UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

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

Commission File Number 1-12317

NATIONAL OILWELL VARCO, INC.

(Exact name of registrant as specified in its charter)

Delaware		76-0475815
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

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

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

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

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

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

As of November 2, 2009 the registrant had 418,336,718 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,
		2009				2008
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	3,192			$	1,543
Receivables, net			2,204				3,136
Inventories, net			3,767				3,806
Costs in excess of billings			612				618
Deferred income taxes			227				271
Prepaid and other current assets			405				283
Total current assets			10,407				9,657
Property, plant and equipment, net			1,753				1,677
Deferred income taxes			189				126
Goodwill			5,405				5,225
Intangibles, net			4,103				4,300
Investment in unconsolidated affiliate			389				421
Other assets			116				73
Total assets		$	22,362			$	21,479
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	510			$	852
Accrued liabilities			2,454				2,376
Billings in excess of costs			1,615				2,161
Current portion of long-term debt and short-term borrowings			9				4
Accrued income taxes			401				230
Total current liabilities			4,989				5,623
Long-term debt			875				870
Deferred income taxes			2,098				2,134
Other liabilities			121				128
Total liabilities			8,083				8,755
Commitments and contingencies
Stockholders’ equity:
Common stock — par value $.01; 418,281,455 and 417,350,924 shares issued and outstanding at September 30, 2009 and December 31, 2008			4				4
Additional paid-in capital			8,203				7,989
Accumulated other comprehensive income (loss)			92				(161	)
Retained earnings			5,871				4,796
Total Company stockholders’ equity			14,170				12,628
Noncontrolling interests			109				96
Total stockholders’ equity			14,279				12,724
Total liabilities and stockholders’ equity		$	22,362			$	21,479

See notes to unaudited consolidated financial statements.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Revenue		$	3,087			$	3,611			$	9,578			$	9,621
Cost of revenue			2,196				2,511				6,773				6,743
Gross profit			891				1,100				2,805				2,878
Selling, general and administrative			279				310				932				812
Intangible asset impairment			—				—				147				—
Transaction and restructuring costs			11				—				19				16
Operating profit			601				790				1,707				2,050
Interest and financial costs			(14	)			(19	)			(40	)			(53	)
Interest income			4				11				8				37
Equity income in unconsolidated affiliate			1				20				45				37
Other income (expense), net			(13	)			15				(87	)			14
Income before income taxes			579				817				1,633				2,085
Provision for income taxes			192				264				551				707
Net income			387				553				1,082				1,378
Net income attributable to noncontrolling interests			2				5				7				11
Net income attributable to Company		$	385			$	548			$	1,075			$	1,367
Net income attributable to Company per share:
Basic		$	0.93			$	1.32			$	2.58			$	3.49
Diluted		$	0.92			$	1.31			$	2.58			$	3.48
Weighted average shares outstanding:
Basic			416				416				416				391
Diluted			418				418				417				393

See notes to unaudited consolidated financial statements.

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

		Nine Months Ended
		September 30,
		2009				2008
Cash flows from operating activities:
Net income		$	1,082			$	1,378
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			364				284
Excess tax benefit from exercise of stock options			—				(37	)
Equity income in unconsolidated affiliate			(45	)			(37	)
Dividend from unconsolidated affiliate			86				—
Intangible asset impairment			147				—
Other			(53	)			36
Change in operating assets and liabilities, net of acquisitions:
Receivables			979				(596	)
Inventories			103				(450	)
Costs in excess of billings			7				(10	)
Prepaid and other current assets			(122	)			69
Accounts payable			(384	)			201
Billings in excess of costs			(545	)			749
Other assets/liabilities, net			350				119
Net cash provided by operating activities			1,969				1,706
Cash flows from investing activities:
Purchases of property, plant and equipment			(186	)			(264	)
Business acquisitions, net of cash acquired			(392	)			(2,988	)
Business divestitures, net of cash disposed			251				801
Dividend from unconsolidated affiliate			8				113
Other, net			—				(1	)
Net cash used in investing activities			(319	)			(2,339	)
Cash flows from financing activities:
Borrowings against lines of credit and other debt			7				2,728
Payments against lines of credit and other debt			(35	)			(2,281	)
Proceeds from exercise of stock options			3				84
Excess tax benefit from exercise of stock options			—				37
Net cash provided by (used in) financing activities			(25	)			568
Effect of exchange rates on cash			24				(12	)
Increase (decrease) in cash equivalents			1,649				(77	)
Cash and cash equivalents, beginning of period			1,543				1,842
Cash and cash equivalents, end of period		$	3,192			$	1,765
Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest		$	37			$	52
Income taxes		$	603			$	921

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 2008 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, 2009 are not necessarily indicative of the results to be expected for the full year. The Company has evaluated subsequent events for potential recognition or disclosure in the consolidated financial statements included through November 5, 2009.

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. Grant Prideco Merger and Other Acquisitions

The Grant Prideco merger was accounted for as a purchase business combination. Assets acquired and liabilities assumed were recorded at their fair values as of April 21, 2008. The total purchase price is $7,199 million, including Grant Prideco stock options assumed and acquisition related transaction costs and is comprised of (in millions):

Consideration given to acquire the outstanding common stock of Grant Prideco:
Shares issued totaled approximately 56.9 million shares at $72.74 per share		$	4,135
Cash paid at $23.20 per share			2,932
Grant Prideco stock options assumed			55
Merger related transaction costs			77
Total purchase price		$	7,199

Purchase Price Allocation

The following table, set forth below, displays the total purchase price allocated to Grant Prideco’s net tangible and identifiable intangible assets based on their fair values as of April 21, 2008 (in millions):

Cash and cash equivalents		$	171
Receivables			420
Assets held for sale, net			784
Inventories			611
Prepaid and other current assets			210
Property, plant and equipment			392
Goodwill			2,772
Intangibles			3,696
Investment in unconsolidated affiliate			512
Other assets			98
Accounts payable and accrued liabilities			(316	)
Accrued income taxes			(624	)
Long-term debt			(176	)
Deferred income taxes			(1,305	)
Minority interest			(25	)
Other liabilities			(21	)
Total purchase price		$	7,199

Unaudited Pro Forma Financial Information

The unaudited financial information in the table below summarizes the combined results of operations of National Oilwell Varco and Grant Prideco, on a pro forma basis, as though the companies had been combined as of the beginning of 2008. The pro forma financial information is presented for informational purposes only and may not be indicative of the results of operations that would have been achieved if the merger had taken place at the beginning of 2008. The pro forma financial information for the three and nine months ended September 30, 2008 includes the business combination accounting effect on historical Grant Prideco revenues, adjustments to depreciation on acquired property, amortization charges from acquired intangible assets, financing costs on new debt in connection with the merger and related tax effects. (in millions, except per share data):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Total revenues		$	3,087			$	3,611			$	9,578			$	10,225
Net income attributable to Company		$	385			$	568			$	1,075			$	1,495
Basic net income attributable to Company per share		$	0.93			$	1.37			$	2.58			$	3.61
Diluted net income attributable to Company per share		$	0.92			$	1.36			$	2.58			$	3.59

Other Acquisitions

In the nine months ended September 30, 2009, the Company completed five acquisitions for an aggregate purchase price of $392 million, net of cash acquired. These acquisitions included:

	•		The shares of ASEP Group Holding B.V., a Netherlands-based manufacturer of well service equipment.
	•		The shares of ANS (1001) Ltd. (“Anson”), a U.K.-based manufacturer of pumps and fluid expendibles.
	•		The business and assets of Spirit Drilling Fluids Ltd., a U.S.-based company that provides drilling fluids and related well-site services to exploration and production companies.
	•		The business and assets of Spirit Minerals L.P., a U.S.-based company that mines, processes and distributes barite to the oil and gas drilling fluid industry.

From the dates of acquisition, the results of operations from ASEP are included in the Rig Technology segment and the results of operations from Anson, Spirit Drilling Fluids, and Spirit Minerals are included in the Petroleum Services & Supplies segment. The impact of these acquisitions was not material to the consolidated financial statements.

3. IntelliServ Joint Venture

In September 2009, the Company sold 45 percent of certain of its IntelliServ operations and created the IntelliServ Joint Venture (“IntelliServ”). IntelliServ provides drilling technology that enables downhole drilling conditions to be measured, evaluated and monitored.

4. Asset Impairment

Generally accepted accounting principles require the Company to test goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that such assets might be impaired.

During the second quarter of 2009, the worldwide average rig count was 2,009 rigs, down 41% from the fourth quarter 2008 average of 3,395 and down 25% from the first quarter 2009 average of 2,681. The second quarter 2009 average rig count represented the lowest quarterly average in the past six years. In addition, the Company’s updated forecast was behind the Company’s previous forecast completed at the beginning of 2009. While operating profit for the first quarter of 2009 was in line with the Company’s first quarter 2009 operating profit forecast, the Company’s consolidated operating profit for the second quarter of 2009 was below its second quarter 2009 forecast. As a result of the substantial decline in the worldwide rig count, and the decline in actual/forecasted results compared to the original 2009 forecast, the Company concluded that events or circumstances had occurred indicating that goodwill and other indefinite-lived intangible assets might be impaired as described under SFAS 142, which was primarily codified into ASC Topic 350, “Intangibles — Goodwill and Other” (“ASC Topic 350”).

Therefore, the Company performed its interim impairment test of goodwill for all its reporting units at the end of the second quarter of 2009. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Fair value of the reporting units is determined in accordance with SFAS 157, which was primarily codified into ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”), using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on internal management estimates, forecasts and judgments, using a combination of three methods: discounted cash flow, comparable companies, and representative transactions. While the Company primarily uses the discounted cash flow method to assess fair value, the Company uses the comparable companies and representative transaction methods to validate the discounted cash flow analysis and further support management’s expectations, where possible.

The discounted cash flow is based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in measuring goodwill impairment, which bear the risk of change and could impact the Company’s goodwill impairment analysis, include the cash flow from operations from each of the Company’s individual business units and the weighted average cost of capital. The starting point for each of the reporting unit’s cash flow

from operations is the detailed annual plan or updated forecast. The detailed planning and forecasting process takes into consideration a multitude of factors including worldwide rig activity, inflationary forces, pricing strategies, customer analysis, operational issues, competitor analysis, capital spending requirements, working capital needs, customer needs to replace aging equipment, increased complexity of drilling, new technology, and existing backlog among other items which impact the individual reporting unit projections. Cash flows beyond the specific operating plans were estimated using a terminal value calculation, which incorporated historical and forecasted financial cyclical trends for each reporting unit and considered long-term earnings growth rates. The financial and credit market volatility directly impacts our fair value measurement through our weighted average cost of capital that we use to determine our discount rate. During times of volatility, significant judgment must be applied to determine whether credit changes are a short-term or long-term trend.

Projections for the remainder of 2009 also reflected declines compared to the original 2009 annual forecast. The Company updated its 2009 operating forecast, long-term forecast, and discounted cash flows based on this information. The goodwill impairment analysis that we performed during the second quarter of 2009 did not result in goodwill impairment as of June 30, 2009.

Other indefinite-lived intangible assets, representing trade names management intends to use indefinitely, were valued using significant unobservable inputs (level 3) and are tested for impairment using the Relief from Royalty Method, a form of the Income Approach. An impairment is measured and recognized based on the amount the book value of the indefinite-lived intangible assets exceeds its estimated fair value as of the date of the impairment test. Included in the impairment test are assumptions, for each trade name, regarding the related revenue streams attributable to the trade names which are determined consistent with the forecasting process described above, the royalty rate, and the discount rate applied. Based on the Company’s indefinite-lived intangible asset impairment analysis performed during the second quarter of 2009, the Company incurred an impairment charge of $147 million in the Petroleum Services & Supplies segment related to a partial impairment of the Company’s Grant Prideco trade name. The impairment charge was primarily the result of the substantial decline in worldwide rig counts through June 2009, declines in current forecasts in rig activity for the remainder of 2009, 2010, and 2011 compared to rig count forecast at the beginning of 2009, and a current decline in the revenue forecast for the drill pipe business unit for the remainder of 2009, 2010, and 2011.

5. Inventories, net

Inventories consist of (in millions):

		September 30,				December 31,
		2009				2008
Raw materials and supplies		$	762			$	739
Work in process			1,646				1,326
Finished goods and purchased products			1,359				1,741
Total		$	3,767			$	3,806

6. Accrued Liabilities

Accrued liabilities consist of (in millions):

		September 30,				December 31,
		2009				2008
Compensation		$	225			$	258
Customer prepayments and billings			455				912
Warranty			185				114
Interest			16				11
Taxes (non income)			66				76
Insurance			59				50
Accrued purchase orders			1,166				688
Fair value of derivatives			81				59
Other			201				208
Total		$	2,454			$	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 SFAS 5, which was primarily codified into 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, December 31, 2008		$	114
Net provisions for warranties issued during the year			86
Amounts incurred			(35	)
Foreign currency translation and other			20
Balance, September 30, 2009		$	185

7. Costs and Estimated Earnings on Uncompleted Contracts

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

		September 30,				December 31,
		2009				2008
Costs incurred on uncompleted contracts		$	6,372			$	4,776
Estimated earnings			3,453				2,277
			9,825				7,053
Less: Billings to date			10,828				8,596
		$	(1,003	)		$	(1,543	)
Costs and estimated earnings in excess of billings on uncompleted contracts		$	612			$	618
Billings in excess of costs and estimated earnings on uncompleted contracts			(1,615	)			(2,161	)
		$	(1,003	)		$	(1,543	)

8. Comprehensive Income

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Net income		$	387			$	553			$	1,082			$	1,378
Currency translation adjustments, net of tax			22				(71	)			79				(33	)
Changes in derivative financial instruments, net of tax			69				(86	)			174				(65	)
Changes in defined benefit plans, net of tax			1				—				—				—
Comprehensive income			479				396				1,335				1,280
Comprehensive income attributable to noncontrolling interest			2				5				7				11
Comprehensive income attributable to Company		$	477			$	391			$	1,328			$	1,269

The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in Other Comprehensive Income in accordance with SFAS 52, “Foreign Currency Translation”, which was primarily codified into ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three months ended September 30, 2009, a majority of these local currencies strengthened against the U.S. dollar resulting in a net increase to Other Comprehensive Income of $22 million (net of tax of $12 million) upon the translation of their financial statements from their local currency to the U.S. dollar.

The effect of changes in the fair values of derivatives designated as Cash Flow hedges are accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of accumulated Other Comprehensive Income related to the fair value of derivatives that have settled in the current or prior periods. The accumulated effects of these scenarios have caused an increase in Other Comprehensive Income of $69 million (net of tax of $28 million) for the three months ended September 30, 2009.

9. Business Segments

Operating results by segment are as follows (in millions). The 2008 actual results include Grant Prideco operations from the acquisition date of April 21, 2008:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Revenue:
Rig Technology		$	2,000			$	1,926			$	6,116			$	5,440
Petroleum Services & Supplies			882				1,310				2,809				3,264
Distribution Services			306				498				1,019				1,289
Elimination			(101	)			(123	)			(366	)			(372	)
Total Revenue		$	3,087			$	3,611			$	9,578			$	9,621
Operating Profit:
Rig Technology (a)		$	577			$	501			$	1,717			$	1,413
Petroleum Services & Supplies (b) (c)			82				302				195				718
Distribution Services			7				43				42				87
Unallocated expenses and eliminations (d)			(54	)			(56	)			(228	)			(152	)
Transaction and restructuring costs			(11	)			—				(19	)			(16	)
Total Operating Profit		$	601			$	790			$	1,707			$	2,050
Operating Profit %:
Rig Technology (a)			28.9	%			26.0	%			28.1	%			26.0	%
Petroleum Services & Supplies (b) (c)			9.3	%			23.0	%			6.9	%			22.0	%
Distribution Services			2.3	%			8.8	%			4.1	%			6.8	%
Total Operating Profit %			19.5	%			21.9	%			17.8	%			21.3	%

The Company had revenues of 16.7% of total revenue from one of its customers for the nine months ended September 30, 2009. This customer 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.

10. Debt

Debt consists of (in millions):

		September 30,				December 31,
		2009				2008
Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011		$	150			$	150
Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011			206				208
Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012			200				200
Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012			151				151
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015			151				151
Other			26				14
Total debt			884				874
Less current portion			9				4
Long-term debt		$	875			$	870

Senior Notes

In connection with the merger of Grant Prideco, the Company completed an exchange offer relative to the $175 million of 6.125% Senior Notes due 2015 previously issued by Grant Prideco. On April 21, 2008, $151 million of Grant Prideco Senior Notes were exchanged for National Oilwell Varco Senior Notes. The National Oilwell Varco Senior Notes have the same interest rate, interest payment dates, redemption terms and maturity as the Grant Prideco Senior Notes. In November 2008, the Company repurchased $23 million of the unexchanged Grant Prideco Senior Notes.

Revolving Credit Facilities

On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2 billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility. At September 30, 2009, there were no borrowings against these facilities, and there were $589 million in outstanding letters of credit issued under these facilities, resulting in $1,411 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% subject to a ratings-based grid, or the prime rate. In early February 2009, we terminated early the $1 billion, 364-day revolving credit facility, which matured April 20, 2009.

The Company also had $2,234 million of additional outstanding letters of credit at September 30, 2009, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. We were in compliance with all covenants at September 30, 2009.

Other

Other debt includes approximately $4 million in promissory notes due to former owners of businesses acquired who remain employed by the Company.

11. Tax

The effective tax rate for the three and nine months ended September 30, 2009 was 33.2% and 33.7%, respectively, compared to 32.3% and 33.9% for the same periods in 2008. The nine months 2009 tax rate includes $21 million of additional tax provision recognized in the second quarter 2009 on prior year income in Norway. These additional taxes resulted from foreign currency gains on dollar-denominated accounts that were realized for Norwegian tax purposes.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Federal income tax at U.S. federal statutory rate		$	203			$	286			$	572			$	730
Foreign income tax rate differential			(23	)			(29	)			(81	)			(72	)
State income tax, net of federal benefit			4				9				12				26
Foreign dividends, net of foreign tax credits			3				(1	)			10				33
Benefit of U.S. Manufacturing Deduction			(6	)			(7	)			(13	)			(13	)
Prior year tax on revaluation gains in Norway			—				—				21				—
Other			11				6				30				3
Provision for income taxes		$	192			$	264			$	551			$	707

The Company accounts for uncertainty in income taxes in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB No. 109” (“FIN 48”) , which was primarily codified into ASC Topic 740, “Income Taxes”. (“ASC Topic 740”) FIN 48/ASC Topic 740 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”, which was primarily codified into ASC Topic 740, and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a return. Under FIN 48/ASC Topic 740, the impact of an uncertain income tax position, in management’s opinion, on the income tax return must be recognized at the largest amount that is more-likely-than not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has a less than 50% likelihood of being sustained.

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

Balance at January 1, 2009		$	61
Additions based on tax positions related to the current year			5
Additions for tax positions of prior years			6
Reductions for lapse of applicable statutes of limitations			(2	)
Settlements			(11	)
Balance at September 30, 2009		$	59

The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The Company has significant operations in the U.S., Canada, the U. K., the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdiction vary by legal entity, but are generally open in the U.S. for the tax years after 2005 and outside the U.S. for tax years ending after 2002.

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

12. 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. During the second quarter of 2009, the Company with approval from shareholders increased the number of shares authorized under the Plan from 15 million to 26 million. As of September 30, 2009, 11,890,826 shares remain available for future grants under the Plan, all of which are available for grants of stock options, performance-based share awards, restricted stock awards, phantom shares, stock payments and stock appreciation rights. Total stock-based compensation for all share-based compensation arrangements under the Plan was $15 million and $46 million for the three and nine months ended September 30, 2009, respectively, and $23 million and $52 million for the three and nine months ended September 30, 2008, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $5 million and $17 million for the three and nine months ended September 30, 2009, respectively, and $5 million and $16 million for the three and nine months ended September 30, 2008, respectively.

During the nine months ended September 30, 2009, the Company granted 3,234,400 stock options and 762,692 restricted stock awards, which includes 309,000 performance-based restricted stock awards. Out of the total number of stock options granted, 3,206,400 were granted on February 20, 2009 with an exercise price of $25.96. These options generally vest over a three-year period from the grant date. The remaining 28,000 options were granted May 13, 2009 to the non-employee members of the Board of Directors at an exercise price of $33.57. These options generally vest over a three-year period from the grant date. Out of the total number of restricted stock awards granted, 434,400 were granted on February 20, 2009 and vest on the third anniversary of the date of grant. On May 13, 2009, 19,292 restricted stock awards were granted to the non-employee members of the Board of Directors. These restricted stock awards vest in equal thirds over three years on the anniversary of the grant date. The performance-based restricted stock awards of 309,000 were granted on February 20, 2009. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s average operating income growth, measured on a percentage basis, from January 1, 2009 through December 31, 2011 exceeding the median operating income level growth of a designated peer group over the same period.

13. Derivative Financial Instruments

The Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”), which was primarily codified into ASC Topic 815, “Derivatives and Hedging”. (“ASC Topic 815”) This Standard requires companies to recognize all of its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.

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

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

At September 30, 2009, the Company has determined that its financial assets of $150 million and liabilities of $64 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At September 30, 2009, the fair value of the Company’s foreign currency forward contracts totaled $86 million.

As of September 30, 2009, the Company did not have any interest rate swaps and our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

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

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

As of September 30, 2009, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and costs:

					Currency
Foreign Currency					Denomination
					(in millions)
British Pound Sterling						£	40
Danish Krone						DKK	201
Euro						€	220
Norwegian Krone						NOK	6,896
U.S. Dollar						$	137
Korean Won						KRW	5,170

Fair Value Hedging Strategy

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

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

As of September 30, 2009, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency fair values of firm commitments of revenues and costs:

		Currency
Foreign Currency		Denomination
		(in millions)
U.S. Dollar		$	42

Non-designated Hedging Strategy

For derivative instruments that are non-designated, the gain or loss on the derivative instrument subject to the hedged risk (i.e. nonfunctional currency monetary accounts) are recognized in the same line item associated with the hedged item in current earnings.

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

As of September 30, 2009, the Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts:

					Currency
Foreign Currency					Denomination
					(in millions)
British Pound Sterling						£	7
Danish Krone						DKK	180
Euro						€	121
Norwegian Krone						NOK	4,590
Swedish Krone						SEK	5
U.S. Dollar						$	571
Korean Won						KRW	496

As of September 30, 2009, 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)

		September 30, 2009
		Asset Derivatives						Liability Derivatives
		Balance Sheet		Fair				Balance Sheet		Fair
		Location		Value				Location		Value
Derivatives designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets		$	73			Accrued liabilities		$	22
Foreign exchange contracts		Other Assets			30			Other Liabilities			2
Total derivatives designated as hedging instruments under ASC Topic 815				$	103					$	24
Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets		$	43			Accrued liabilities		$	39
Foreign exchange contracts		Other Assets			4			Other Liabilities			1
Total derivatives not designated as hedging instruments under ASC Topic 815				$	47					$	40
Total derivatives				$	150					$	64

The Effect of Derivative Instruments on the Consolidated Statement of Income
Periods Ended September 30, 2009
($ 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)

September 30, 2009

September 30, 2009

September 30, 2009

Three Months

Nine Months

Three Months

Nine Months

Three Months

Nine Months

Ended

Ended

Ended

Ended

Ended

Ended

Revenue

8

18

Foreign exchange contracts

88

162

Cost of revenue

(7

)

(51

)

Other income(expense), net

(3

)

(27

)

Total

88

162

1

(33

)

(3

)

(27

)

Derivatives in ASC Topic 815

Location of Gain (Loss)

Amount of Gain (Loss)

ASC Topic 815

Location of Gain (Loss)

Recognized in Income on

Fair Value

Recognized in Income

Recognized in Income on

Fair Value Hedge

Recognized in Income on

Related Hedged

Hedging Relationships

on Derivative

Derivative

Relationships

Related Hedged Item

Items

September 30, 2009

September 30, 2009

Three Months

Nine Months

Three Months

Nine Months

Ended

Ended

Ended

Ended

Foreign exchange contracts

Revenue

(3

)

(5

)

Firm commitments

Revenue

3

5

Foreign exchange contracts

Cost of revenue

2

1

Firm commitments

Cost of revenue

(2

)

(1

)

Total

(1

)

(4

)

1

4

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 (a)

Foreign exchange contracts

Other income (expense), net

10

(14

)

Total

10

(14

)

We assess the functional currencies of our operating units to ensure that the appropriate currencies are utilized in accordance with the guidance of SFAS No. 52, Foreign Currency Translation, which was primarily codified into ASC Topic 830. Effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian krone to the U.S. dollar to more appropriately reflect the primary economic environment in which they operate. This change was precipitated by significant changes in the economic facts and circumstances, including the increased order rate for large drilling platforms and components technology, the use of our Norway unit as our preferred project manager of these projects, increasing revenue and cost base in U.S. dollars, and the implementation of an international cash pool denominated in U.S. dollars. As a Norwegian krone functional unit, Norway was subject to increasing foreign currency exchange risk as a result of these changes in its economic environment and was dependent upon significant hedging transactions to offset its non-functional currency positions.

At December 31, 2007, our Norway operations had foreign currency forward contracts with notional amounts aggregating $2,551 million with a fair value of $91 million to mitigate foreign currency exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the functional currency, the Company terminated these hedges. The related net gain position of $109 million associated with the terminated hedges was deferred and is being recognized into earnings in the future period(s) the forecasted transactions affect earnings, of which $15 million remains to be recognized into earnings at September 30, 2009. The Company has, subsequent to January 1, 2008, entered into new hedges to cover the exposures as a result of the change to U.S. dollar functional. At September 30, 2009, our Norway operations had derivatives with $2,431 million in notional value with a fair value asset of $82 million.

14. Net Income Attributable to Company Per Share

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Numerator:
Net income attributable to Company		$	385			$	548			$	1,075			$	1,367
Denominator:
Basic—weighted average common shares outstanding			416				416				416				391
Dilutive effect of employee stock options and other unvested stock awards			2				2				1				2
Diluted outstanding shares			418				418				417				393
Net income attributable to Company per share:
Basic		$	0.93			$	1.32			$	2.58			$	3.49
Diluted		$	0.92			$	1.31			$	2.58			$	3.48

In addition, the Company had stock options outstanding that were anti-dilutive totaling 4 million and 6 million shares for the three and nine months ended September 30, 2009, respectively, and 1 million shares for both the three and nine months ended September 30, 2008, respectively.

15. Recently Issued Accounting Standards

In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) SFAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”), which defers the effective date of SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), as it related to non-financial assets and non-financial liabilities, to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. Both standards mentioned above were primarily codified into ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”). The Company, as of January 1, 2009, adopted the provisions of this statement and included the appropriate disclosures surrounding non-financial assets and liabilities, as applicable.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”), which was primarily codified into ASC Topic 850, “Business Combinations” (“ASC Topic 850”). ASC Topic 850 provides revised guidance on how acquirers recognize and measure the consideration transferred, identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired in a business combination. ASC Topic 850 also expands required disclosures surrounding the nature and financial effects of business combinations. ASC Topic 850 is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC Topic 850. The Company expects that this new standard will impact certain aspects of its accounting for business combinations on a prospective basis, including the determination of fair values assigned to certain purchased assets and liabilities.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160’), which was primarily codified into ASC Topic 810, “Consolidations” (“ASC Topic 810”). ASC Topic 810 establishes requirements for ownership interests in subsidiaries held by parties other than the Company (previously called minority interests) be clearly identified, presented, and disclosed in the consolidated statement of financial position within equity, but separate from the parent’s equity. All changes in the parent’s ownership interests are required to be accounted for consistently as equity transactions and any noncontrolling equity investments in deconsolidated subsidiaries must be measured initially at fair value. ASC Topic 810 is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. However, presentation and disclosure requirements must be retrospectively applied to comparative financial statements. On January 1, 2009, the Company adopted ASC Topic 810, and reclassified noncontrolling interests in the amounts of $109 million and $96 million from the mezzanine section to equity in the September 30, 2009 and December 31, 2008 balance sheets, respectively.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161’), which was primarily codified into ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”). ASC Topic 815 amends and expands the disclosure requirements for derivative instruments and hedging activities, with the intent to provide users of financial statements with an enhanced understanding of how and why an

entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial statements. ASC Topic 815 is effective for fiscal years and interim periods beginning after November 15, 2008. On January 1, 2009, the Company adopted ASC Topic 815. See Note 11. “Derivative Financial Instruments”, in the notes to the consolidated financial statements.

In April 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3’), which was primarily codified into ASC Topic 350, “Intangibles — Goodwill and Other” (“ASC Topic 350”). ASC Topic 350 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets”. The objective of this ASC is to improve the consistency between the useful life of a recognized intangible asset under Statement No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R and other U.S. GAAP principles. ASC Topic 350 is effective for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC Topic 350. There was no significant impact to the Company’s consolidated financial statements from the adoption of ASC Topic 350.

In April 2009 the FASB issued FSP 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141R-1”), which was primarily codified into ASC Topic 850, “Business Combinations” (“ASC Topic 850”). ASC Topic 850 amends the provisions in SFAS 141R for the initial recognition and measurement, subsequent measurement and accounting, and disclosures for assets and liabilities arising from contingencies in business combinations. The ASC eliminates the distinction between contractual and non-contractual contingencies, including the initial recognition and measurement criteria in SFAS 141R and instead carries forward most of the provisions in SFAS 141 for acquired contingencies. ASC Topic 850 is effective for contingent assets and contingent liabilities acquired in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company expects ASC Topic 850 will have a future impact on its consolidated financial statements, but the nature and magnitude of the specific effects will depend upon the nature, term and size of the acquired contingencies.

In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP SFAS 107-1”), which was primarily codified into ASC Topic 825, “Financial Instruments” (“ASC Topic 825”). ASC Topic 825 extends the disclosure requirements regarding the fair value of financial instruments under SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (“SFAS No. 107”), to interim financial statements of publicly traded companies. ASC Topic 825 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Early adoption of this ASC is permitted only if the entity also elects to early adopt FSP SFAS 157-4 and FSP SFAS 115-2. On June 1, 2009, the Company adopted ASC Topic 825. There was no significant impact to the Company’s consolidated financial statements from the adoption of ASC Topic 825.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”), which was primarily codified into ASC Topic 855, “Subsequent Events” (“ASC Topic 855”). ASC Topic 855 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. ASC Topic 855 is effective for fiscal years and interim periods ending after June 15, 2009. On June 1, 2009, the Company adopted ASC Topic 855. There was no significant impact to the Company’s consolidated financial statements from the adoption of ASC Topic 855.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (SFAS 168”), which amends SFAS 162, “The Hierarchy of Generally Accepted Accounting Principles.” Both of these standards were primarily codified into ASC Topic 105, “Generally Accepted Accounting Standards” (“ASC Topic 105”). The ASC will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date, ASC Topic 105 will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the ASC will become non-authoritative. ASC Topic 105 is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

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

Introduction

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

Rig Technology

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

Petroleum Services & Supplies

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

Distribution Services

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

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2008, 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 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.

Goodwill and Other Indefinite — Lived Intangible Assets

The Company has approximately $5.5 billion of goodwill and $0.6 billion of other intangible assets with indefinite lives on its consolidated balance sheet as of September 30, 2009. The Company tests goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that goodwill or other indefinite-lived intangible assets might be impaired. The annual impairment test is performed during the fourth quarter of each year. Based on its analysis, the Company did not report any impairment of goodwill and other indefinite-lived intangible assets for the year ended December 31, 2008. As described below, the Company concluded that an indicator of impairment did occur in the second quarter of 2009 and updated its impairment testing at June 30, 2009. Based on its updated analysis, the Company concluded that it did not incur an impairment of goodwill for the period ending June 30, 2009. However, based on the Company’s indefinite-lived intangible asset impairment analysis performed during the second quarter of 2009, the Company concluded that it did incur an impairment charge to certain indefinite-lived intangible assets of $147 million at June 30, 2009. The $147 million impairment charge is included in the Company’s consolidated income statement for the nine months ended September 30, 2009.

During the second quarter of 2009, the worldwide average rig count was 2,009 rigs, down 41% from the fourth quarter 2008 average of 3,395 and down 25% from the first quarter 2009 average of 2,681. The second quarter 2009 average rig count represented the lowest quarterly average in the past six years. In addition, the Company’s updated forecast was behind the Company’s previous forecast completed at the beginning of 2009. While operating profit for the first quarter of 2009 was in line with the Company’s first quarter 2009 operating profit forecast, the Company’s consolidated operating profit for the second quarter of 2009 was below its second quarter 2009 forecast. As a result of the substantial decline in the worldwide rig count, and the decline in actual/forecasted results compared to the original 2009 forecast, the Company concluded that events or circumstances had occurred indicating that goodwill and other indefinite-lived intangible assets might be impaired as described under ASC Topic 350.

Therefore, the Company performed its interim impairment test of goodwill for all its reporting units at the end of the second quarter of 2009. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Fair value of the reporting units is determined in accordance with ASC Topic 820 using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on internal management estimates, forecasts and judgments, using a combination of three methods: discounted cash flow, comparable companies, and representative transactions. While the Company primarily uses the discounted cash flow method to assess fair value, the Company uses the comparable companies and representative transaction methods to validate the discounted cash flow analysis and further support management’s expectations, where possible.

The discounted cash flow is based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in measuring goodwill impairment, which bear the risk of change and could impact the Company’s goodwill impairment analysis, include the cash flow from operations from each of the Company’s individual business units and the weighted average cost of capital. The starting point for each of the reporting unit’s cash flow from operations is the detailed annual plan or updated forecast. The detailed planning and forecasting process takes into consideration a multitude of factors including worldwide rig activity, inflationary forces, pricing strategies, customer analysis, operational issues, competitor analysis, capital spending requirements, working capital needs, customer needs to replace aging equipment, increased complexity of drilling, new technology, and existing backlog among other items which impact the individual reporting unit projections. Cash flows beyond the specific operating plans were estimated using a terminal value calculation, which incorporated historical and forecasted financial cyclical trends for each reporting unit and considered long-term earnings growth rates. The financial and credit market volatility directly impacts our fair value measurement through our weighted average cost of capital that we use to determine our discount rate. During times of volatility, significant judgment must be applied to determine whether credit changes are a short-term or long-term trend.

Projections for the remainder of 2009 also reflected declines compared to the original 2009 annual forecast. The Company updated its 2009 operating forecast, long-term forecast, and discounted cash flows based on this information. The goodwill impairment analysis that we performed during the second quarter of 2009 did not result in goodwill impairment as of June 30, 2009.

The Company performed a sensitivity analysis on the projected results and goodwill impairment analysis assuming revenue for each individual reporting unit decreased an additional 20% from the current projections for each of the remainder of 2009, 2010, and 2011, while holding all other factors constant, and no goodwill impairment was identified for any of the reporting units. Additionally, if the Company were to increase its discount rate 100 basis points, while keeping all other assumptions constant, there would be no impairments in any of the reporting units. While the Company does not believe that these events (20% drop in additional revenue for the next three years or 100 basis point increases in weighted average costs of capital) or changes are likely to occur, it is reasonably possible these events could transpire if market conditions worsen and if the market fails to recover in 2010 and/or 2011. Any significant changes to these assumptions and factors could have a material impact on the Company’s goodwill impairment analysis. Inherent in our projections are key assumptions relative to how long the current downward cycle might last. While we believe these assumptions are reasonable and appropriate, we will continue to monitor these, and update our impairment analysis if the cycle downturn continues for longer than expected.

Other indefinite-lived intangible assets, representing trade names management intends to use indefinitely, were valued using significant unobservable inputs (level 3) and are tested for impairment using the Relief from Royalty Method, a form of the Income Approach. An impairment is measured and recognized based on the amount the book value of the indefinite-lived intangible assets exceeds its estimated fair value as of the date of the impairment test. Included in the impairment test are assumptions, for each trade name, regarding the related revenue streams attributable to the trade names which are determined consistent with the forecasting process described above, the royalty rate, and the discount rate applied. Based on the Company’s indefinite-lived intangible asset impairment analysis performed during the second quarter of 2009, the Company incurred an impairment charge of $147 million in the Petroleum Services & Supplies segment related to a partial impairment of the Company’s Grant Prideco trade name. The impairment charge was primarily the result of the substantial decline in worldwide rig counts through June 2009, declines in current forecasts in rig activity for the remainder of 2009, 2010, and 2011 compared to rig count forecast at the beginning of 2009 and a current decline in the revenue forecast for the drill pipe business unit for the remainder of 2009, 2010, and 2011.

The Company performed a sensitivity analysis on the projected results and indefinite-lived intangible asset impairment assuming revenue for each individual trade name decreased an additional 20% from the current projections for each of the remainder of 2009, 2010, and 2011, while holding all other factors constant, and a pre-tax non-cash impairment charge of approximately $79 million would be incurred under those assumptions. If the discount rate applied to the fair value calculation increased by 100 basis points, and all other assumptions remained constant, a pre-tax, non-cash impairment charge of approximately $36 million would be incurred under those assumptions.

The Company will continue to closely monitor indicators of impairment, which could include, but are not limited to, further declines in worldwide rig activity, further declines in commodity prices or futures, or further significant economic declines. If such further deterioration of indicators occurs, and the Company believes that these negative trends are likely to persist for a prolonged period of time, then the Company’s expected future earnings and cash flows from operations would be adversely impacted. This may result in impairment to either or both goodwill and indefinite-lived intangible assets, and such impairment may be material.

EXECUTIVE SUMMARY

National Oilwell Varco generated earnings of $385 million or $0.92 per fully diluted share in its third quarter ended September 30, 2009, on revenues of $3,087 million. Compared to the third quarter of 2008 revenue declined 15 percent and net income attributable to the Company declined 30 percent. Compared to the second quarter of 2009 revenue increased three percent and net income attributable to the Company increased 75 percent, due in large part to the non-recurrence of $203 million in pre-tax asset impairment, transaction, and voluntary retirement charges and a higher income tax rate recognized in the second quarter of 2009, in addition to higher third quarter sales and margins.

Operating profit was $601 million or 19.5 percent of sales for the third quarter. Excluding $11 million of transaction and restructuring charges, third quarter operating profit was $612 million or 19.8 percent of sales, compared to $589 million or 19.6 percent of sales in the second quarter of 2009 (excluding transaction and impairment charges), and $790 million or 21.9 percent of sales in the third quarter of 2008. Operating profit leverage or flow-through (the change in operating profit divided by the change in revenue period-to-period) was up 38 percent from the second quarter of 2009 to the third quarter of 2009, and down 38 percent from the third quarter of 2008 to the third quarter of 2009, excluding transaction, restructuring and impairment charges from all periods.

Oil & Gas Equipment and Services Market

Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks have responded vigorously, but credit and financial markets have not yet fully recovered, and a credit-driven worldwide economic recession deepened during the second quarter. Asset and commodity prices, including oil and gas prices, have declined sharply. After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to average $42.91 per barrel during the first quarter of 2009, but have been recovering steadily to average $68.20 during the third quarter of 2009. Higher oil and gas prices over the past several years led to high levels of exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit availability.

The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a low of 887 in June 2009. Rig count has increased slightly since, to 1,048 in October 2009, and averaged 974 rigs during the third quarter of 2009. Many oil and gas operators reliant on external financing to fund their drilling programs have significantly curtailed their drilling activity, which appears to have had the greatest impact on gas drilling across North America. Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings, but the international rig count has exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 986 in September 2009. During the third quarter of 2009 the Company saw its Petroleum Services & Supplies and its Distribution Services margins affected most acutely by a drilling downturn, through both volume and price declines, while the Company’s Rig Technology segment was less impacted owing to its high level of backlog.

Recent downturns follow 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 retool the existing fleet of jackup rigs (according to Offshore Data Services, 73 percent of the existing 445 jackup rigs are more than 25 years old); to replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and to 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, and that declining dayrates may accelerate the retirement of older rigs. As a result of these trends the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at March 31, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders have declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $7.3 billion by September 30, 2009.

Land rigs comprised 11 percent and equipment destined for offshore operations comprised 89 percent of the total backlog as of September 30, 2009. Equipment destined for international markets totaled 93 percent of the backlog. The Company believes that its existing contracts for rig equipment are very strong in that they carry significant down payment and progress billing terms favorable to the ultimate completion of these projects, and generally do not allow customers to cancel projects for convenience. During the third quarter of 2009 the Company removed $72 million in discontinued orders on cancelled projects and project change orders requested by customers. We do not expect the credit crisis or softer market to result in additional material cancelation of contracts or abandonment of major projects; however, there can be no assurance that such discontinuance of projects will not occur. The Company had approximately $334 million of projects in its September 30, 2009 backlog that it considers at risk.

Segment Performance

Rig Technology generated $2,000 million in revenue and $577 million in operating profit in the third quarter of 2009, producing a record operating margin for the segment of 28.9 percent. The segment generated 52 percent operating leverage or flow-through on four percent higher sales from the second quarter of 2009 to the third quarter of 2009. Compared to the prior year third quarter operating leverage or
flow-through was 105 percent on four percent sales growth. Revenue out of backlog of $1,599 million increased 12 percent sequentially and increased 17 percent compared to the third quarter of last year. Execution of the backlog orders was very strong, which led to higher margin performance for the Rig Technology segment in the third quarter due to excellent cost control, deflation in certain inputs, greater experience building and commissioning rigs which enables better efficiencies, and somewhat better FX movements. As a result our estimated costs to complete projects have declined steadily through 2009. As of September 30, 2009 the scheduled outflow of revenue from backlog is expected to be approximately $1.3 billion in the fourth quarter of 2009, $4.7 billion in 2010, and $1.3 billion for 2011. From 2005 through the current quarter, the segment has delivered a total of 66 newly built offshore rigs. Aftermarket spare parts and services revenue was essentially flat in the third quarter as compared to the second quarter, but sales of smaller capital items which do not qualify for the backlog declined sharply. Demand for offshore rigs and equipment is strongest in Brazil, owing to significant drilling equipment needs to develop new ultradeepwater discoveries, and the segment also continues to pursue a variety of new offshore rig, intervention vessel, FPSO and platform upgrade opportunities in other markets. However, tight credit markets and fewer committed term contracts for rigs by oil and gas companies as compared to market conditions in 2006-2008 are adversely affecting new orders, which totaled only $333 million in the third quarter. Demand for land rig and well stimulation equipment has also been very slow, except for the Middle East and certain Latin American markets. In particular demand for equipment in North America remains soft, although the Company’s first new Drake rigs delivered into the Marcellus shale play are performing well, and the Company believes acceptance of new technology land rigs continues to make steady progress.

The Petroleum Services & Supplies segment generated revenues of $882 million and operating profit of $82 million or 9.3 percent of sales in the third quarter of 2009 (excluding transaction and restructuring charges). Revenues declined three percent from the second quarter of 2009 and 33 percent from the third quarter of 2008. Almost all product lines within Petroleum Services & Supplies posted low single-digit percent sales declines in the third quarter as compared to the second quarter, as customer spending remained subdued. Decremental operating leverage was 32 percent from the second quarter of 2009 and 57 percent from the third quarter of 2008, reflective of sharp pricing declines. Prices are down 30 percent or more year-over-year for many of the items the segment sells, although discounts vary widely depending upon product and region. The business continues to face very challenging market conditions with lower levels of drilling despite the recent modest improvement in North American rig count. North American sales accounted for approximately 42 percent of the segments total revenue during the third quarter of 2009. Consumable products sales remain under pressure as customers cannibalize idle stocks and equipment from stacked rigs, rather than place orders with the Company, as they reduced operating and capital expenditures in view of lower activity. International markets have held up better, with pricing down 5 to 20 percent as the rig count declined one percent sequentially. Sales of bits and downhole tools improved in North America, but international demand for these fell in the third quarter in Saudi Arabia and Europe, driving sequentially lower results.

Drill pipe revenues were roughly flat with the second quarter but margins improved due to more favorable mix of premium pipe for new offshore rigs and lower steel costs. Drill pipe backlog and sales are expected to continue to decline due to the current oversupply, which is not likely to turn around before late 2010. Lower drill pipe demand also reduced drill pipe coating and inspection services at high decremental margins. Wellsite Services and coiled tubing posted slightly lower margins on lower solids control equipment and string sales, and increased discounting.

The Distribution Services segment generated total sales of $306 million for the third quarter of 2009, unchanged from the second quarter and down 39 percent from the third quarter of 2008. Operating profit was $7 million in the third quarter, down $3 million from the second quarter of 2009, and operating margins were 2.3 percent, down 100 basis points from the second quarter of 2009. The sequential decline in profitability arose from lower pricing, a decrease in supplier rebates on falling annual sales volumes, and lower margins on industrial products and artificial lift. Compared to the third quarter of 2008 decremental third quarter leverage was 19 percent on a 39 percent sales decline. Domestic sales were essentially unchanged sequentially, but Canada revenues increased as the region emerged from seasonal breakup, at excellent incremental profitability. Total North American revenue mix grew slightly overall sequentially to 71 percent and international sales declined sequentially and accounted for 29 percent of the segment’s third quarter mix. Pricing pressures appear to be stabilizing across North America, but many customers are bidding out much more of their work, which enabled the segment to win some incremental maintenance, repair and operating supplies contracts during the quarter. Unconventional shale plays in the Marcellus, Haynesville and Bakken are some of the most active North American markets, and the group continues to expand its presence in these areas, as well as expand in Russia.

Outlook

The recent credit market downturn, global recession, and lower commodity prices have presented challenges to our business, and consequently we remain cautious in our outlook, but we believe we are seeing signs of stabilization in many of our markets. Order levels for new drilling rigs have been slower to materialize in 2009 than we have expected, and while we do not foresee a significant turnaround in the fourth quarter, we believe 2010 should produce better results. Stronger 2010 orders assume that recently issued tenders for new rigs, including up to 28 new offshore floaters to be built in Brazil, translate into orders during the coming year; that rig dayrates generally hold up well; that commodity prices remain high; and that broad economic conditions do not deteriorate further. North American land gas drilling activity, particularly by independent gas producers reliant on external financing, has fallen sharply since 2008 and although gas prices have recently improved, we do not know when this sector will recover. Meaningfully lower gas production, due to the industry downturn, should bring supply and demand back into balance at some point. Our outlook for international markets, which are more driven by national oil company activity, are historically less volatile and expected to continue to see comparatively better market conditions.

Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution Services segment remains guarded. We expect revenues for Petroleum Services & Supplies to fall again slightly, and revenues for Distribution Services to rise slightly in the fourth quarter of 2009, and margins for both to remain approximately stable, as cost reduction initiatives offset continued pricing pressure. The Rig Technology segment is expected to be less affected by the downturn due to the strength of its backlog, but is likely to nevertheless see lower fourth quarter revenues and margins as revenues out of backlog decline sequentially, partly offset by non-backlog revenue gains.

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

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, pipeline maintenance activity, and worldwide oil and gas inventory levels. Key industry indicators for the third quarter of 2009 and 2008, and the second quarter of 2009 include the following:

														%				%
														3Q09 v				3Q09 v
		3Q09*				3Q08*				2Q09*				3Q08				2Q09
Active Drilling Rigs:
U.S.			974				1,978				936				(50.8	%)			4.1	%
Canada			187				432				90				(56.7	%)			107.8	%
International			969				1,095				983				(11.5	%)			(1.4	%)
Worldwide			2,130				3,505				2,009				(39.2	%)			6.0	%
West Texas Intermediate Crude Prices (per barrel)		$	68.20			$	118.40			$	59.44				(42.4	%)			14.7	%
Natural Gas Prices ($/mmbtu)		$	3.17			$	9.03			$	3.71				(64.9	%)			(14.6	%)

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, 2009 on a quarterly basis:

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

The worldwide and U.S. quarterly average rig count decreased 39% (from 3,505 to 2,130) and 51% (from 1,978 to 974), respectively, in the third quarter of 2009 compared to the third quarter of 2008. The average per barrel price of West Texas Intermediate Crude decreased 42% (from $118.40 per barrel to $68.20 per barrel) and natural gas prices decreased 65% (from $9.03 per mmbtu to $3.17 per mmbtu) in the third quarter of 2009 compared to the third quarter of 2008.

U.S. rig activity at October 23, 2009 was 1,048 rigs compared to the third quarter average of 974 rigs. The price for West Texas Intermediate Crude was at $80.50 per barrel as of October 23, 2009, increasing 18% from the third quarter 2009 average.

Results of Operations

Operating results by segment are as follows (in millions). The 2008 actual results include Grant Prideco operations from the acquisition date of April 21, 2008:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Revenue:
Rig Technology		$	2,000			$	1,926			$	6,116			$	5,440
Petroleum Services & Supplies			882				1,310				2,809				3,264
Distribution Services			306				498				1,019				1,289
Elimination			(101	)			(123	)			(366	)			(372	)
Total Revenue		$	3,087			$	3,611			$	9,578			$	9,621
Operating Profit:
Rig Technology (a)		$	577			$	501			$	1,717			$	1,413
Petroleum Services & Supplies (b) (c)			82				302				195				718
Distribution Services			7				43				42				87
Unallocated expenses and eliminations (d)			(54	)			(56	)			(228	)			(152	)
Transaction and restructuring costs			(11	)			—				(19	)			(16	)
Total Operating Profit		$	601			$	790			$	1,707			$	2,050
Operating Profit %:
Rig Technology (a)			28.9	%			26.0	%			28.1	%			26.0	%
Petroleum Services & Supplies (b) (c)			9.3	%			23.0	%			6.9	%			22.0	%
Distribution Services			2.3	%			8.8	%			4.1	%			6.8	%
Total Operating Profit %			19.5	%			21.9	%			17.8	%			21.3	%

Rig Technology

Three Months Ended September 30, 2009 and 2008. Rig Technology revenue in the third quarter of 2009 was $2,000 million, an increase of $74 million compared to the same period in 2008. Backlog was $7.3 billion, down 37.8% from the same period last year. Revenue out of backlog increased 17.3%, offset by a 28.9% decrease in non-backlog revenue from the prior year period reflecting a continued decrease in capital spending by North American land drillers and pressure pumpers.

Operating profit from Rig Technology was $577 million for the third quarter ended September 30, 2009, an increase of $76 million (15.2%) over the same period of 2008. Operating profit percentage increased to 28.9%, up from 26.0% for the same prior year period primarily due to revising cost estimates on large rig projects as a result of favorable pricing from vendors.

Nine Months Ended September 30, 2009 and 2008. Revenue for the first nine months of 2009 was $6,116 million, an increase of $676 million (12.4%) compared to the same period in 2008. Revenue out of backlog increased 23.2% offset by a 13.2% decrease in non-backlog revenue from the prior year period, largely due to lower spare parts and small capital equipment sales.

Operating profit for the first nine months of 2009 was $1,717 million, an increase of $304 million (21.5%) over the same period of 2008. Operating profit percentage increased to 28.1%, up from 26.0% for the same prior year period primarily driven by lower commodity prices and improved manufacturing efficiencies.

Petroleum Services & Supplies

Three Months Ended September 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was $882 million for the third quarter of 2009 compared to $1,310 million for the third quarter of 2008, a decrease of $428 million (32.7%). The decrease was primarily attributable to the decline in North American rig count activity and weaker than usual Canadian winter drilling activity rebound, with average rig utilization at 25% for the third quarter of 2009.

Operating profit from Petroleum Services & Supplies was $82 million for the third quarter of 2009 compared to $302 million for the same period in 2008, a decrease of $220 million (72.8%), and operating profit percentage decreased to 9.3% down from 23.0% in the same period of 2008. Decremental operating profit is a result of the dramatic decline in drilling activity beginning in late third quarter 2008. North American rig count has decreased 52% since September 2008, and 50% since December 2008.

Nine Months Ended September 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was $2,809 million for the first nine months of 2009 compared to $3,264 million for the first nine months of 2008, a decrease of $455 million (13.9%). The decrease was primarily attributable to a 43% decline in North American average rig count activity during the first nine months of 2009 over the comparable 2008 period, partially offset by contributions from Grant Prideco which was acquired on April 21, 2008.

Operating profit from Petroleum Services & Supplies was $195 million for the first nine months of 2009 compared to $718 million for the same period in 2008, a decrease of $523 million (72.8%). Operating profit percentage decreased to 6.9% down from 22.0% in the same prior year period. The primary reason for the decrease is due to a $147 million impairment charge on the carrying value of a trade name associated with this segment in the second quarter of 2009. (See Note 4 to the consolidated financial statements). In addition, the decrease was largely due to reduced North American rig count activity combined with strong price competition; however, this was partly offset by lower inflationary costs, particularly steel, labor and fuel. The decrease in operating profit was also partially offset by contributions from Grant Prideco which was acquired on April 21, 2008.

Distribution Services

Three Months Ended September 30, 2009 and 2008. Revenue from Distribution Services was $306 million, a decrease of $192 million (38.6%) during the third quarter of 2009 over the comparable 2008 period. The number of drilling rigs actively searching for oil and gas is a key metric for this business segment. North America sales declined 47% as a result of the 50% decline in the average North American rig count for the third quarter of 2009 compared to the third quarter of 2008.

Operating profit of $7 million for the third quarter of 2009 decreased $36 million over the comparable period in 2008. Operating profit percentage decreased to 2.3%, from 8.8% for the same prior year period as a result of reduced North American drilling activity.

Nine Months Ended September 30, 2009 and 2008. Revenue from Distribution Services was $1,019 million, a decrease of $270 million (20.9%) during the first nine months of 2009 over the comparable 2008 period. The decrease in revenue is mainly concentrated in the North American region as average drilling activity declined 43% for the first nine months of 2009 over the comparable 2008 period. However, international revenues increased 17% over the same period in 2008 due to increased US exports and further development of the new RigStore™ business that provides innovative supply chain solutions to install, staff and manage supply stores on offshore drilling rigs.

Operating profit of $42 million in the first nine months of 2009 decreased $45 million over the comparable period in 2008. Operating profit percentage decreased to 4.1%, from 6.8% for the same prior year period as a result of strong price competition and volume reductions as North American rig activity continues to decline.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $54 million and $228 for the three and nine months ended September 30, 2009, respectively, compared to $56 million and $152 million for the same periods in 2008. The decrease for the three months comparison is primarily due to lower administration costs resulting from the voluntary retirement program adopted in the second quarter of 2009. The increase for the nine months comparison is a result of the charge taken related to the voluntary retirement program adopted in the second quarter of 2009.

Transaction and restructuring costs

Transaction costs were $11 million and $19 million for the three and nine months ending September 30, 2009, respectively. The transaction costs related primarily to restructuring costs and costs associated with recent acquisitions.

Interest and financial costs

Interest and financial costs were $14 million and $40 million for the three and nine months ended September 30, 2009, respectively, compared to $19 million and $53 million for the same periods in 2008. The primary reasons for the decrease in interest and financial costs were a direct result of the repayment of borrowings on the Company’s credit facility used to purchase Grant Prideco, the repayment of the Company’s 7.5% Senior Notes and the repayment of a portion of the Company’s 6.125% Senior Notes. These repayments occurred during 2008 causing lower debt levels in 2009.

Other income (expense), net

Other income (expense), net was expense, net of $13 million and $87 million for the three and nine months ended September 30, 2009 compared to income, net of $15 million and $14 million for the same periods in 2008. The increase in other expense was mainly due to foreign exchange losses in 2009 as a result of unfavorable exchange rate movements in 2009, primarily related to the weakening of the U.S. dollar.

Provision for income taxes

The effective tax rate for the three and nine months ended September 30, 2009 was 33.2% and 33.7%, respectively, compared to 32.3% and 33.9% for the same periods in 2008. The nine months 2009 tax rate includes $21 million of additional tax provision recognized in the second quarter 2009 on prior year income in Norway. These additional taxes resulted from foreign currency gains on dollar-denominated accounts that were realized for Norwegian tax purposes. The Company expects its income tax rate to be in the 32% to 33% range for the remainder of the year.

Liquidity and Capital Resources

Overview

At September 30, 2009, the Company had cash and cash equivalents of $3,192 million, and total debt of $884 million. At December 31, 2008, cash and cash equivalents were $1,543 million and total debt was $874 million. A 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. The Company’s outstanding debt at September 30, 2009 consisted of $200 million of 5.65% Senior Notes due 2012, $200 million of 7.25% Senior Notes due 2011, $150 million of 6.5% Senior Notes due 2011, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $33 million.

The Company had $2,234 million of additional outstanding letters of credit at September 30, 2009, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. We were in compliance with all covenants at September 30, 2009.

There were no borrowings against the Company’s unsecured credit facilities, and there were $589 million in outstanding letters of credit issued under such facilities, resulting in $1,411 million of funds available under the Company’s unsecured revolving credit facilities at September 30, 2009.

Operating Activities

For the first nine months of 2009, cash provided by operating activities increased $263 million to $1,969 million compared to cash provided by operating activities of $1,706 million in the same period of 2008. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $1,082 million plus non-cash charges of $511 million and dividends from unconsolidated affiliates of $86 million less $45 million in equity income from the Company’s unconsolidated affiliate. Net changes in operating assets and liabilities, net of acquisitions, contributed another $335 million in cash provided by operating activities, a $306 million increase from the same period in 2008.

Investing Activities

For the first nine months of 2009, cash used in investing activities was $319 million compared to cash used in investing of $2,339 million for the same period of 2008. The primary reason for the decrease in cash used in investing activities for the first nine months of 2009 related to a decrease in size of business acquisitions, net of cash acquired, to approximately $392 million compared to $2,988 million used in the same period of 2008 which included the purchase of the business and operating assets of Grant Prideco, offset by the approximately $801 million received related to the disposition of certain Grant Prideco tubular businesses. In addition, the Company used $186 million for capital expenditures in the first nine months of 2009, compared to $264 million for the same period in 2008.

Financing Activities

For the first nine months of 2009, cash used in financing activities was $25 million compared to cash provided by financing activities of $568 million for the same period of 2008. The cash used in financing activities for the first nine months of 2009 related to $35 million cash payments on debt primarily acquired in the second quarter 2009 acquisitions, offset by cash proceeds from borrowings in the amount of $7 million and exercised stock options in the amount of $3 million. The borrowings and payments of debt in the first nine months of 2008 primarily relates to the financing of the Grant Prideco acquisition. For the first nine months of 2009, the Company used its cash on hand to fund its acquisitions.

The effect of the change in exchange rates on cash flows was a positive $24 million and a negative $12 million for the nine months ended September 30, 2009 and 2008, respectively.

The Company’s cash balance as of September 30, 2009 was $3,192 million. We believe that cash on hand, cash generated from operations and amounts available under the credit facilities and from other sources of debt will be sufficient to fund operations, working capital needs, capital expenditure requirements and financing obligations.

We intend to pursue additional acquisition candidates, but the timing, size or success of any acquisition effort and the related potential capital commitments cannot be predicted. We expect to fund future cash acquisitions primarily with cash flow from operations and borrowings, including the unborrowed portion of the credit facility or new debt issuances, but may also issue

additional equity either directly or in connection with acquisitions. There can be no assurance that additional financing for acquisitions will be available at terms acceptable to us.

Recently Issued Accounting Standards

In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) SFAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”), which defers the effective date of SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), as it related to non-financial assets and non-financial liabilities, to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. Both standards mentioned above were primarily codified into ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”). The Company, as of January 1, 2009, adopted the provisions of this statement and included the appropriate disclosures surrounding non-financial assets and liabilities, as applicable.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”), which was primarily codified into ASC Topic 850, “Business Combinations” (“ASC Topic 850”). ASC Topic 850 provides revised guidance on how acquirers recognize and measure the consideration transferred, identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired in a business combination. ASC Topic 850 also expands required disclosures surrounding the nature and financial effects of business combinations. ASC Topic 850 is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC Topic 850. The Company expects that this new standard will impact certain aspects of its accounting for business combinations on a prospective basis, including the determination of fair values assigned to certain purchased assets and liabilities.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160’), which was primarily codified into ASC Topic 810, “Consolidations” (“ASC Topic 810”). ASC Topic 810 establishes requirements for ownership interests in subsidiaries held by parties other than the Company (previously called minority interests) be clearly identified, presented, and disclosed in the consolidated statement of financial position within equity, but separate from the parent’s equity. All changes in the parent’s ownership interests are required to be accounted for consistently as equity transactions and any noncontrolling equity investments in deconsolidated subsidiaries must be measured initially at fair value. ASC Topic 810 is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. However, presentation and disclosure requirements must be retrospectively applied to comparative financial statements. On January 1, 2009, the Company adopted ASC Topic 810, and reclassified noncontrolling interests in the amounts of $109 million and $96 million from the mezzanine section to equity in the September 30, 2009 and December 31, 2008 balance sheets, respectively.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161’), which was primarily codified into ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”). ASC Topic 815 amends and expands the disclosure requirements for derivative instruments and hedging activities, with the intent to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial statements. ASC Topic 815 is effective for fiscal years and interim periods beginning after November 15, 2008. On January 1, 2009, the Company adopted ASC Topic 815. See Note 11. “Derivative Financial Instruments”, in the notes to the consolidated financial statements.

In April 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3’), which was primarily codified into ASC Topic 350, “Intangibles — Goodwill and Other” (“ASC Topic 350”). ASC Topic 350 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets”. The objective of this ASC is to improve the consistency between the useful life of a recognized intangible asset under Statement No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R and other U.S. GAAP principles. ASC Topic 350 is effective for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC Topic 350. There was no significant impact to the Company’s consolidated financial statements from the adoption of ASC Topic 350.

In April 2009 the FASB issued FSP 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141R-1”), which was primarily codified into ASC Topic 850, “Business Combinations” (“ASC Topic 850”). ASC Topic 850 amends the provisions in SFAS 141R for the initial recognition and measurement, subsequent measurement and accounting, and disclosures for assets and liabilities arising from contingencies in business combinations. The ASC eliminates the distinction between contractual and non-contractual contingencies, including the initial recognition and measurement criteria in SFAS 141R and instead carries forward most of the provisions in SFAS 141 for acquired contingencies. ASC Topic 850 is effective for contingent assets and contingent liabilities acquired in business

combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company expects ASC Topic 850 will have a future impact on its consolidated financial statements, but the nature and magnitude of the specific effects will depend upon the nature, term and size of the acquired contingencies.

In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP SFAS 107-1”), which was primarily codified into ASC Topic 825, “Financial Instruments” (“ASC Topic 825”). ASC Topic 825 extends the disclosure requirements regarding the fair value of financial instruments under SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (“SFAS No. 107”), to interim financial statements of publicly traded companies. ASC Topic 825 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Early adoption of this ASC is permitted only if the entity also elects to early adopt FSP SFAS 157-4 and FSP SFAS 115-2. On June 1, 2009, the Company adopted ASC Topic 825. There was no significant impact to the Company’s consolidated financial statements from the adoption of ASC Topic 825.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”), which was primarily codified into ASC Topic 855, “Subsequent Events” (“ASC Topic 855”). ASC Topic 855 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. ASC Topic 855 is effective for fiscal years and interim periods ending after June 15, 2009. On June 1, 2009, the Company adopted ASC Topic 855. There was no significant impact to the Company’s consolidated financial statements from the adoption of ASC Topic 855.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (SFAS 168”), which amends SFAS 162, “The Hierarchy of Generally Accepted Accounting Principles.” Both of these standards were primarily codified into ASC Topic 105, “Generally Accepted Accounting Standards” (“ASC Topic 105”). The ASC will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date, ASC Topic 105 will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the ASC will become non-authoritative. ASC Topic 105 is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

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, 2008, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that do impact income. We recorded a foreign exchange loss in our income statement of approximately $62 million in the first nine months of 2009, compared to a $30 million foreign currency gain in the same period of the prior year. The gain/losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of the current economic environment. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods as of September 30, 2009 (in millions, except contract rates):

		As of September 30, 2009																December 31,
Functional Currency		2009				2010				2011				Total				2008
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)			329				6				—				335				527
Average CAD to USD contract rate			1.1189				1.0966				—				1.1185				1.1843
Fair Value at September 30, 2009 in U.S. dollars			(9	)			—				—				(9	)			14
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)			33				70				—				103				241
Average CAD to USD contract rate			1.0710				1.1109				—				1.0977				1.1196
Fair Value at September 30, 2009 in U.S. dollars			—				2				—				2				(18	)
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)			89				—				—				89				11
Average USD to EUR contract rate			1.4103				—				—				1.4103				1.4397
Fair Value at September 30, 2009 in U.S. dollars			(4	)			—				—				(4	)			—
Sell USD/Buy EUR:
Notional amount to buy (in euros)			37				67				1				105				245
Average USD to EUR contract rate			1.3282				1.3633				1.4324				1.3515				1.3986
Fair Value at September 30, 2009 in U.S. dollars			5				6				—				11				1
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)			49				—				—				49				—
Average USD to GBP contract rate			1.6400				—				—				1.6400				—
Fair Value at September 30, 2009 in U.S. dollars			2				—				—				2				—
Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)			5				2				—				7				34
Average USD to GBP contract rate			1.5522				1.5313				—				1.5458				1.5647
Fair Value at September 30, 2009 in U.S. dollars			—				—				—				—				(4	)