a drilling equipment repair business in the Far East during the third quarter. Compared to the third quarter of 2010 revenue out of backlog grew 22 percent and aftermarket spares and services revenues improved 31 percent. An order for seven deepwater drillships to be built for Petrobras in Brazil; orders for seven additional floating rigs and 14 jackup rig packages; and strong demand for well stimulation, intervention and pressure pumping equipment contributed to the segment’s record order level during the third quarter of 2011.

The Petroleum Services & Supplies segment generated total sales of $1,460 million in the third quarter of 2011, up seven percent from the second quarter of 2011 and up 34 percent from the third quarter of 2010. Operating profit was $298 million or 20.4 percent of sales for the third quarter, compared to 18.3 percent in the second quarter of 2011 and 15.1 percent in the third quarter of 2010. Operating leverage or flow-through was 49 percent from the second quarter of 2011, and 36 percent from the third quarter of 2010 to the third quarter of 2011. High sequential flowthroughs and margins were due to the impact of the seasonal turnaround out of breakup in Canada, continued favorable pricing within most product lines within the segment, and improved profitability and volume within the segment’s downhole tools product line. Favorable trends were partly offset by higher startup costs for a number of new locations. Operations in North Africa and the Middle East continue to face low levels of activity due to continuing unrest in that region.

The Distribution Services segment generated $480 million in revenue during the third quarter of 2011, up 13 percent from both sequential and prior year quarters. Operating profit was $37 million, and operating margin was 7.7 percent of sales, up from both the second quarter of 2011 as well as the third quarter of 2010. Operating leverage or flow-through was 21 percent sequentially and 23 percent year-over-year. The segment posted sharply improved results in Canada due to seasonal improvements, as well as good growth and higher margins in the U.S. due to increasing drilling activity associated with unconventional shale plays. International operations posted increasing revenues but margins declined slightly on mix. The segment’s Mono business posted higher sales of artificial lift products into international markets during the third quarter.

Outlook

Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher drilling activity in North America and slowly improving international drilling activity. Order levels for new drilling rigs has rebounded sharply, and the Rig Technology segment continues to experience a high level of interest in new capital equipment. Rig dayrates appear to have stabilized for certain classes of newer technology rigs, and appear to be trending higher for deepwater offshore rigs. We expect lower pricing in our backlog to lead to modest declines in Rig Technology margins over the next few quarters, until recently won offshore rig construction orders begin to generate revenues at higher margins.

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. Many products are beginning to see higher steel, alloy, resin and fiberglass costs impact their business, and are attempting to raise prices to offset rising costs. Continuing tight iron ore supplies to the steel mills could adversely affect margins as the year unfolds.

The Company believes it is well positioned, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders which are expected to continue to generate earnings during the remainder of 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, and we remain hopeful that a downturn will generate new opportunities.

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

Operating Environment Overview

The Company’s results are dependent on, among other things, the level of worldwide oil and gas drilling, well remediation activity, the prices of crude oil and natural gas, capital spending by other oilfield service companies and drilling contractors, and worldwide oil and gas inventory levels. Key industry indicators for the third quarter of 2011 and 2010, and the second quarter of 2011 include the following:


							%			%
							3Q11 v			3Q11 v
	3Q11*		2Q11*		3Q10*		2Q11			3Q10
Active Drilling Rigs:
U.S.		1,945		1,829		1,622		6.3	%		19.9	%
Canada		443		188		361		135.6	%		22.7	%
International		1,169		1,147		1,110		1.9	%		5.3	%

Worldwide		3,557		3,164		3,093		12.4	%		15.0	%

West Texas Intermediate	$	89.82	$	102.23	$	76.05		(12.1	%)		18.1	%
Crude Prices (per barrel)

Natural Gas Prices ($/mmbtu)	$	4.12	$	4.36	$	4.28		(5.5	%)		(3.7	%)


*		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, 2011 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 3,164 to 3,557) and 6% (from 1,829 to 1,945), in the third quarter of 2011 compared to the second quarter of 2011. The average per barrel price of West Texas Intermediate Crude decreased 12% (from $102.23 per barrel to $89.82 per barrel) and natural gas prices decreased 6% (from $4.36 per mmbtu to $4.12 per mmbtu) in the third quarter of 2011 compared to the second quarter of 2011.

U.S. rig activity at October 21, 2011 was 2,013 rigs compared to the third quarter average of 1,945 rigs, increasing 3%. The price for West Texas Intermediate Crude was at $87.40 per barrel as of October 21, 2011, decreasing 3% from the third quarter average. The price for natural gas was at $3.63 per mmbtu as of October 21, 2011, decreasing 12% from the third quarter average.

Results of Operations

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Revenue:
Rig Technology	$	1,970		$	1,650		$	5,472		$	5,208
Petroleum Services & Supplies		1,460			1,089			4,084			3,045
Distribution Services		480			424			1,313			1,123
Elimination		(170	)		(152	)		(470	)		(392	)

Total Revenue	$	3,740		$	3,011		$	10,399		$	8,984


Operating Profit:
Rig Technology	$	523		$	478		$	1,456		$	1,564
Petroleum Services & Supplies		298			164			777			415
Distribution Services		37			24			90			48
Unallocated expenses and eliminations		(86	)		(70	)		(234	)		(204	)

Total Operating Profit	$	772		$	596		$	2,089		$	1,823


Operating Profit %:
Rig Technology		26.5	%		29.0	%		26.6	%		30.0	%
Petroleum Services & Supplies		20.4	%		15.1	%		19.0	%		13.6	%
Distribution Services		7.7	%		5.7	%		6.9	%		4.3	%
Total Operating Profit %		20.6	%		19.8	%		20.1	%		20.3	%

Rig Technology

Three Months Ended September 30, 2011 and 2010. Rig Technology revenue in the third quarter of 2011 was $1,970 million, an increase of $320 million (19.4%) compared to the same period in 2010. Backlog rose to $10.3 billion, up 111% from the same period last year. Backlog and non-backlog revenue increased 22% and 14%, respectively, from the prior year period reflecting increased rig construction activity associated with offshore rigs and active shale plays in the U.S. as well as increased demand for aftermarket spare parts and services.

Operating profit from Rig Technology was $523 million for the third quarter ended September 30, 2011, an increase of $45 million (9.4%) over the same period of 2010. Operating profit percentage decreased to 26.5%, from 29.0% for the same prior year period primarily due to a decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008.

Nine Months Ended September 30, 2011 and 2010. Rig Technology revenue for the first nine months of 2011 was $5,472 million, an increase of $264 million (5.1%) compared to the same period in 2010. Revenue out of backlog remained relatively flat while revenue out of non-backlog increased 20% primarily due to the increased demand for aftermarket spare parts and services.

Operating profit from Rig Technology was $1,456 million for the first nine months of 2011, a decrease of $108 million (6.9%) over the same period of 2010. Operating profit percentage decreased to 26.6%, from 30.0% for the same prior year period primarily due to a decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. This decrease in margins was partially offset by the increase in demand for aftermarket spare parts and services.

Petroleum Services & Supplies

Three Months Ended September 30, 2011 and 2010. Revenue from Petroleum Services & Supplies was $1,460 million for the third quarter of 2011 compared to $1,089 million for the third quarter of 2010, an increase of $371 million (34.1%). The increase was primarily attributable to shale plays leading to a strong North American market with a 19.9% increase in U.S. rig activity and a 22.7% increase in Canada rig activity compared to the third quarter of 2010.

Operating profit from Petroleum Services & Supplies was $298 million for the third quarter ended September 30, 2011, an increase of $134 million (81.7%) over the same period of 2010. Operating profit percentage increased to 20.4%, up from 15.1% for the same prior year period primarily due to favorable pricing as well as increased volume with a strong North American demand fueled by an increase in rig count.

Nine Months Ended September 30, 2011 and 2010. Revenue from Petroleum Services & Supplies was $4,084 million for the first nine months of 2011 compared to $3,045 million for the first nine months of 2010, an increase of $1,039 million (34.1%). The increase was primarily attributable to shale plays leading to a strong North American market with an 22.7% increase in U.S. rig activity and a 22.3% increase in Canada rig activity compared to the first nine months of 2010.

Operating profit from Petroleum Services & Supplies was $777 million for the nine months ended September 30, 2011, an increase of $362 million (87.2%) over the same period of 2010. Operating profit percentage increased to 19.0%, up from 13.6% for the same prior year period primarily due to favorable pricing as well as increased volume with a strong North American demand fueled by an increase in rig count. The increase was offset by the write-down, in the first quarter, of Libyan assets of $15 million, mostly related to accounts receivable affected by sanctions enacted during the quarter along with the write off of certain inventory and fixed assets in the country. The Company’s Rig Technology and Distribution Services segments incurred $2 million of such asset write-downs during the first quarter for a total of $17 million in Libyan asset write-downs incurred by the Company.

Distribution Services

Three Months Ended September 30, 2011 and 2010. Revenue from Distribution Services was $480 million for the third quarter of 2011 compared to $424 million for the third quarter of 2010, an increase of $56 million (13.2%). This increase was primarily attributable to increased U.S. rig count activity.

Operating profit from Distribution Services was $37 million for the third quarter ended September 30, 2011, an increase of $13 million (54.2%) over the same period of 2010. Operating profit percentage increased to 7.7%, up from 5.7% for the same prior year period primarily due to better pricing related to strong demand fueled by an increase in U.S. rig count activity.

Nine Months Ended September 30, 2011 and 2010. Revenue from Distribution Services was $1,313 million for the first nine months of 2011 compared to $1,123 million for the first nine months of 2010, an increase of $190 million (16.9%). This increase was primarily attributable to increased U.S. rig count activity.

Operating profit from Distribution Services was $90 million for the first nine months of 2011 compared to $48 million for the same period in 2010, an increase of $42 million (87.5%). Operating profit percentage increased to 6.9%, up from 4.3% for the same prior year period primarily due to greater cost efficiencies and better pricing related to strong demand fueled by an increase in U.S. rig count activity.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $86 million and $234 million for the three and nine months ended September 30, 2011, respectively, compared to $70 million and $204 million, respectively, for the same periods in 2010. This increase is primarily due to higher legal costs associated with acquisitions and intersegment eliminations.

Interest and financial costs

Interest and financial costs were $8 million and $31 million for the three and nine months ended September 30, 2011, respectively, compared to $12 million and $38 million, respectively, for the same periods in 2010. 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, 2011 compared to the same periods in 2010.

Other income (expense), net

Other income (expense), net were expenses of nil and $26 million for the three and nine months ended September 30, 2011, respectively, compared to $23 million and $42 million, respectively for the same periods in 2010. The increase for the three and nine months ended September 30, 2011, was mainly due to lower foreign exchange losses during 2011 as a result of exchange rate movements, primarily related to the strengthening of the U.S. dollar.

Provision for income taxes

Non-GAAP Financial Measures and Reconciliations

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

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

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


	Three Months Ended						Nine Months Ended
	September 30,				June 30,		September 30,
	2011		2010		2011		2011		2010
Reconciliation of operating profit:
GAAP operating profit	$	772	$	596	$	708	$	2,089	$	1,823
Other costs:
Transaction costs		6		2		4		12		6
Libya asset write-down		—		—		—		17		—
Devaluation costs		—		—		—		—		11

Operating profit excluding other costs	$	778	$	598	$	712	$	2,118	$	1,840


	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
	2011			2010			2011			2011			2010
Reconciliation of operating profit %:
GAAP operating profit %		20.6	%		19.8	%		20.2	%		20.1	%		20.3	%
Other costs %		0.2	%		0.1	%		0.1	%		0.3	%		0.2	%

Operating profit % excluding other costs		20.8	%		19.9	%		20.3	%		20.4	%		20.5	%


	Three Months Ended						Nine Months Ended
	September 30,				June 30,		September 30,
	2011		2010		2011		2011		2010
Reconciliation of diluted earnings per share:
GAAP earnings per share	$	1.25	$	0.96	$	1.13	$	3.35	$	2.93
Other costs		0.01		0.01		0.01		0.06		0.11

Earnings per share excluding other costs	$	1.26	$	0.97	$	1.14	$	3.41	$	3.04

Liquidity and Capital Resources

Overview

At September 30, 2011, the Company had cash and cash equivalents of $3,870 million, and total debt of $512 million. At December 31, 2010, cash and cash equivalents were $3,333 million and total debt was $887 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, 2011 consisted of $200 million of 5.65% Senior Notes due 2012, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $11 million.

There were no borrowings against the Company’s unsecured revolving credit facility, and there were $731 million in outstanding letters of credit issued under the facility, resulting in $1,269 million of funds available under the Company’s unsecured revolving credit facility at September 30, 2011.

The Company had $1,773 million of additional outstanding letters of credit at September 30, 2011, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The 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, 2011.

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,
	2011			2010
Net cash provided by operating activities	$	1,521		$	735
Net cash used in investing activities		(576	)		(170	)
Net cash used in financing activities		(398	)		(123	)

Operating Activities

For the first nine months of 2011, cash provided by operating activities was $1,521 million, an increase of $786 million compared to cash provided by operating activities of $735 million in the same period of 2010. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $1,412 million plus non-cash charges of $234 million and $45 million of the dividend received from the Company’s unconsolidated affiliate less $34 million in equity income from the Company’s unconsolidated affiliate.

Net changes in operating assets and liabilities, net of acquisitions, used $206 million for the first nine months of 2011 compared to $889 million used in the same period in 2010. Due to an increase in market activity during the first nine months of 2011 compared to the same period in 2010, revenue and backlog (milestone invoicing) increased which is reflected in increased accounts receivable coupled with a buildup in inventory, partially offset by a decrease in costs in excess of billings and an increase in billings in excess of costs. Incentive compensation and tax payments contributed to the reduction in other assets/liabilities, net for the first nine months of 2011 compared to the same period in 2010.

The Company received $58 million and $33 million in dividends from its unconsolidated affiliate in 2011 and 2010, respectively. The portion included in operating activities in 2011 and 2010 was $45 million and $17 million, respectively. The remaining $13 million and $16 million were included in investing activities in 2011 and 2010, respectively.

Investing Activities

For the first nine months of 2011, cash used in investing activities was $576 million compared to cash used in investing activities of $170 million for the same period of 2010. The primary reason for the increase related to the increase in cash paid for acquisitions to approximately $315 million during the first nine months of 2011 compared to $69 million during the same period of 2010. In addition, capital expenditures increased to approximately $317 million as capital was spent on several U.S. and international expansion projects during the first nine months of 2011 compared to $140 million used in the same period of 2010.

Financing Activities

For the first nine months of 2011, cash used in financing activities was $398 million compared to cash used in financing activities of $123 million for the same period of 2010. The $275 million increase in cash used in financing activities for the first nine months of 2011 primarily related to the repayment of $150 million in Senior Notes that were due late in the first quarter, $200 million in Senior Notes that were due in the second quarter as well as $20 million in other current borrowings. The Company increased its dividend slightly to $140 million for the first nine months of 2011 compared to $126 million for the same period of 2010. The increase in cash used was partially offset by $71 million in proceeds from stock options exercised during the first nine months of 2011 compared to $8 million in proceeds from stock options exercised during the same period in 2010. For the first nine months of 2011, the Company used its cash on hand to fund its acquisitions.

The effect of the change in exchange rates on cash flows was a negative $10 million and a positive $6 million for the nine months ended September 30, 2011 and 2010, 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

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs” (“ ASU No. 2011-04”), which provides guidance about how fair value should be applied where it is already required or permitted under U.S. GAAP. The ASU does not extend the use of fair value or require additional fair value measurements, but rather provides explanations about how to measure fair value. ASU No. 2011-04 requires prospective application and will be effective for interim and annual reporting periods beginning after December 15, 2011. The Company is currently assessing the impact ASU No. 2011-04 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.

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, 2010, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. We recorded a foreign exchange loss in our income statement of approximately $8 million in the first nine months of 2011, compared to a $29 million foreign exchange loss in the same period of the prior year. The gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods as of September 30, 2011 (in millions, except contract rates):


	As of September 30, 2011											December 31,
Functional Currency	2011			2012			2013		Total			2010
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		279			1			—		280			267
Average CAD to USD contract rate		1.0210			0.9879			—		1.0209			1.0072
Fair Value at September 30, 2011 in U.S. dollars		6			—			—		6			(1	)

Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		98			84			2		184			55
Average CAD to USD contract rate		0.9853			0.9842			1.0189		0.9853			1.0237
Fair Value at September 30, 2011 in U.S. dollars		(5	)		(4	)		—		(9	)		1

EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		5			8			—		13			1
Average USD to EUR contract rate		1.4150			1.4185			—		1.4164			1.3884
Fair Value at September 30, 2011 in U.S. dollars		—			—			—		—			—

Sell USD/Buy EUR:
Notional amount to buy (in euros)		84			88			—		172			74
Average USD to EUR contract rate		1.3550			1.3943			—		1.3751			1.3172
Fair Value at September 30, 2011 in U.S. dollars		—			3			—		3			1

KRW Sell EUR/Buy KRW:
Notional amount to buy (in South Korean won)		35,627			3,416			639		39,682			273
Average KRW to EUR contract rate		1,077.0160			1,118.6770			1,020.2500		1,079.5090			1,742.5300
Fair Value at September 30, 2011 in U.S. dollars		(3	)		—			—		(3	)		—


	As of September 30, 2011												December 31,
Functional Currency	2011			2012			2013			Total			2010
Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)		—			123			261			384			67,657
Average KRW to USD contract rate		—			923.7000			918.8200			920.3811			1,085.6800
Fair Value at September 30, 2011 in U.S. dollars		—			—			—			—			(3	)

GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		77			—			—			77			—
Average USD to GBP contract rate		1.5625			—			—			1.5625			—
Fair Value at September 30, 2011 in U.S. dollars		—			—			—			—			—

Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		21			16			—			37			49
Average USD to GBP contract rate		1.6023			1.5979			—			1.6004			1.4952
Fair Value at September 30, 2011 in U.S. dollars		(1	)		(1	)		—			(2	)		2

USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		13			13			—			26			19
Average DKK to USD contract rate		5.2992			5.3172			—			5.3086			5.5064
Fair Value at September 30, 2011 in U.S. dollars		—			—			—			—			—

Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		115			353			27			495			224
Average USD to EUR contract rate		1.4089			1.4012			1.3971			1.4027			1.3243
Fair Value at September 30, 2011 in U.S. dollars		(4	)		(10	)		(1	)		(15	)		—

Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		19			—			—			19			18
Average USD to GBP contract rate		1.6134			—			—			1.6134			1.5724
Fair Value at September 30, 2011 in U.S. dollars		(1	)		—			—			(1	)		—

Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		225			607			160			992			810
Average NOK to USD contract rate		5.7352			5.9349			5.8941			5.8830			6.2022
Fair Value at September 30, 2011 in U.S. dollars		(2	)		9			(1	)		6			32

Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		9			—			—			9			8
Average DKK to USD contract rate		5.3043			—			—			5.3043			5.5998
Fair Value at September 30, 2011 in U.S. dollars		—			—			—			—			—

Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		43			22			1			66			66
Average USD to EUR contract rate		1.3972			1.3860			1.4019			1.3936			1.3423
Fair Value at September 30, 2011 in U.S. dollars		1			—			—			1			1

Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		158			59			1			218			229
Average NOK to USD contract rate		5.5777			5.7842			5.9030			5.6349			6.1282
Fair Value at September 30, 2011 in U.S. dollars		6			—			—			6			(7	)

Sell RUB/Buy USD:
Notional amount to buy (in U.S. dollars)		21			—			—			21			25
Average DKK to USD contract rate		32.5400			—			—			32.5400			31.2030
Fair Value at September 30, 2011 in U.S. dollars		—			—			—			—			(1	)

Other Currencies
Fair Value at September 30, 2011 in U.S. dollars		(1	)		(5	)		1			(5	)		(1	)


Total Fair Value at September 30, 2011 in U.S. dollars		(4	)		(8	)		(1	)		(13	)		24

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $181 million and translation exposures totaling $653 million as of September 30, 2011 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 $12 million and the transactional exposures financial market risk sensitive instruments could affect the future fair value by $65 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, 2011 our long term borrowings consisted of $200 million in 5.65% Senior Notes, $150 million in 5.5% Senior Notes and $151 million in 6.125% Senior Notes. We occasionally have borrowings under our credit facility, and a portion of these borrowings could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to six months. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.

Item 4. Controls and Procedures

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

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

PART II — OTHER INFORMATION

Item 5. Other Information

Consistent with the recommendation of our stockholders at our 2011 Annual Meeting, the Company will include an advisory stockholder vote on executive compensation in its proxy materials every year until the next required advisory vote on the frequency of stockholder votes on executive compensation, which will occur no later than our annual meeting of stockholders in 2017.

Item 6. Exhibits

Reference is hereby made to the Exhibit Index commencing on page 34.

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 4, 2011	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		Fifth Amended and Restated Certificate of Incorporation of National Oilwell Varco, Inc. (Exhibit 3.1) (1)

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

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

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

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

10.4		National Oilwell Varco Long-Term Incentive Plan. (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, 2011 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 5, 2011.

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

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

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

(5)		Filed as 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 August 17, 2011.

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

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

(12)		Filed as 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.