NOV Inc. - Quarter Report: 2012 September (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2012

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

Commission File Number 1-12317

NATIONAL OILWELL VARCO, INC.

(Exact name of registrant as specified in its charter)

Delaware

76-0475815

(State or other jurisdiction

of incorporation or organization)

(I.R.S. Employer

Identification No.)

7909 Parkwood Circle Drive

Houston, Texas

77036-6565

(Address of principal executive offices)

(713) 346-7500

(Registrant’s telephone number, including area code)

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

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

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

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

As of October 30, 2012 the registrant had 426,905,434 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,
	2012		2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,702	$	3,535
Receivables, net		4,033		3,291
Inventories, net		5,989		4,030
Costs in excess of billings		1,065		593
Deferred income taxes		286		336
Prepaid and other current assets		592		325

Total current assets		13,667		12,110

Property, plant and equipment, net		2,818		2,445
Deferred income taxes		320		267
Goodwill		6,940		6,151
Intangibles, net		4,431		4,073
Investment in unconsolidated affiliates		370		391
Other assets		116		78

Total assets	$	28,662	$	25,515

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,365	$	901
Accrued liabilities		2,363		2,376
Billings in excess of costs		1,037		865
Current portion of long-term debt and short-term borrowings		354		351
Accrued income taxes		194		709
Deferred income taxes		368		214

Total current liabilities		5,681		5,416

Long-term debt		1,175		159
Deferred income taxes		1,802		1,852
Other liabilities		321		360

Total liabilities		8,979		7,787

Commitments and contingencies

Stockholders’ equity:
Common stock - par value $.01; 1 billion shares authorized; 426,879,173 and 423,900,601 shares issued and outstanding at September 30, 2012 and December 31, 2011		4		4
Additional paid-in capital		8,718		8,535
Accumulated other comprehensive income (loss)		79		(23	)
Retained earnings		10,773		9,103

Total Company stockholders’ equity		19,574		17,619
Noncontrolling interests		109		109

Total stockholders’ equity		19,683		17,728

Total liabilities and stockholders’ equity	$	28,662	$	25,515

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(In millions, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenue	$	5,319		$	3,740		$	14,356		$	10,399
Cost of revenue		3,948			2,576			10,411			7,177

Gross profit		1,371			1,164			3,945			3,222
Selling, general and administrative		473			392			1,291			1,133

Operating profit		898			772			2,654			2,089
Interest and financial costs		(11	)		(8	)		(28	)		(31	)
Interest income		2			5			8			13
Equity income in unconsolidated affiliates		7			11			43			34
Other income (expense), net		(22	)		—			(43	)		(26	)

Income before income taxes		874			780			2,634			2,079
Provision for income taxes		265			252			819			667

Net income		609			528			1,815			1,412
Net loss attributable to noncontrolling interests		(3	)		(4	)		(8	)		(8	)

Net income attributable to Company	$	612		$	532		$	1,823		$	1,420

Net income attributable to Company per share:
Basic	$	1.44		$	1.26		$	4.29		$	3.37

Diluted	$	1.43		$	1.25		$	4.28		$	3.35

Cash dividends per share	$	0.12		$	0.11		$	0.36		$	0.33

Weighted average shares outstanding:
Basic		425			422			425			421

Diluted		427			425			426			424

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(In millions)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net income	$	609		$	528		$	1,815		$	1,412
Currency translation adjustments		84			(117	)		28			(25	)
Changes in derivative financial instruments, net of tax		64			(71	)		74			(29	)

Comprehensive income		757			340			1,917			1,358
Comprehensive loss attributable to noncontrolling interest		(3	)		(4	)		(8	)		(8	)

Comprehensive income attributable to Company	$	760		$	344		$	1,925		$	1,366

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In millions)


	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	1,815		$	1,412
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		462			413
Deferred income taxes		40			(179	)
Equity income in unconsolidated affiliates		(43	)		(34	)
Dividend from unconsolidated affiliate		61			45
Other, net		76			70
Change in operating assets and liabilities, net of acquisitions:
Receivables		(251	)		(646	)
Inventories		(1,152	)		(530	)
Costs in excess of billings		(472	)		284
Prepaid and other current assets		(254	)		(78	)
Accounts payable		165			146
Billings in excess of costs		173			606
Income taxes payable		(569	)		(20	)
Other assets/liabilities, net		(231	)		32

Net cash provided by (used in) operating activities		(180	)		1,521

Cash flows from investing activities:
Purchases of property, plant and equipment		(382	)		(317	)
Business acquisitions, net of cash acquired		(2,305	)		(315	)
Dividend from unconsolidated affiliate		—			13
Other		24			43

Net cash used in investing activities		(2,663	)		(576	)

Cash flows from financing activities:
Borrowings against lines of credit and other debt		1,019			—
Repayments on debt		(3	)		(374	)
Cash dividends paid		(153	)		(140	)
Proceeds from stock options exercised		111			94
Other		31			22

Net cash provided by (used in) financing activities		1,005			(398	)
Effect of exchange rates on cash		5			(10	)

Increase (decrease) in cash and cash equivalents		(1,833	)		537
Cash and cash equivalents, beginning of period		3,535			3,333

Cash and cash equivalents, end of period	$	1,702		$	3,870

Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	21		$	34
Income taxes	$	1,320		$	805

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

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

The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (the “Company”) present information in accordance with GAAP in the United States for interim financial information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not include all information or footnotes required by GAAP in the United States for complete consolidated financial statements and should be read in conjunction with our 2011 Annual Report on Form 10-K.

In our opinion, the consolidated financial statements include all adjustments, all of which are of a normal recurring nature, necessary for a fair presentation of the results for the interim periods. The results of operations for the three and nine months ended September 30, 2012 are not necessarily indicative of the results to be expected for the full year.

Fair Value of Financial Instruments

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

2. Inventories, net

Inventories consist of (in millions):


	September 30,		December 31,
	2012		2011
Raw materials and supplies	$	1,245	$	907
Work in process		1,151		852
Finished goods and purchased products		3,593		2,271

Total	$	5,989	$	4,030

3. Accrued Liabilities

Accrued liabilities consist of (in millions):


	September 30,		December 31,
	2012		2011
Customer prepayments and billings	$	687	$	686
Accrued vendor costs		407		280
Compensation		349		468
Warranty		210		211
Taxes (non income)		113		119
Insurance		111		103
Fair value of derivatives		33		83
Interest		9		7
Other		444		419

Total	$	2,363	$	2,376

Service and Product Warranties

The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with Accounting Standards Codification (“ASC”) Topic 450 “Contingencies” (“ASC Topic 450”). Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product performance issues and accrues for them when they are encountered.

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


Balance at December 31, 2011	$	211

Net provisions for warranties issued during the year		39
Amounts incurred		(44	)
Currency translation adjustments and other		4

Balance at September 30, 2012	$	210

4. Costs and Estimated Earnings on Uncompleted Contracts

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


	September 30,			December 31,
	2012			2011
Costs incurred on uncompleted contracts	$	6,479		$	5,839
Estimated earnings		3,516			3,775

		9,995			9,614
Less: Billings to date		9,967			9,886

	$	28		$	(272	)

Costs and estimated earnings in excess of billings on uncompleted contracts	$	1,065		$	593
Billings in excess of costs and estimated earnings on uncompleted contracts		(1,037	)		(865	)

	$	28		$	(272	)

5. Comprehensive Income

The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, currency translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in Other Comprehensive Income or Loss in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three and nine months ended September 30, 2012, a majority of these local currencies strengthened against the U.S. dollar resulting in net Other Comprehensive Income of $84 million and $28 million, respectively, upon the translation from local currencies to the U.S. dollar. For the three and nine months ended September 30, 2011, a majority of these local currencies weakened against the U.S. dollar resulting in net Other Comprehensive Loss of $117 million and $25 million, respectively.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in Other Comprehensive Income or Loss, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income or Loss from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of Other Comprehensive Income or Loss related to cumulative changes in the fair value of derivatives that have settled in the current or prior periods. The accumulated effect was Other Comprehensive Income of $64 million (net of tax of $23 million) and $74 million (net of tax of $27 million) for the three and nine months ended September 30, 2012, respectively. The accumulated effect was Other Comprehensive Loss 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 September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenue:
Rig Technology	$	2,547		$	1,970		$	7,211		$	5,472
Petroleum Services & Supplies		1,717			1,460			5,197			4,084
Distribution & Transmission		1,315			480			2,659			1,313
Eliminations		(260	)		(170	)		(711	)		(470	)

Total Revenue	$	5,319		$	3,740		$	14,356		$	10,399

Operating Profit:
Rig Technology	$	598		$	523		$	1,699		$	1,456
Petroleum Services & Supplies		383			298			1,161			777
Distribution & Transmission		42			37			131			90
Unallocated expenses and eliminations		(125	)		(86	)		(337	)		(234	)

Total Operating Profit	$	898		$	772		$	2,654		$	2,089

Operating Profit %:
Rig Technology		23.5	%		26.5	%		23.6	%		26.6	%
Petroleum Services & Supplies		22.3	%		20.4	%		22.3	%		19.0	%
Distribution & Transmission		3.2	%		7.7	%		4.9	%		6.9	%
Total Operating Profit %		16.9	%		20.6	%		18.5	%		20.1	%

Included in operating profit are other costs related to acquisitions, such as the amortization of backlog and inventory that was stepped up to fair value during purchase accounting. Other costs by segment are as follows (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Other costs:
Rig Technology	$	12	$	5	$	33	$	11
Petroleum Services & Supplies		—		1		3		17
Distribution & Transmission		36		—		44		1

Total other costs	$	48	$	6	$	80	$	29

The Company had revenues of 9% and 10% of total revenue from one of its customers for the three and nine months ended September 30, 2012, respectively, and revenues of 13% and 12% of total revenue from one of its customers for the three and nine months ended September 30, 2011. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.

7. Debt

Debt consists of (in millions):


	September 30,		December 31,
	2012		2011
Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012	$	200	$	200
Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012		150		150
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015		151		151
Revolving Credit Facility, expires September 28, 2017		1,015		—
Other		13		9

Total debt		1,529		510
Less current portion		354		351

Long-term debt	$	1,175	$	159

New Revolving Credit Facility

On September 28, 2012, the Company entered into a new five-year unsecured revolving credit facility with a syndicate of financial institutions. This new credit facility replaced early the Company’s previous $2.0 billion revolving credit facility and provides for aggregate multicurrency borrowings up to $3.5 billion. In addition, the Company has an accordion option to increase aggregate borrowing availability by an additional $1.0 billion, subject to obtaining additional or increased lender commitments from members of the syndication. Interest under the new credit facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% subject to a ratings-based grid, or the prime rate. The terms of the new credit facility provide for a financial covenant regarding maximum debt to capitalization. At September 30, 2012, the Company was in compliance with the financial covenant under the new credit facility.

At September 30, 2012, there were $1,015 million in borrowings, and there were $913 million in outstanding letters of credit issued, resulting in $1,572 million of funds available under the new credit facility.

The Company also had $1,944 million of additional outstanding letters of credit at September 30, 2012, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds.

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

8. Tax

The effective tax rate for the three and nine months ended September 30, 2012 was 30.3% and 31.1%, respectively, compared to 32.3% and 32.1% for the same period in 2011. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the period by the effect of lower tax rates on income earned in foreign jurisdictions, reduced non-deductible expenses, the deduction in the U.S. for manufacturing activities and foreign exchange losses for tax reporting in Norway.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Federal income tax at U.S. federal statutory rate	$	306		$	273		$	922		$	728
Foreign income tax rate differential		(29	)		(42	)		(109	)		(108	)
State income tax, net of federal benefit		7			6			24			17
Nondeductible expenses		—			9			23			33
Tax benefit of manufacturing deduction		(12	)		(14	)		(30	)		(26	)
Foreign dividends, net of foreign tax credits		2			33			22			43
Tax impact of foreign exchange		(15	)		13			(33	)		14
Tax rate change on temporary differences		—			(5	)		—			(18	)
Other		6			(21	)		—			(16	)

Provision for income taxes	$	265		$	252		$	819		$	667

The balance of unrecognized tax benefits at September 30, 2012 was $127 million. The Company recognized no material changes in the balance of unrecognized tax benefits for the three and nine months ended September 30, 2012.

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

The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The Company has significant operations in the U.S., Canada, the U.K., the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdiction vary by legal entity, but are generally open in the U.S. for tax years after 2008 and outside the U.S. for tax years after 2005.

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

9. Stock-Based Compensation

The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights. The number of shares authorized under the Plan is 25.5 million. At September 30, 2012, 3,563,803 shares remain available for future grants under the Plan, all of which are available for grants of stock options, performance-based share awards, restricted stock awards, phantom shares, stock payments and stock appreciation rights. During the three months ended March 31, 2012, the Company concluded that the performance conditions relating to the performance-based restricted stock awards granted on February 20, 2009 were not met. As a result, the Company reversed $8 million in previously recognized stock-based compensation expense related to performance-based restricted stock awards that did not vest. Total stock-based compensation for all stock-based compensation arrangements under the Plan was $23 million and $57 million for the three and nine months ended September 30, 2012, respectively, and $19 million and $55 million for the three and nine months ended September 30, 2011, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $6 million and $17 million for the three and nine months ended September 30, 2012, respectively, and $6 million and $17 million for the three and nine months ended September 30, 2011, respectively.

During the nine months ended September 30, 2012, the Company granted 2,239,088 stock options and 482,428 shares of restricted stock and restricted stock units, which includes 148,550 performance-based restricted stock awards. The stock options were granted February 21, 2012 with an exercise price of $84.58. Out of the total number of restricted stock and restricted stock units, 464,270 were granted February 21, 2012 and vest on the third anniversary of the date of grant. On May 16, 2012, 18,158 restricted stock awards were granted to the non-employee members of the board of directors. These restricted stock awards vest in equal thirds over three years on the anniversary of the grant date. The performance-based restricted stock awards were granted February 21, 2012. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s operating income growth, measured on a percentage basis, from January 1, 2012 through December 31, 2014 exceeding the median operating income growth for the designated peer group over the same period.

10. Derivative Financial Instruments

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

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

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

At September 30, 2012, the Company has determined that the fair value of its derivative financial instruments representing assets of $81 million and liabilities of $34 million (primarily currency related derivatives) are determined using level 2 inputs (inputs other than quoted prices in active markets for identical assets and liabilities that are observable either directly or indirectly for substantially the full term of the asset or liability) in the fair value hierarchy as the fair value is based on publicly available foreign exchange and interest rates at each financial reporting date. At September 30, 2012, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $47 million.

At September 30, 2012, the Company did not have any interest rate swaps and its financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

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

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

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


	Currency Denomination
Foreign Currency	September 30, 2012		December 31, 2011
Norwegian Krone	NOK	7,035	NOK	6,639
U.S. Dollar	$	393	$	402
Euro	€	383	€	456
Mexican Peso	MXN	102	MXN	—
Danish Krone	DKK	112	DKK	98
Singapore Dollar	SGD	16	SGD	10
British Pound Sterling	£	11	£	2

Non-designated Hedging Strategy

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.

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) is recognized in other income (expense), net in current earnings.

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


	Currency Denomination
Foreign Currency	September 30, 2012		December 31, 2011
Norwegian Krone	NOK	1,717	NOK	2,310
Russian Ruble	RUB	1,266	RUB	786
U.S. Dollar	$	936	$	483
Euro	€	253	€	161
Danish Krone	DKK	217	DKK	67
Brazilian Real	BRL	99	BRL	—
Singapore Dollar	SGD	43	SGD	5
British Pound Sterling	£	12	£	9
Canadian Dollar	CAD	2	CAD	—
Swedish Krone	SEK	—	SEK	4

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

NATIONAL OILWELL VARCO, INC.

Fair Values of Derivative Instruments

(In millions)


	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet	September 30,		December 31,		Balance Sheet	September 30,		December 31,
	Location	2012		2011		Location	2012		2011
Derivatives designated as hedging instruments under ASC Topic 815
Foreign exchange contracts	Prepaid and other current assets	$	42	$	16	Accrued liabilities	$	16	$	62
Foreign exchange contracts	Other Assets		22		1	Other Liabilities		1		13

Total derivatives designated as hedging instruments under ASC Topic 815		$	64	$	17		$	17	$	75

Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts	Prepaid and other current assets	$	17	$	9	Accrued liabilities	$	17	$	21

Total derivatives not designated as hedging instruments under ASC Topic 815		$	17	$	9		$	17	$	21

Total derivatives		$	81	$	26		$	34	$	96

The Effect of Derivative Instruments on the Consolidated Statements 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,

2012

2011

2012

2011

2012

2011

Revenue

)

Foreign exchange contracts

Cost of revenue

(22

)

Other income (expense), net

Total

(31

)


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,
		2012		2011
Foreign exchange contracts	Other income (expense), net		8		0

Total			8		0

(a)	The Company expects that $11 million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow.

(b)

The amount of gain (loss) recognized in income represents $(1) million and $11 million related to the ineffective portion of the hedging relationships for the nine months ended September 30, 2012 and 2011, respectively, and $6 million and $13 million related to the amount excluded from the assessment of the hedge effectiveness for the nine months ended September 30, 2012 and 2011, respectively.

11. Net Income Attributable to Company Per Share

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Numerator:
Net income attributable to Company	$	612	$	532	$	1,823	$	1,420

Denominator:
Basic—weighted average common shares outstanding		425		422		425		421
Dilutive effect of employee stock options and other unvested stock awards		2		3		1		3

Diluted outstanding shares		427		425		426		424

Net income attributable to Company per share:
Basic	$	1.44	$	1.26	$	4.29	$	3.37

Diluted	$	1.43	$	1.25	$	4.28	$	3.35

Cash dividends per share	$	0.12	$	0.11	$	0.36	$	0.33

ASC Topic 260, “Earnings Per Share” (“ASC Topic 260”) requires companies with unvested participating securities to utilize a two-class method for the computation of Net income attributable to Company per share. The two-class method requires a portion of Net income attributable to Company to be allocated to participating securities, which are unvested awards of share-based payments with non-forfeitable rights to receive dividends or dividend equivalents, if declared. Net income attributable to Company allocated to these participating securities was immaterial for three and nine months ended September 30, 2012 and 2011 and therefore not excluded from Net income attributable to Company per share calculation.

In addition, the Company had stock options outstanding that were anti-dilutive totaling 4 million and 5 million shares for the three and nine months ended September 30, 2012, respectively, and 2 million and 3 million shares for the three and nine months ended September 30, 2011, respectively.

12. Cash Dividends

On August 15, 2012, the Company’s Board of Directors approved a cash dividend of $0.12 per share. The cash dividend was paid on September 28, 2012, to each stockholder of record on September 14, 2012. Cash dividends aggregated $51 million and $153 million for the three and nine months ended September 30, 2012, respectively, and $47 million and $140 million for the three and nine months ended September 30, 2011, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.

13. Commitments and Contingencies

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

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

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

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

14. Acquisitions

In the nine months ended September 30, 2012, the Company completed twelve acquisitions for an aggregate purchase price of $2,305 million, net of cash acquired. These acquisitions included:

•

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

•

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

•

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

•

The shares of CE Franklin Ltd. (“CE Franklin”), a Canada-based distributor of pipe, valves, flanges, fittings, production equipment, tubular products and other general oilfield supplies to oil and gas producers in Canada as well as to the oil sands, refining, heavy oil, petrochemical, forestry and mining industries, acquired on July 19, 2012.

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


Current assets, net of cash acquired	$	1,365
Property, plant and equipment		205
Intangible assets		597
Goodwill		774

Total assets acquired		2,941

Current liabilities		549
Long-term debt		4
Other liabilities		83

Total liabilities		636

Cash consideration, net of cash acquired	$	2,305

The Company allocated $597 million to intangible assets (21.1 year weighted-average life). The intangible assets are expected to be amortizable and are comprised of: $238 million of customer relationships (24.7 year weighted-average life), $91 million of trademarks (18.5 year weighted-average life), and $268 million of other intangible assets (18.7 year weighted-average life). The $774 million allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill resulting from the NKT and CE Franklin acquisitions and a portion of the Enerflow acquisition is not expected to be deductible for tax purposes.

Robbins & Myers, Inc. Merger Agreement

On August 8, 2012, the Company entered into an agreement to acquire Robbins & Myers, Inc. for approximately $2.5 billion in cash. Under the agreement, Robbins & Myers’ shareholders would receive $60.00 per share in cash in return for each of the approximately 42.4 million shares outstanding. The boards of directors of the Company and Robbins & Myers, Inc. have unanimously approved the transaction, which is subject to customary closing conditions, including the approval of holders of at least two-thirds of Robbins & Myers, Inc. outstanding shares and approval from various regulatory agencies. Compliance with requests from regulatory agencies will put pressure on timing, and although a fourth quarter 2012 closing is targeted, the closing could slip into 2013.

15. Recently Issued Accounting Standards

In July 2012, the Financial Accounting Standards Board issued Accounting Standard Update No. 2012-02 “Intangibles—Goodwill and Other (Topic 350)” that amends the accounting guidance on testing indefinite-lived intangible assets for impairment. The amendments in this accounting standard update are intended to reduce complexity and costs by allowing an entity the option to make a qualitative evaluation about the likelihood that an indefinite-lived intangible asset is impaired to determine whether it should perform a quantitative impairment test. The amendments also enhance the consistency of impairment testing guidance among long-lived asset categories by permitting an entity to assess qualitative factors to determine whether it is necessary to calculate the asset’s fair value when testing an indefinite-lived intangible asset for impairment, which is equivalent to the impairment testing requirements for other long-lived assets. The amendments in this accounting standard update are effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012. The Company tests its indefinite-lived intangible assets for impairment annually in the fourth quarter or more frequently when events or changes in circumstances indicate that impairment may have occurred.

16. Subsequent Events

Subsequent to September 30, 2012, the Company completed multiple acquisitions for approximately $500 million in cash.

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

Introduction

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

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

Rig Technology

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

Petroleum Services & Supplies

Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service drill pipe, tubing, casing, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer pumps, solids control systems, drilling motors, drilling fluids, drill bits, reamers and other downhole tools, and mud pump consumables. Demand for these services and supplies is determined principally by the level of oilfield drilling and workover activity by drilling contractors, major and independent oil and gas companies, and national oil companies. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drill pipe, line pipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced fiberglass composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including additional operations in the United States, Canada, the United Kingdom, Brazil, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, Oman, and the United Arab Emirates.

Distribution & Transmission

Our Distribution & Transmission segment provides maintenance, repair and operating supplies (“MRO”) and spare parts to drill site and production locations worldwide. In addition to its comprehensive network of field locations supporting land drilling operations throughout North America, the segment supports major offshore operations for all the major oil and gas producing regions throughout the world. The segment employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe. The segment also has a global reach in oil and gas, waste water treatment, chemical, food and beverage, paper and pulp, mining, agriculture, and a variety of municipal markets and is a leading producer of water transmission pipe and fabricated steel products, such as specialized materials and products used in infrastructure projects. Demand for the segment’s services is determined primarily by the level of drilling, servicing, and oil and gas production activities and is also influenced by the domestic economy in general, housing starts and government policies. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including additional operations in the United States, Canada, the United Kingdom, Kazakhstan, Singapore, Russia, and Malaysia.

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2011, we identified our most critical accounting policies. In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are most critical in nature which are related to revenue recognition under long-term construction contracts; allowance for doubtful accounts; inventory reserves; impairments of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets; service and product warranties; and income taxes. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. The combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates and those differences may be material.

EXECUTIVE SUMMARY

For its third quarter ended September 30, 2012, the Company generated $612 million in net income attributable to Company, or $1.43 per fully diluted share, on $5.3 billion in revenue. Compared to the second quarter of 2012, revenue increased $585 million or 12 percent and net income attributable to Company increased $7 million. Compared to the third quarter of 2011, revenue increased $1.6 billion or 42 percent and net income attributable to Company increased $80 million or 15 percent.

The third quarter of 2012 included pre-tax transaction charges of $57 million, the second quarter of 2012 included pre-tax transaction charges of $28 million, and the third quarter of 2011 included pre-tax transaction charges of $6 million. Excluding transaction charges from all periods, third quarter 2012 earnings were $1.52 per fully diluted share, compared to $1.46 per fully diluted share in the second quarter of 2012 and $1.26 per fully diluted share in the third quarter of 2011.

Operating profit excluding transaction charges was $946 million or 17.8 percent of sales in the third quarter of 2012, compared to $907 million or 19.2 percent of sales in the second quarter of 2012, and $778 million or 20.8 percent of sales in the third quarter of 2011. Third quarter 2012 results include full or partial quarter results for several businesses acquired since the beginning of the year, including three lower-margin distribution businesses, which resulted in lower margins for the third quarter of 2012 both sequentially and year-over-year. Operating leverage or flow-through (the change in operating profit divided by the change in revenue) was seven percent on the sequential revenue increase, and 11 percent on the year-over-year third quarter sales increase.

Oil & Gas Equipment and Services Market

Worldwide developed economies turned down in late 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks responded vigorously through 2009, but a credit-driven worldwide economic recession developed nonetheless. Developed economies struggled to recover throughout 2010 and 2011, facing additional economic weakness related to potential sovereign debt defaults in Europe. As a result, commodity prices, including oil and gas prices, have been volatile. After rising steadily for six years to peak at around $140 per barrel (West Texas Intermediate Crude Prices) earlier in 2008, oil prices collapsed back to average $43 per barrel during the first quarter of 2009, but have slowly recovered into the $100 per barrel range by mid-2011 where they held relatively steady since (the third quarter of 2012 dipped slightly to average $92 per barrel). After trading in the range of $6 to $9 an mmbtu from 2004 to 2008, North American gas prices declined to average $3.17 per mmbtu in the third quarter of 2009. Gas prices recovered modestly, trading up above $5 six months later, but then slowly settled into the $3 to $4 per mmbtu through 2011 before turning down sharply in early 2012 to the $2 range (third quarter 2012 recovered slightly to average $2.88 per mmbtu). The recent gas price collapse appears to be a direct result of rising gas supply out of unconventional shale reservoir developments across North America, including gas associated with liquids production from shales.

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

The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a low of 876 in June, 2009. U.S. rig count increased steadily to 2,026 by late 2011, but began to decline with lower gas prices to average 1,906 rigs during the third quarter of 2012 (and had fallen to 1,826 by late October 2012). Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity in 2009, but drilling recovered across North America as gas prices improved. Recently low gas prices have caused operators to trim drilling, driving the U.S. gas rig count down 42 percent to 505 in the past year. However, with high oil prices many redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. Oil drilling has risen to 74 percent of the total domestic drilling effort and with oil drilling above 1,400 rigs, it is at the highest levels in the U.S. since the early 1980’s.

Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings, but the international rig count exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 947 in August 2009. Recently international drilling rebounded due to high oil prices, climbing back to 1,285 in June 2012 before falling back to 1,254 in September.

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

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

The industry responded by launching many new rig construction projects since 2005, to 1.) retool the existing fleet of jackup rigs (according to Offshore Data Services, nearly 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 June 30, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $4.9 billion by June 30, 2010. The backlog increased steadily since as drillers began ordering more than the Company shipped out of backlog, and finished the third quarter of 2012 at $11.7 billion. Approximately $1.9 billion of these orders are scheduled to flow out as revenue during the remainder of 2012; $7.1 billion are scheduled to flow out as revenue during 2013; and the balance thereafter. The land rig backlog comprised 13 percent and equipment destined for offshore operations comprised 87 percent of the total backlog as of September 30, 2012. Equipment destined for international markets totaled 95 percent of the backlog.

Segment Performance

The Rig Technology segment generated $2.5 billion in revenues and $598 million in operating profit (which included $12 million in other costs related to acquisitions) or 23.5 percent of sales during the third quarter of 2012. Compared to the prior quarter revenues increased $142 million or six percent, and operating profit increased $44 million. Operating leverage or flow-through was 31 percent from the second quarter to the third quarter. Compared to the third quarter of 2011 segment revenues grew $577 million or 29 percent, and operating profit increased $75 million. Year-over-year operating leverage or flow-through was 13 percent. Margins have moved down steadily since mid-2010 due to an adverse mix shift in the segment, as well as the addition of lower-margin acquisitions. The mix shift arises from offshore projects contracted at high prices in 2007 and 2008, which were subsequently manufactured in low cost environments in 2009 and 2010, resulting in high margins for the group which peaked in the third quarter of 2010. As these projects have been completed and replaced with lower priced projects, margins have gradually declined. Revenue out of backlog increased five percent sequentially and increased 36 percent year-over-year. Non-backlog revenue, which is predominantly aftermarket spares and services, increased eight percent sequentially and increased 13 percent from the third quarter of 2011. Orders for seven deepwater floating rig equipment packages, including five for Brazil, and one jackup rig package contributed to total order additions to backlog of $2.3 billion during the third quarter. Interest in offshore rig construction has remained strong as announced dayrates for deepwater offshore rigs are increasing, rig building costs have stabilized at attractive levels, and financing appears to be available for most established drillers. The Company continues to tender additional new offshore rig projects for Petrobras to shipyards and drilling contractors, which are to be built in Brazil. However, further potential bookings of any additional offshore rigs for Brazil may continue to be subject to delays. The segment’s well intervention and stimulation product sales increased slightly sequentially, as the full-quarter contribution from an acquisition was more than offset by falling pressure pumping equipment demand.

The Petroleum Services & Supplies segment generated $1.7 billion in revenue and $383 million in operating profit, or 22.3 percent of sales, for the third quarter of 2012. Compared to the prior quarter revenue decreased $59 million or three percent, and operating leverage or flow-through was 12 percent. Sequentially lower sales of drill pipe accounted for most of the segment’s third quarter revenue decrease. Additionally, though, lower sales of composite pipe, coiled tubing and conductor pipe connectors were partly offset

by higher sales of downhole tools, pipe services and production equipment sales into international projects. Compared to the third quarter of 2011 revenues increased $257 million or 18 percent and operating leverage or flow-through was 33 percent. Despite a seasonal recovery in Canada, which resulted in an average of 153 more rigs drilling in the third quarter, the segment’s sales into Canada declined sequentially as a large shipment of downhole tools in the second quarter did not repeat, leading to lower revenues which more than offset sales gains in other products. Approximately 60 percent of the segment’s third quarter sales were into North American markets, and 40 percent of sales were into international markets.

The Distribution & Transmission segment generated $1.3 billion in revenue and $42 million in operating profit (which included $36 million in other costs related to acquisitions) or 3.2 percent of sales during the third quarter of 2012. Revenues grew $535 million or 69 percent from the second quarter of 2012. Compared to the third quarter of 2011 revenues increased $835 million or 174 percent. Third quarter revenue growth in both comparisons is due primarily to the acquisitions of Wilson and C. E. Franklin, made during the second and third quarters of 2012, and Ameron’s Water Transmission and Infrastructure Products, made during the fourth quarter of 2011. Approximately 84 percent of the group’s third quarter sales were into North American markets and 16 percent into international markets.

Outlook

Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher drilling activity in North America and slowly improving international drilling activity. Order levels for new deepwater drilling rigs have rebounded sharply, and the Rig Technology segment continues to experience a high level of interest as dayrates are improving for deepwater offshore rigs. While lower pricing led to declines in Rig Technology margins since mid-2010, we expect margins to stabilize in the mid-20 percent range. Recently won offshore rig construction orders at higher margins flowing in are likely to be offset by lower-margin contributions from recent subsea production equipment acquisitions, and a softening outlook for land drilling, workover and pressure pumping equipment markets in North America, in view of low gas and natural gas liquids prices.

Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution & Transmission segment remains closely tied to the rig count, particularly in North America. The third quarter saw domestic rig counts continue to decline, resulting in a U.S. rig count down 9 percent since the start of the year, and a very weak seasonal recovery in Canada. As a result, pricing and volumes are beginning to come under pressure as pressure pumpers, drilling contractors and oil companies reduce operating and capital expenditures. Additionally, economic weakness may pressure oil prices, which could lead to further activity declines, particularly among North American operators which may rely on cash flows from gas production and/or external financing to fund their drilling operations. In contrast, activity generally seems to be continuing to increase in most international markets outside North America, the modest third quarter international rig count decline notwithstanding.

The Company believes it is well positioned, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders. The Company has a long history of cost-control and downsizing in response to slowing market conditions, and of executing strategic acquisitions during difficult periods. Such a period may present opportunities to the Company to effect new organic growth and acquisition initiatives, and we remain hopeful that a downturn will generate new opportunities.

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

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


							%			%
							3Q12 v			3Q12 v
	3Q12*		3Q11*		2Q12*		3Q11			2Q12
Active Drilling Rigs:
U.S.		1,906		1,945		1,970		(2.0	%)		(3.2	%)
Canada		326		443		173		(26.4	%)		88.4	%
International		1,259		1,169		1,229		7.7	%		2.4	%

Worldwide		3,491		3,557		3,372		(1.9	%)		3.5	%

West Texas Intermediate Crude Prices (per barrel)	$	92.18	$	89.82	$	93.42		2.6	%		(1.3	%)
Natural Gas Prices ($/mmbtu)	$	2.88	$	4.12	$	2.28		(30.1	%)		26.3	%

*	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, 2012 on a quarterly basis:

LOGO

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

The worldwide quarterly average rig count increased 4% (from 3,372 to 3,491) and the U.S. decreased 3% (from 1,970 to 1,906), in the third quarter of 2012 compared to the second quarter of 2012. The average per barrel price of West Texas Intermediate Crude decreased 1% (from $93.42 per barrel to $92.18 per barrel) and natural gas prices increased 26% (from $2.28 per mmbtu to $2.88 per mmbtu) in the third quarter of 2012 compared to the second quarter of 2012.

U.S. rig activity at October 26, 2012 was 1,826 rigs compared to the third quarter average of 1,906 rigs, decreasing 4%. The price for West Texas Intermediate Crude was at $86.28 per barrel at October 26, 2012, decreasing 6% from the third quarter average. The price for natural gas was at $3.40 per mmbtu at October 26, 2012, increasing 18% from the third quarter average.

Results of Operations

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenue:
Rig Technology	$	2,547		$	1,970		$	7,211		$	5,472
Petroleum Services & Supplies		1,717			1,460			5,197			4,084
Distribution & Transmission		1,315			480			2,659			1,313
Eliminations		(260	)		(170	)		(711	)		(470	)

Total Revenue	$	5,319		$	3,740		$	14,356		$	10,399

Operating Profit:
Rig Technology	$	598		$	523		$	1,699		$	1,456
Petroleum Services & Supplies		383			298			1,161			777
Distribution & Transmission		42			37			131			90
Unallocated expenses and eliminations		(125	)		(86	)		(337	)		(234	)

Total Operating Profit	$	898		$	772		$	2,654		$	2,089

Operating Profit %:
Rig Technology		23.5	%		26.5	%		23.6	%		26.6	%
Petroleum Services & Supplies		22.3	%		20.4	%		22.3	%		19.0	%
Distribution & Transmission		3.2	%		7.7	%		4.9	%		6.9	%
Total Operating Profit %		16.9	%		20.6	%		18.5	%		20.1	%

Rig Technology

Three and Nine Months Ended September 30, 2012 and 2011. Revenue from Rig Technology was $2,547 million for the three months ended September 30, 2012, compared to $1,970 million for the three months ended September 30, 2011, an increase of $577 million (29.3%). For the nine months ended September 30, 2012, revenue from Rig Technology was $7,211 million compared to $5,472 million for the nine months ending September 30, 2011, an increase of $1,739 million (31.8%). Both deepwater offshore drilling worldwide and active shale plays in North America were the primary driving forces for the increase in revenue for this segment during the first half of 2012, resulting in increased rig construction as well as demand for well intervention and stimulation equipment and aftermarket spare parts. In addition, the acquisitions of NKT and Enerflow, occurring towards the beginning of the second quarter of 2012, contributed to the increase in revenue for Rig Technology. Moving into the second half of 2012, the Company saw continued strong deepwater offshore demand as well as a strong demand in international markets. North American markets, however, have begun to see a decrease in demand for land drilling as both gas and oil plays have begun to decrease production. This is evidenced by a slightly lower rig count in the U.S. and has resulted in lower sales of land rigs and jackups as the Company moved into the second half of 2012.

Operating profit from Rig Technology was $598 million (which included $12 million in other costs related to acquisitions) for the three months ended September 30, 2012 compared to $523 million for the three months ended September 30, 2011, an increase of $75 million (14.3%). Operating profit percentage decreased in the three months ended September 30, 2012 to 23.5%, from 26.5% in the three months ended September 30, 2011. For the nine months ended September 30, 2012, operating profit from Rig Technology was $1,699 million compared to $1,456 million for the nine months ended September 30, 2011, an increase of $243 million (16.7%). Operating profit percentage decreased to 23.6% in the nine months ended September 30, 2012, from 26.6% in the nine months ended September 30, 2011. The decrease in operating profit percentage was primarily due to decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. The integration of the NKT and Enerflow acquisitions made during the second quarter of 2012 also contributed to lower operating profit percentages.

The Rig Technology segment monitors its capital equipment backlog to plan its business. New orders are added to backlog only when the Company receives a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $11.7 billion at September 30, 2012, an increase of $1.4 billion (13.6%) from backlog of $10.3 billion at September 30, 2011. At September 30, 2012, approximately 87% of the capital equipment backlog was for offshore products and 13% was for land. In addition, at September 30, 2012, approximately 95% of the capital equipment backlog was for international markets and 5% was for domestic markets.

Petroleum Services & Supplies

Three and Nine Months Ended September 30, 2012 and 2011. Revenue from Petroleum Services & Supplies was $1,717 million for the three months ended September 30, 2012 compared to $1,460 million for the three months ended September 30, 2011, an increase of $257 million (17.6%). For the nine months ended September 30, 2012, revenue from Petroleum Services & Supplies was $5,197 million compared to $4,084 million for the nine months ended September 30, 2011, an increase of $1,113 million (27.3%). Strong shale plays in North America lead to a an increase in revenue for the Petroleum Services & Supplies segment during the first half of 2012 compared to the same period in 2011. Full period results of Ameron as well as other strategic acquisitions made during 2011 in the U.S., the U.K., the Netherlands, Singapore, Malaysia and Brazil also contributed to the increase in revenue for this segment in 2012 compared to 2011. Moving into the three months ended September 30, 2012, while stronger than the same period in 2011, compared to the first half of 2012, the Company began to see a decrease in North American activity as evidenced in the slight decrease in U.S. rig count. The three months ended September 30, 2012 saw a slower than normal recovery out of the breakup in Canada and the segment showed signs of slowing in a number of product lines, most notably drill pipe but also in composite pipe, coiled tubing, conductor pipe connectors and inspection equipment when compared to the first half of 2012.

Operating profit from Petroleum Services & Supplies was $383 million for the three months ended September 30, 2012 compared to $298 million for the three months ended September 30, 2011, an increase of $85 million (28.5%). Operating profit percentage increased to 22.3% in the three months ended September 30, 2012, up from 20.4% in the three months ended September 30, 2011. For the nine months ended September 30, 2012, operating profit from Petroleum Services & Supplies was $1,161 million compared to $777 million for the nine months ended September 30, 2011, an increase of $384 million (49.4%). Operating profit percentage increased to 22.3% in the nine months ended September 30, 2012, up from 19.0% in the nine months ended September 30, 2011. This increase is primarily due to increased volume, favorable pricing and cost reductions within most business units within the segment during the first half of 2012 compared to the same period in 2011. As the segment ended the three months ended September 30, 2012, it began to see pricing pressures as North American activity declined, the effects of which will likely be seen in quarters to come.

Distribution & Transmission

Three and Nine Months Ended September 30, 2012 and 2011. Revenue from Distribution & Transmission was $1,315 million for the three months ended September 30, 2012 compared to $480 million for the three months ended September 30, 2011, an increase of $835 million (174.0%). For the nine months ended September 30, 2012, revenue from Distribution & Transmission totaled $2,659 million compared to $1,313 million for the nine months ended September 30, 2011, an increase of $1,346 million (102.5%). This increase was primarily attributable to the acquisition of Wilson during the second quarter of 2012 and CE Franklin during the third quarter of 2012. In addition, the increasing recovery of deepwater drilling in the U.S. Gulf of Mexico lead to stronger revenue during 2012 when compared to 2011.

Operating profit from Distribution & Transmission was $42 million for the three months ended September 30, 2012 compared to $37 million for the three months ended September 30, 2011, an increase of $5 million (13.5%). Operating profit percentage decreased in the three months ended September 30, 2012 to 3.2%, from 7.7% in the three months ended September 30, 2011. For the nine months ended September 30, 2012, operating profit from Distribution & Transmission was $131 million compared to $90 million for the nine months ended September 30, 2011, an increase of $41 million (45.6%). Operating profit percentage decreased to 4.9% in the nine months ended September 30, 2012 from 6.9% in the nine months ended September 30, 2011. Increased volume, greater cost efficiencies and continued favorable pricing which related to strong demand for this segment contributed to an increase in operating profit percentages for this segment during the first half of 2012. Towards the end of the first half of 2012 and moving into the second half of 2012, the increase was offset by the integration of acquired, slightly lower operating profit percentage, businesses made during the second and third quarters of 2012. In addition, other costs incurred for the expense recognition associated with acquired current assets stepped up to fair value during purchase accounting also contributed to the decrease in operating profit percentage. The majority of the stepped up value related to inventory and was fully amortized by September 30, 2012. For the three and nine months ended September 30, 2012, operating profit for Distribution & Transmission included other costs related to acquisitions of $36 million and $44 million, respectively, compared to nil and $1 million for the three and nine months ended September 30, 2011.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $125 million and $337 million for the three and nine months ended September 30, 2012, respectively, compared to $86 million and $234 million, respectively, for the same periods in 2011. This increase is primarily due to higher intersegment eliminations as a result of increased market activity and recent acquisitions.

Other income (expense), net

Other income (expense), net were expenses of $22 million and $43 million for the three and nine months ended September 30, 2012, respectively, compared to nil and $26 million, respectively, for the same periods in 2011. Foreign exchange losses and increased bank charges and fees were the primary reasons for the increase in expenses for the three months ended September 30, 2012 compared to the same period in 2011. For the nine months ended September 30, 2012, the increase was primarily due to increased bank charges and fees with minimal effects from foreign exchange movement compared to the same period in 2011.

Provision for income taxes

Non-GAAP Financial Measures and Reconciliations

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

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

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


	Three Months Ended									Nine Months Ended September 30,
	September 30,						June			Nine Months Ended September 30,
	2012			2011			2012			2012			2011
Reconciliation of operating profit:
GAAP operating profit	$	898		$	772		$	879		$	2,654		$	2,089
Other costs (1):
Rig Technology		12			5			17			33			11
Petroleum Services & Supplies		—			1			3			3			17
Distribution & Transmission		36			—			8			44			1

Operating profit excluding other costs	$	946		$	778		$	907		$	2,734		$	2,118


	Three Months Ended									Nine Months Ended September 30,
	September 30,						June			Nine Months Ended September 30,
	2012			2011			2012			2012			2011
Reconciliation of operating profit %:
GAAP operating profit %		16.9	%		20.6	%		18.6	%		18.5	%		20.1	%
Other costs %		0.9	%		0.2	%		0.6	%		0.5	%		0.3	%

Operating profit % excluding other costs		17.8	%		20.8	%		19.2	%		19.0	%		20.4	%


	Three Months Ended									Nine Months Ended September 30,
	September 30,						June			Nine Months Ended September 30,
	2012			2011			2012			2012			2011
Reconciliation of diluted earnings per share:
GAAP earnings per share	$	1.43		$	1.25		$	1.42		$	4.28		$	3.35
Other costs (1)		0.09			0.01			0.04			0.15			0.06

Earnings per share excluding other costs	$	1.52		$	1.26		$	1.46		$	4.43		$	3.41

(1)

Other costs primarily include items such as the amortization of backlog and inventory that was stepped up to fair value during purchase accounting, items which are included in operating profit. For the three and nine months ended September 30, 2012, other costs included in operating profit were $48 million and $80 million, respectively. Certain other costs are included in other income (expense), net as well as interest and financial costs and were $9 million and $12 million for the three and nine months ended September 30, 2012, respectively. Other costs for the three and nine months ended September 30, 2012 totaled $57 million and $92 million, respectively.

Liquidity and Capital Resources

Overview

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

At September 30, 2012, the Company had cash and cash equivalents of $1,702 million, and total debt of $1,529 million. At December 31, 2011, cash and cash equivalents were $3,535 million and total debt was $510 million. A significant portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. Of the $1,702 million of cash and cash equivalents at September 30, 2012, approximately $1,596 million is held outside the U.S. If opportunities to invest in the U.S. are greater than available cash balances, rather than repatriating this cash, the Company may choose to borrow against its revolving credit facility.

The Company’s outstanding debt at September 30, 2012 was $1,529 million and consisted of $200 million of 5.65% Senior Notes due 2012, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, $1,015 million in borrowings against its new credit facility and other debt of $13 million.

At September 30, 2012, in addition to $1,015 million in borrowings, there were $913 million in outstanding letters of credit issued, resulting in $1,572 million of funds available under the new credit facility.

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


	Nine Months Ended September 30,
	2012			2011
Net cash provided by (used in) operating activities	$	(180	)	$	1,521
Net cash used in investing activities		(2,663	)		(576	)
Net cash provided by (used in) financing activities		1,005			(398	)

Operating Activities

For the first nine months of 2012, cash used in operating activities was $180 million compared to cash provided by operating activities of $1,521 million in the same period of 2011. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $1,815 million plus non-cash charges of $502 million and $61 million in a dividend received from Voestalpine Tubulars, an unconsolidated affiliate, less $43 million in equity income.

Net changes in operating assets and liabilities, net of acquisitions, used $2,592 million for the first nine months of 2012 compared to $206 million used in the same period in 2011. Due to an increase in market activity during the first nine months of 2012 compared to the same period in 2011, revenue and backlog increased which is reflected in increased accounts receivable as well as a buildup in inventory. Increased market activity during the first nine months of 2012 also resulted in higher taxes paid, higher accounts payable and an increase in both costs in excess of billings and billings in excess of costs with costs incurred on major rig projects outpacing customer progress and milestone invoicing.

Investing Activities

For the first nine months of 2012, net cash used in investing activities was $2,663 million compared to net cash used in investing activities of $576 million for the same period of 2011. Net cash used in investing activities continued to primarily be the result of acquisition activity and capital expenditures both of which increased in the first nine months of 2012 compared to the first nine months of 2011. The Company used $2,305 million for the purpose of strategic acquisitions during the first nine months of 2012 compared to $315 million for the same period of 2011. Subsequent to September 30, 2012, the Company completed multiple acquisitions using approximately $500 million in borrowings from its revolving credit facility. In addition, due to the continued growth in the Company worldwide both organically and through acquisition, the Company used $382 million during the first nine months of 2012 for capital expenditures compared to $317 million for the same period of 2011. The Company expects to finish 2012 having spent in the range of approximately $600 million for capital expenditures. During the first nine months of 2012, the Company used a combination of its cash on hand as well as borrowings from its revolving credit facility to fund its acquisitions and capital expenditures.

Financing Activities

For the first nine months of 2012, net cash provided by financing activities was $1,005 million compared to cash used in financing activities of $398 million for the same period of 2011. The change related to a shift from the Company primarily repaying its Senior Notes during the first nine months of 2011 to the Company refinancing and borrowing on its revolving credit facility during the first nine months of 2012. Credit facility borrowings were approximately $1,015 million during the first nine months of 2012 with the majority of funds received used to finance working capital and acquisitions and to make tax payments. Repayments on debt during the first nine months of 2012 were $3 million compared to $374 million for the same period of 2011. During the fourth quarter of 2012, the Company will repay another $350 million of its Senior Notes. In addition, proceeds from stock options exercised were $111 million during the first nine months of 2012 compared to $94 million for the same period of 2011. The Company also increased its dividend slightly to $153 million during the first nine months of 2012 compared to $140 million for the same period of 2011.

The effect of the change in exchange rates on cash flows was a positive $5 million and a negative $10 million for the nine months ended September 30, 2012 and 2011, respectively.

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

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

Recently Issued Accounting Standards

Forward-Looking Statements

Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as "may," "will," "expect," "anticipate," "estimate," and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward-looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products, difficulties encountered in integrating mergers and acquisitions, and worldwide economic activity. You should also consider carefully the statements under "Risk Factors," as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. We recorded a foreign exchange loss in our income statement of approximately $6 million in the first nine months of 2012, compared to approximately an $8 million foreign exchange loss in the same period of the prior year. The gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods at September 30, 2012 (in millions, except contract rates):


	As of September 30, 2012										December 31,
Functional Currency	2012			2013		2014		Total			2011
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		504			—		—		504			274
Average USD to CAD contract rate		0.9811			—		—		0.9811			1.0315
Fair Value at September 30, 2012 in U.S. dollars		2			—		—		2			(3	)
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		109			178		—		287			239
Average USD to CAD contract rate		1.0234			1.0350		—		1.0234			1.0196
Fair Value at September 30, 2012 in U.S. dollars		2			8		—		10			(1	)
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		1			3		—		4			10
Average USD to EUR contract rate		1.2930			1.2946		—		1.2930			1.4035
Fair Value at September 30, 2012 in U.S. dollars		—			—		—		—			1
Sell USD/Buy EUR:
Notional amount to buy (in euros)		96			94		3		193			120
Average USD to EUR contract rate		1.2982			1.2809		1.2388		1.2982			1.3846
Fair Value at September 30, 2012 in U.S. dollars		(3	)		1		—		(2	)		(11	)
KRW Buy USD/Sell KRW:
Notional amount to buy (in South Korean won)		—			260		—		260			385
Average USD to KRW contract rate		—			919		—		919			920
Fair Value at September 30, 2012 in U.S. dollars		—			—		—		—			—
Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)		82			639		58		779			53,825
Average USD to KRW contract rate		1,024			1,020		941		1,024			1,152
Fair Value at September 30, 2012 in U.S. dollars		—			—		—		—			—
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		51			—		—		51			45
Average USD to GBP contract rate		1.6169			—		—		1.6169			1.5499
Fair Value at September 30, 2012 in U.S. dollars		—			—		—		—			—


	As of September 30, 2012											December 31,
Functional Currency	2012			2013			2014		Total			2011
GBP Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		21			26			—		47			44
Average USD to GBP contract rate		1.5603			1.5629			—		1.5603			1.5818
Fair Value at September 30, 2012 in U.S. dollars		1			1			—		2			(2	)
USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		26			15			—		41			27
Average DKK to USD contract rate		0.1767			0.1724			—		0.1767			0.1845
Fair Value at September 30, 2012 in U.S. dollars		(1	)		—			—		(1	)		(1	)
Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		283			367			21		671			710
Average EUR to USD contract rate		1.3118			1.3128			1.2656		1.3118			1.3783
Fair Value at September 30, 2012 in U.S. dollars		(6	)		(7	)		—		(13	)		(40	)
Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		21			6			—		27			15
Average GBP to USD contract rate		1.5888			1.5815			—		1.5888			1.5737
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		325			646			264		1,235			1,336
Average NOK to USD contract rate		0.1673			0.1672			0.1626		0.1673			0.1683
Fair Value at September 30, 2012 in U.S. dollars		10			22			14		46			(22	)
Buy MXN/Sell USD:
Notional amount to buy (in U.S. dollars)		7			—			—		7			—
Average MXN to USD contract rate		0.0719			—			—		0.0719			—
Fair Value at September 30, 2012 in U.S. dollars		1			—			—		1			—
Buy SGD/Sell USD:
Notional amount to buy (in U.S. dollars)		28			8			3		39			10
Average SGD to USD contract rate		0.8024			0.7865			0.7920		0.8024			0.7679
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
Sell CAD/Buy USD:
Notional amount to buy (in U.S. dollars)		2			—			—		2			—
Average CAD to USD contract rate		0.9877			—			—		0.9877			—
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		16			—			—		16			3
Average DKK to USD contract rate		0.1682			—			—		0.1682			0.1817
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		142			21			—		163			137
Average EUR to USD contract rate		1.3031			1.3263			—		1.3031			1.3517
Fair Value at September 30, 2012 in U.S. dollars		1			1			—		2			5
Sell GBP/Buy USD:
Notional amount to sell (in U.S. dollars)		9			—			—		9			—
Average GBP to USD contract rate		1.5853			—			—		1.5853			—
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		120			97			9		226			173
Average NOK to USD contract rate		0.1677			0.1672			0.6832		0.1677			0.1719
Fair Value at September 30, 2012 in U.S. dollars		(4	)		(4	)		—		(8	)		6
Sell SGD/Buy USD:
Notional amount to sell (in U.S. dollars)		9			—			—		9			2
Average SGD to USD contract rate		0.7986			—			—		0.7986			0.7674
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
Sell RUB/Buy USD:
Notional amount to sell (in U.S. dollars)		40			—			—		40			24
Average RUB to USD contract rate		0.0316			—			—		0.0316			0.0305
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
DKK Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		109			—			—		109			96
Average DKK to USD contract rate		0.1746			—			—		0.1746			0.1763
Fair Value at September 30, 2012 in U.S. dollars		—			—			—		—			—
Other Currencies
Fair Value at September 30, 2012 in U.S. dollars		1			7			—		8			(2	)

Total Fair Value at September 30, 2012 in U.S. dollars		4			29			14		47			(70	)

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $557 million and translation exposures totaling $258 million as of September 30, 2012 excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on the transactional exposures financial market risk sensitive instruments could affect net income by $36 million and the transactional exposures financial market risk sensitive instruments could affect the future fair value by $26 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, 2012 our borrowings consisted of $200 million in 5.65% Senior Notes, $150 million in 5.5% Senior Notes and $151 million in 6.125% Senior Notes, and $1,015 million in borrowings under our revolving credit facility. Occasionally a portion of borrowings under our credit facility could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to six months. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.

Item 4. Controls and Procedures

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

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

PART II — OTHER INFORMATION

Item 4. Mine Safety Disclosures

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

Item 6. Exhibits

Reference is hereby made to the Exhibit Index commencing on page 35.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

INDEX TO EXHIBITS

(a)

Exhibits


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

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

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

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

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

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

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

10.4		National Oilwell Varco Long-Term Incentive Plan, as amended and restated. (5)*

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

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

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

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

10.9		Credit Agreement, dated as of September 28, 2012, 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. (Exhibit 10.1) (10)

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

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

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

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

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

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

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

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

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

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



31.1		Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.

31.2		Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.

32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

101		The following materials from our Quarterly Report on Form 10-Q for the period ended September 30, 2012 formatted in eXtensible Business Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (13)

*	Compensatory plan or arrangement for management or others.

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

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

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

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

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

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

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

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

(9)	Filed as an Exhibit to our Current Report on Form 8-K filed on August 17, 2011.

(10)	Filed as an Exhibit to our Current Report on Form 8-K filed on October 1, 2012.

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

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

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

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