NOV Inc. - Quarter Report: 2009 June (Form 10-Q)

 

 

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.

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

7909 Parkwood Circle Drive
Houston, Texas
77036-6565

(713) 346-7500

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 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 August 3, 2009 the registrant had 418,199,258 shares of common stock, par value $.01 per share, outstanding.

 

 

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)

		June 30,				December 31,
		2009				2008
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	2,286			$	1,543
Receivables, net			2,603				3,136
Inventories, net			3,825				3,806
Costs in excess of billings			590				618
Deferred income taxes			215				271
Prepaid and other current assets			391				283
Total current assets			9,910				9,657
Property, plant and equipment, net			1,758				1,677
Deferred income taxes			195				126
Goodwill			5,466				5,225
Intangibles, net			4,134				4,300
Investment in unconsolidated affiliate			387				421
Other assets			89				73
Total assets		$	21,939			$	21,479
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	760			$	852
Accrued liabilities			2,082				2,376
Billings in excess of costs			2,081				2,161
Current portion of long-term debt and short-term borrowings			8				4
Accrued income taxes			236				230
Total current liabilities			5,167				5,623
Long-term debt			873				870
Deferred income taxes			2,150				2,134
Other liabilities			144				128
Total liabilities			8,334				8,755
Commitments and contingencies
Stockholders’ equity:
Common stock — par value $.01; 418,192,372 and 417,350,924 shares issued and outstanding at June 30, 2009 and December 31, 2008			4				4
Additional paid-in capital			8,027				7,989
Accumulated other comprehensive loss			—				(161	)
Retained earnings			5,486				4,796
Total Company stockholders’ equity			13,517				12,628
Noncontrolling interests			88				96
Total stockholders’ equity			13,605				12,724
Total liabilities and stockholders’ equity		$	21,939			$	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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Revenue		$	3,010			$	3,325			$	6,491			$	6,010
Cost of revenue			2,135				2,344				4,577				4,232
Gross profit			875				981				1,914				1,778
Selling, general and administrative			334				274				653				502
Intangible asset impairment			147				—				147				—
Transaction costs			8				16				8				16
Operating profit			386				691				1,106				1,260
Interest and financial costs			(13	)			(24	)			(26	)			(34	)
Interest income			2				10				4				26
Equity income in unconsolidated affiliate			16				17				44				17
Other income (expense), net			(38	)			(14	)			(74	)			(1	)
Income before income taxes			353				680				1,054				1,268
Provision for income taxes			131				255				359				443
Net income			222				425				695				825
Net income attributable to noncontrolling interests			2				4				5				6
Net income attributable to Company		$	220			$	421			$	690			$	819
Net income attributable to Company per share:
Basic		$	0.53			$	1.05			$	1.66			$	2.16
Diluted		$	0.53			$	1.04			$	1.65			$	2.15
Weighted average shares outstanding:
Basic			416				402				416				379
Diluted			418				404				417				381

See notes to unaudited consolidated financial statements.

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

		Six Months Ended
		June 30,
		2009				2008
Cash flows from operating activities:
Net income		$	695			$	825
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			238				168
Excess tax benefit from exercise of stock options			—				(36	)
Equity income in unconsolidated affiliate			(44	)			(17	)
Dividend from unconsolidated affiliate			86				—
Intangible asset impairment			147				—
Other			(5	)			43
Change in operating assets and liabilities, net of acquisitions:
Receivables			590				(507	)
Inventories			75				(297	)
Costs in excess of billings			28				38
Prepaid and other current assets			(108	)			74
Accounts payable			(152	)			22
Billings in excess of costs			(80	)			556
Other assets/liabilities, net			(185	)			375
Net cash provided by operating activities			1,285				1,244
Cash flows from investing activities:
Purchases of property, plant and equipment			(143	)			(160	)
Business acquisitions, net of cash acquired			(389	)			(2,945	)
Business divestitures, net of cash disposed			—				784
Dividend from unconsolidated affiliate			8				113
Other, net			—				(1	)
Net cash used in investing activities			(524	)			(2,209	)
Cash flows from financing activities:
Borrowings against lines of credit and other debt			—				2,577
Payments against lines of credit and other debt			(34	)			(1,928	)
Proceeds from exercise of stock options			1				77
Excess tax benefit from exercise of stock options			—				36
Net cash provided by (used in) financing activities			(33	)			762
Effect of exchange rates on cash			15				13
Increase in cash equivalents			743				(190	)
Cash and cash equivalents, beginning of period			1,543				1,842
Cash and cash equivalents, end of period		$	2,286			$	1,652
Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest		$	27			$	30
Income taxes		$	409			$	376

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 six months ended June 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 August 7, 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 six month periods ended June 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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Total revenues		$	3,010			$	3,444			$	6,491			$	6,613
Net income attributable to Company		$	220			$	446			$	690			$	898
Basic net income attributable to Company per share		$	0.53			$	1.08			$	1.66			$	2.17
Diluted net income attributable to Company per share		$	0.53			$	1.07			$	1.65			$	2.16

In the three and six months ended June 30, 2009, the Company completed five acquisitions for an aggregate purchase price of $389 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 following table summarizes the preliminary purchase price allocation of the assets acquired and liabilities assumed at the date of acquisition of the 2009 acquisitions (in millions):

		Total
Current assets, net of cash acquired		$	213
Property, plant and equipment			57
Intangible assets			85
Goodwill			198
Total assets acquired			553
Current liabilities			113
Long-term debt			42
Other liabilities			9
Total liabilities			164
Cash consideration, net of cash acquired		$	389

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.

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 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 next three years (2009, 2010, and 2011).

Inventories consist of (in millions):

		June 30,				December 31,
		2009				2008
Raw materials and supplies		$	782			$	739
Work in process			1,507				1,326
Finished goods and purchased products			1,536				1,741
Total		$	3,825			$	3,806

5. Accrued Liabilities

Accrued liabilities consist of (in millions):

		June 30,				December 31,
		2009				2008
Compensation		$	185			$	258
Customer prepayments and billings			547				912
Warranty			162				114
Interest			12				11
Taxes (non income)			57				76
Insurance			56				50
Accrued purchase orders			743				688
Fair value of derivatives			83				59
Other			237				208
Total		$	2,082			$	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. 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			75
Amounts incurred			(29	)
Foreign currency translation			2
Balance, June 30, 2009		$	162

6. Costs and Estimated Earnings on Uncompleted Contracts

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

		June 30,				December 31,
		2009				2008
Costs incurred on uncompleted contracts		$	5,734			$	4,776
Estimated earnings			2,987				2,277
			8,721				7,053
Less: Billings to date			10,212				8,596
		$	(1,491	)		$	(1,543	)
Costs and estimated earnings in excess of billings on uncompleted contracts		$	590			$	618
Billings in excess of costs and estimated earnings on uncompleted contracts			(2,081	)			(2,161	)
		$	(1,491	)		$	(1,543	)

7. Comprehensive Income

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Net income		$	222			$	425			$	695			$	825
Currency translation adjustments, net of tax			112				11				57				38
Changes in derivative financial instruments, net of tax			83				—				105				21
Changes in defined benefit plans, net of tax			(1	)			1				(1	)			—
Comprehensive income			416				437				856				884
Comprehensive income attributable to noncontrolling interest			2				4				5				6
Comprehensive income attributable to Company		$	414			$	433			$	851			$	878

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.” For the three months ended June 30, 2009, a majority of these local currencies strengthened against the U.S. dollar resulting in a net increase to Other Comprehensive Income of $112 million (net of tax of $60 million) upon the translation of their financial statements from their local currency to the U.S. dollar.

The effect of changes in the exchange rates for 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 currency rates for open derivatives and the outflow of accumulated Other Comprehensive Income on previously matured derivatives. The accumulated effects of these scenarios have caused an increase in Other Comprehensive Income of $83 million (net of tax of $30 million) for the three months ended June 30, 2009.

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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Revenue:
Rig Technology		$	1,917			$	1,911			$	4,116			$	3,514
Petroleum Services & Supplies			913				1,124				1,927				1,954
Distribution Services			305				425				713				791
Elimination			(125	)			(135	)			(265	)			(249	)
Total Revenue		$	3,010			$	3,325			$	6,491			$	6,010
Operating Profit:
Rig Technology (a)		$	534			$	506			$	1,140			$	912
Petroleum Services & Supplies (b)(c)			(51	)			221				113				416
Distribution Services			10				25				35				44
Unallocated expenses and eliminations (d)			(99	)			(45	)			(174	)			(96	)
Transaction costs			(8	)			(16	)			(8	)			(16	)
Total Operating Profit		$	386			$	691			$	1,106			$	1,260
Operating Profit %:
Rig Technology (a)			27.9	%			26.5	%			27.7	%			26.0	%
Petroleum Services & Supplies (b)(c)			(5.6	%)			19.7	%			5.9	%			21.3	%
Distribution Services			3.3	%			5.8	%			4.9	%			5.5	%
Total Operating Profit %			12.8	%			20.8	%			17.0	%			21.0	%

The Company had revenues of 15.6% of total revenue from one of its customers for the six months ended June 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. There were no customers that represented 10% or greater of total revenue for the six months ended June 30, 2008.

9. Debt

Debt consists of (in millions):

		June 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			23				14
Total debt			881				874
Less current portion			8				4
Long-term debt		$	873			$	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.

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 June 30, 2009, there were no borrowings against these facilities, and there were $636 million in outstanding letters of credit issued under these facilities, resulting in $1,364 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 $2,414 million of additional outstanding letters of credit at June 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 June 30, 2009.

Other debt includes approximately $5 million in promissory notes due to former owners of businesses acquired.

The effective tax rate for the three and six months ended June 30, 2009 was 37.3% and 34.1%, respectively, compared to 37.5% and 34.9% for the same periods in 2008. The second quarter 2009 tax rate, which was higher than periods preceding this quarter, was primarily affected by $21 million of additional tax provisions recognized in the period 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 return to the 32% to 33% range for the remainder of the year.

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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Federal income tax at U.S. federal statutory rate		$	124			$	238			$	369			$	444
Foreign income tax rate differential			(26	)			(23	)			(58	)			(43	)
State income tax, net of federal benefit			2				11				8				17
Foreign dividends, net of foreign tax credits			6				33				7				35
Benefit of U.S. Manufacturing Deduction			(3	)			(3	)			(7	)			(5	)
Nondeductible expenses			4				2				12				5
Prior year tax on revaluation gains in Norway			21				—				21				—
Other			3				(3	)			7				(10	)
Provision for income taxes		$	131			$	255			$	359			$	443

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”). FIN 48 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” 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, 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 for tax positions of prior years			3
Settlements			(11	)
Balance at June 30, 2009		$	53

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 2003 and outside the U.S. for tax years ending after 2001.

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.

11. 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 quarter, the Company with approval from shareholders increased the number of shares authorized under the Plan from 15 million to 26 million. As of June 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 $31 million for the three and six months ended June 30, 2009, respectively, and $16 million and $29 million for the three and six months ended June 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 $7 million and $12 million for the three and six months ended June 30, 2009, respectively, and $7 million and $11 million for the three and six months ended June 30, 2008, respectively.

During the six months ended June 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.

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 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.

In accordance with SFAS 133 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 June 30, 2009, the Company has determined that its financial assets of $114 million and liabilities of $95 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At June 30, 2009, the fair value of the Company’s foreign currency forward contracts totaled $16 million.

As of June 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.

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 June 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		£	47
Danish Krone		DKK	197
Euro		€	279
Norwegian Krone		NOK	7,717
U.S. Dollar		$	181

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 June 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)
Korean Won		KRW	1,917
U.S. Dollar		$	64

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 June 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		£	2
Danish Krone		DKK	15
Euro		€	150
Norwegian Krone		NOK	2,280
Swedish Krone		SEK	5
U.S. Dollar		$	67

As of June 30, 2009, the Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions):

		June 30, 2009
		Asset Derivatives						Liability Derivatives
		Balance Sheet		Fair				Balance Sheet		Fair
		Location		Value				Location		Value
Derivatives designated as hedging instruments under SFAS 133
Foreign exchange contracts		Prepaid and other current assets		$	63			Accrued liabilities		$	37
Foreign exchange contracts		Other Assets			11			Other Liabilities			11
Total derivatives designated as hedging instruments under SFAS 133				$	74					$	48
Derivatives not designated as hedging instruments under SFAS 133
Foreign exchange contracts		Prepaid and other current assets		$	34			Accrued liabilities		$	46
Foreign exchange contracts		Other Assets			3			Other Liabilities			1
Total derivatives not designated as hedging instruments under SFAS 133				$	37					$	47
Total derivatives				$	111					$	95

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 SFAS 133

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)

June 30, 2009

June 30, 2009

June 30, 2009

Three Months Ended

Six Months Ended

Three Months Ended

Six Months Ended

Three Months Ended

Six Months Ended

Foreign exchange contracts

70

74

Revenue

11

10

Other income (expense), net

(18

)

(24

)

Foreign exchange contracts

—

—

Cost of revenue

(16

)

(44

)

Total

70

74

(5

)

(34

)

(18

)

(24

)

Derivatives in SFAS 133

Location of Gain (Loss)

Amount of Gain (Loss)

SFAS 133

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

June 30, 2009

June 30, 2009

Three Months Ended

Six Months Ended

Three Months Ended

Six Months Ended

Foreign exchange contracts

Revenue

4

(2

)

Firm commitments

Revenue

(4

)

2

Foreign exchange contracts

Cost of revenue

—

(1

)

Firm commitments

Cost of revenue

—

1

Total

4

(3

)

(4

)

3

Derivatives Not Designated as

Location of Gain (Loss)

Amount of Gain (Loss)

Hedging Instruments under

Recognized in Income

Recognized in Income on

SFAS 133

on Derivative

Derivative (a)

Foreign exchange contracts

Other income (expense), net

46

26

Total

46

26

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. 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 $23 million remains to be recognized into earnings at June 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 June 30, 2009, our Norway operations had derivatives with $2,709 million in notional value with a fair value asset of $33 million.

13. 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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Numerator:
Net income attributable to Company		$	220			$	421			$	690			$	819
Denominator:
Basic—weighted average common shares outstanding			416				402				416				379
Dilutive effect of employee stock options and other unvested stock awards			2				2				1				2
Diluted outstanding shares			418				404				417				381
Net income attributable to Company per share:
Basic		$	0.53			$	1.05			$	1.66			$	2.16
Diluted		$	0.53			$	1.04			$	1.65			$	2.15

In addition, the Company had stock options outstanding that were anti-dilutive totaling 4 million and 10 million shares for the three and six months ended June 30, 2009, respectively, and 1 million shares for both the three and six months ended June 30, 2008, respectively.

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. 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”). SFAS 141R 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. SFAS 141R also expands required disclosures surrounding the nature and financial effects of business combinations. SFAS 141R is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted SFAS 141R. 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”). SFAS 160 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. SFAS 160 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 SFAS 160, and reclassified noncontrolling interests in the amounts of $88 million and $96 million from the mezzanine section to equity in the June 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”). SFAS 161 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. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. On January 1, 2009, the Company adopted SFAS 161. 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”). FSP SFAS 142-3 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 FSP 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. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted FSP SFAS 142-3. There was no significant impact to the Company’s consolidated financial statements from the adoption of FSP SFAS 142-3.

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”). FSP 141R-1 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 FSP 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. FSP 141R-1 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 FSP 141R-1 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”). FSP SFAS 107-1 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. FSP SFAS 107-1 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 FSP 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 FSP SFAS 107-1. There was no significant impact to the Company’s consolidated financial statements from the adoption of FSP SFAS 107-1.

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

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.” SFAS 168 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, SFAS 168 will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in SFAS 168 will become non-authoritative. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company is currently assessing the impact SFAS 168 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.

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:

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 June 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 quarter and six months ended June 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 SFAS 142.

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 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 next three years (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 next three years (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 next three years (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 $220 million or $0.53 per fully diluted share in its second quarter ended June 30, 2009, on revenues of $3,010 million. Compared to the second quarter of 2008, revenue declined nine percent and net income attributable to the Company declined 48 percent, and compared to the first quarter of 2009, revenue declined 14 percent and net income attributable to the Company declined 53 percent. These declines were due to lower market activity, the effect of asset impairment, transaction, and voluntary retirement charges, and a higher income tax rate recognized in the second quarter of 2009 that did not occur in the prior periods.

During the second quarter of 2009, the Company recognized a $147 million pre-tax, or $0.23 per share after-tax, impairment charge on its carrying value of an intangible trade name acquired in its Grant Prideco acquisition. During the second quarter the Company retested all its carrying values for goodwill and intangible assets, which was performed due to deterioration seen in the rig count and performance of certain of its business units compared to forecasts. Additionally, the Company recognized $56 million in pre-tax charges ($0.09 per share after-tax) related to acquisitions made in the quarter, and the results of a voluntary retirement program offered to its long-tenured employees. Legal, due diligence and other costs associated with acquisitions that were previously capitalized under GAAP are now expensed under FAS141R. The Company’s voluntary retirement program charge was $46 million, consisting of separation and accrued medical benefits and options vesting charges, and is expected to result in annual savings of approximately $33 million per year. Second quarter 2009 net income was also affected by an income tax rate of 37 percent, higher than periods preceding this quarter, due to $21 million of additional tax provisions recognized in the period 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 effective income tax rate to return to the 32 percent to 33 percent range for the remainder of the year.

Operating profit was $386 million or 12.8 percent of sales for the second quarter. Excluding the impairment, transaction, and voluntary retirement charges, second quarter operating profit was $589 million or 19.6 percent of sales, compared to $720 million or 20.7 percent of sales in the first quarter of 2009, and $778 million or 22.6 percent of sales in the second quarter of 2008 (excluding transaction charges and including a full quarter contribution from the Grant Prideco acquisition in the second quarter of 2008).

Grant Prideco Acquisition

On April 21, 2008 the Company completed its acquisition of Grant Prideco, Inc. for a combination of approximately $3.0 billion in cash and the issuance of 56.9 million shares of National Oilwell Varco common stock. The Grant Prideco merger further strengthened National Oilwell Varco’s position as manufacturer to the oilfield. Its drill bits and reamers have been integrated into the Company’s offering of drilling motors, non-magnetic drill collars, jars and shock tools, to complement its comprehensive package of bottomhole assembly tools used to drill complex wellpaths. Additionally, Grant Prideco’s drillpipe products are purchased and consumed by the Company’s existing drilling contractor customer base. The Company believes that consumption of drillpipe per foot of hole drilled, or per rig running, has been increasing due to the rising complexity of wellpath designs. Overall the acquisition better positioned National Oilwell Varco to capitalize on continued application of horizontal, directional and extended-reach drilling, through both drillpipe and drill bit product sales. Integration of the business has proceeded well. The Company is introducing new drillpipe tracking products, and expanding OEM drillpipe repair and maintenance offerings through its worldwide network of pipe service operations. The Company is also consolidating a number of bit and downhole tool sales facilities worldwide, and leveraging combined manufacturing and marketing capabilities.

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 $43 per barrel range during the first quarter of 2009. Higher oil and gas prices over the past several years have led to high levels of exploration and development drilling in many oil and gas basins around the globe, but this slowed sharply with falling oil and gas prices. 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 has decreased to 943 rigs as of July 24, 2009. Many oil and gas operators reliant on external financing to fund their drilling programs are curtailing their drilling activity. So far this

appears to be having 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 is showing some modest declines nonetheless, falling from its September 2008 peak of 1,108 to 967 in June 2009. During the second 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 ODS, 74 percent of the existing 446 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 $8.7 billion by June 30, 2009.

The land rig backlog comprised 12 percent and equipment destined for offshore operations comprised 88 percent of the total backlog as of June 30, 2009. Equipment destined for international markets totaled 92 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 second quarter of 2009, the Company removed $108 million in orders on which its customers had defaulted, and booked a gain of $16 million related to down payments and progress billings it had received. 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 $320 million of projects in its June 30, 2009 backlog that it considers at risk.

Segment Performance

Rig Technology generated $1,917 million in revenue and $536 million in operating profit in the second quarter of 2009, yielding a record operating margin for the segment of 28.0 percent (excluding transaction and voluntary retirement charges). The segment generated 25 percent operating leverage or flowthrough (the decrease in operating profit divided by the decrease in revenue) on 13 percent lower revenue from the first quarter of 2009, and posted $30 million higher operating profit on $7 million higher revenues when compared to the second quarter of 2008. Revenue out of backlog of $1,434 million declined 15 percent sequentially and increased seven percent compared to the second quarter of last year. As of June 30, 2009 the scheduled outflow of revenue from backlog is expected to be in the range of $2.5 billion for the remainder of 2009, $4.7 billion in 2010, and $1.5 billion for 2011. From 2005 through the current quarter, the segment has delivered a total of 59 newly built offshore rig packages. Aftermarket spare parts and services revenue, and sales of smaller capital items which do not qualify for the backlog, declined five percent from the first quarter of 2009. Demand for rigs and equipment is strongest in Brazil, the Middle East, Mexico, and the North Sea (for platform cranes and winches). Additionally, we are seeing rising interest for equipment for Iraq and China, and completed a workover rig sale into Russia during the second quarter. Generally, demand for equipment in North America is very slow; although the Company’s first new Drake rig delivered into the Marcellus shale play is performing well.

The Petroleum Services & Supplies segment generated revenues of $913 million and operating profit of $96 million or 10.5 percent of sales in the second quarter of 2009 (excluding impairment, transaction, and voluntary retirement charges). Revenues declined 10 percent from the first quarter of 2009 and 27 percent from the second quarter of 2008 (on a combined adjusted basis for a full quarter contribution from Grant Prideco). Decremental operating leverage was 67 percent from the first quarter of 2009 and 60 percent from the second quarter of 2008. Excluding the impact of acquisitions made during the second quarter revenues fell 13 percent sequentially, and decremental operating leverage was 55 percent. The business faced very challenging market conditions and lower pricing in the second quarter, particularly in North America, where U.S. rig counts fell 29 percent and Canadian rig counts fell 73 percent from the first quarter of 2009. Pricing fell as much as 30 percent to 40 percent across some product lines, although the discounts varied widely depending upon product and region. Consumable products sales were down sharply as drilling contractors cannibalized idle equipment from stacked rigs, rather than place orders with the Company, as they reduced operating and capital expenditures in view of lower rig dayrates. International markets held up better, with pricing down 5 to 20 percent as the rig count declined four percent sequentially. Nevertheless, the group posted 9 percent sequential international sales gains, half of which was due to acquisitions. Sales and rentals of downhole tools and bits, composite pipe, and coiled tubing saw large double-digit percent declines, while other products were down only modestly from the first quarter to the second. Virtually all products and services posted sequential drops in North America, which declined to less than half of the group’s mix during the second quarter in the aggregate. Drillpipe sales were roughly flat sequentially, but margins improved on a better mix of premium high-torque pipe and lower costs.

Distribution Services segment revenues were $305 million during the second quarter of 2009, a decrease of 25 percent from the first quarter of 2009 and a decrease of 28 percent from the second quarter of 2008. Sequential decremental operating leverage was 15 percent, and year-over-year operating leverage was 13 percent on the revenue declines, higher than the segment has typically experienced due to pricing pressure accompanying the volume declines. Pricing for the group’s North American operation declined two to three percent from the first quarter. The group has successfully increased its international presence to about a third of its sales over the past few years, but it still remains dependent on North America for a majority of its business. The softer year-over-year and sequential results are a result of the considerably softer market conditions seen in North America during the second quarter of 2009, which declined 31 percent in sales from the first quarter of 2009. Nevertheless diligent attention to costs and efficiency enabled the group to post 3.3 percent operating margins in the second quarter, excluding voluntary retirement charges. The group continues to expand store coverage of emerging Marcellus, Haynesville, and South Texas Eagle Ford shale plays, while also expanding its presence in Brazil, Mexico, and Central Asia.

Outlook

The serious credit market crisis, global recession, and lower commodity prices are presenting challenging prospects to our business. Consequently we remain cautious in our outlook for the remainder of 2009, and believe we will see orders for new rigs fall in 2009 (although we are nevertheless optimistic that drilling contractors will place orders for new build floating rigs during the year for the Brazilian deepwater market). Drilling activity, particularly by independent gas producers reliant on external financing, has fallen sharply and we do not know when it will recover.

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 slightly, and revenues for Distribution Services to rise slightly in the third quarter of 2009, and margins for both to remain approximately stable, as cost reduction initiatives offset continued pricing pressure. We do not foresee a meaningful recovery in gas drilling in North America this year, but believe the likelihood for such a recovery rises in 2010 and 2011 as gas production is expected to begin to decline and/or recent lower demand is expected to recover. Our outlook for international markets, which are more driven by national oil company activity, are historically less volatile and expected to see better market conditions. The Rig Technology segment is expected to be less affected by the downturn due to the strength of its backlog.

The Company believes it is nevertheless well positioned to manage through this uncertain period, 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 downturn. 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 second quarter of 2009 and 2008, and the first quarter of 2009 include the following:

														%				%
														2Q09 v				2Q09 v
		2Q09*				2Q08*				1Q09*				2Q08				1Q09
Active Drilling Rigs:
U.S.			936				1,864				1,326				(49.8	%)			(29.4	%)
Canada			90				169				329				(46.7	%)			(72.6	%)
International			983				1,084				1,026				(9.3	%)			(4.2	%)
Worldwide			2,009				3,117				2,681				(35.5	%)			(25.1	%)
West Texas Intermediate Crude Prices (per barrel)		$	59.44			$	124.05			$	42.91				(52.1	%)			38.5	%
Natural Gas Prices ($/mmbtu)		$	3.71			$	11.38			$	4.57				(67.4	%)			(18.8	%)

The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended June 30, 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 36% (from 3,117 to 2,009) and 50% (from 1,864 to 936), respectively, in the second quarter of 2009 compared to the second quarter of 2008. The average per barrel price of West Texas Intermediate Crude decreased 52% (from $124.05 per barrel to $59.44 per barrel) and natural gas prices decreased 67% (from $11.38 per mmbtu to $3.71 per mmbtu) in the second quarter of 2009 compared to the second quarter of 2008.

U.S. rig activity at July 24, 2009 was 943 rigs compared to the second quarter average of 936 rigs. The price for West Texas Intermediate Crude was at $66.96 per barrel as of July 24, 2009, increasing 13% from the second quarter 2009 average.

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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Revenue:
Rig Technology		$	1,917			$	1,911			$	4,116			$	3,514
Petroleum Services & Supplies			913				1,124				1,927				1,954
Distribution Services			305				425				713				791
Elimination			(125	)			(135	)			(265	)			(249	)
Total Revenue		$	3,010			$	3,325			$	6,491			$	6,010
Operating Profit:
Rig Technology (a)		$	534			$	506			$	1,140			$	912
Petroleum Services & Supplies (b)(c)			(51	)			221				113				416
Distribution Services			10				25				35				44
Unallocated expenses and eliminations (d)			(99	)			(45	)			(174	)			(96	)
Transaction costs			(8	)			(16	)			(8	)			(16	)
Total Operating Profit		$	386			$	691			$	1,106			$	1,260
Operating Profit %:
Rig Technology (a)			27.9	%			26.5	%			27.7	%			26.0	%
Petroleum Services & Supplies (b)(c)			(5.6	%)			19.7	%			5.9	%			21.3	%
Distribution Services			3.3	%			5.8	%			4.9	%			5.5	%
Total Operating Profit %			12.8	%			20.8	%			17.0	%			21.0	%

Three Months Ended June 30, 2009 and 2008. Rig Technology revenue in the second quarter of 2009 was $1,917 million, an increase of $6 million compared to the same period in 2008. Backlog was $8.7 billion, down 19.5% from the same period last year. Revenue out of backlog increased 7.2%, offset by a 15.6% 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 $534 million for the second quarter ended June 30, 2009, an increase of $28 million (5.5%) over the same period of 2008. Operating profit percentage increased to 27.9%, up from 26.5% for the same prior year period primarily driven by a $16 million gain from a payment received on cancelled rig package.

Six Months Ended June 30, 2009 and 2008. Revenue for the first half of 2009 was $4,116 million, an increase of $602 million (17.1%) compared to the same period in 2008. Revenue out of backlog increased 26.4% offset by a 4.8% 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 six months of 2009 was $1,140 million, an increase of $228 million (25.0%) over the same period of 2008. Operating profit percentage increased to 27.7%, 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 June 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was $913 million for the second quarter of 2009 compared to $1,124 million for the second quarter of 2008, a decrease of $211 million (18.8%). The decrease was primarily attributable to continued decline in North American rig count activity as well as an unusually severe Canada seasonal break-up with average rig utilization at 11% for the second quarter of 2009.

Operating (loss) profit from Petroleum Services & Supplies was $(51) million for the second quarter of 2009 compared to $221 million for the same period in 2008, a decrease of $272 million (123.1%), and operating profit percentage decreased to (5.6%) down from 19.7% in the same period of 2008. 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. (See Note 3. for further detail). In addition, 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 58% since September 2008, and 52% since December 2008.

Six Months Ended June 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was $1,927 million for the first six months of 2009 compared to $1,954 million for the first six months of 2008, a decrease of $27 million (1.4%). The decrease was primarily attributable to a 38% decline in North American average rig count activity during the first half 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 $113 million for the first half of 2009 compared to $416 million for the same period in 2008, a decrease of $303 million (72.8%). Operating profit percentage decreased to 5.9% down from 21.3% 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. (See Note 3. for further detail). 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 June 30, 2009 and 2008. Revenue from Distribution Services was $305 million, a decrease of $120 million (28.2%) during the second 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. U.S. sales declined 45%, less than average North American rig count decline of 50% for the second quarter of 2009 over the comparable period in 2008.

Operating profit of $10 million in the second quarter of 2009 decreased $15 million from the second quarter of 2008. Operating profit percentage decreased to 3.3%, from 5.8% for the same prior year period as a result of reduced North American drilling activity.

Six Months Ended June 30, 2009 and 2008. Revenue from Distribution Services was $713 million, a decrease of $78 million (9.9%) during the first half of 2009 over the comparable 2008 period. The decrease in revenue is mainly concentrated in the North American region as average drilling activity declined 38% for the first half of 2009 over the comparable 2008 period. However, international revenues increased 25% over the same period in 2008 as a result of improved strategic alliances with drilling contractors and the success of the RigStore™ initiative that provides innovative supply chain solutions to install, staff and manage supply stores on offshore drilling rigs.

Operating profit of $35 million in the first six months of 2009 decreased $9 million over the first six months of 2008. Operating profit percentage decreased to 4.9%, from 5.5% for the same prior year period as a result of strong price competition and volume declines as North American rig activity continues to decline.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $99 million and $174 for the three and six months ended June 30, 2009, respectively, compared to $45 million and $96 million for the same periods in 2008. This increase is primarily due to greater

intercompany profit elimination related to sales between the segments. In addition, voluntary retirement costs were $46 million for the three and six months ending June 30, 2009 and were comprised of $39 million in severance and $7 million in stock based compensation.

Transaction costs

Transaction costs were $8 million for both the three and six months ending June 30, 2009. The transaction costs related to restructuring and other costs due to recent acquisitions. Transaction costs of $16 million for the three and six months ended June 30, 2008 were comprised of $6 million for accelerated vesting of stock-based compensation, $4 million for bridge loan fees, and $6 million related to transaction costs for the disposition of certain tubular businesses of Grant Prideco in May 2008.

Interest and financial costs were $13 million and $26 million for the three and six months ended June 30, 2009, compared to $24 million and $34 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 $38 million and $74 million for the three and six months ended June 30, 2009 compared to expense, net of $14 million and $1 million for the same periods in 2008. This is mainly due to an increase in foreign exchange charges and a decrease in interest income for the three and six months ending June 30, 2009.

Provision for income taxes

The effective tax rate for the three and six months ended June 30, 2009 was 37.3% and 34.1%, respectively, compared to 37.5% and 34.9% for the same periods in 2008. The second quarter 2009 tax rate, which was higher than periods preceding this quarter, was primarily affected by $21 million of additional tax provisions recognized in the period 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 return to the 32% to 33% range for the remainder of the year.

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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Federal income tax at U.S. federal statutory rate		$	124			$	238			$	369			$	444
Foreign income tax rate differential			(26	)			(23	)			(58	)			(43	)
State income tax, net of federal benefit			2				11				8				17
Foreign dividends, net of foreign tax credits			6				33				7				35
Benefit of U.S. Manufacturing Deduction			(3	)			(3	)			(7	)			(5	)
Nondeductible expenses			4				2				12				5
Prior year tax on revaluation gains in Norway			21				—				21				—
Other			3				(3	)			7				(10	)
Provision for income taxes		$	131			$	255			$	359			$	443

Liquidity and Capital Resources

Overview

At June 30, 2009, the Company had cash and cash equivalents of $2,286 million, and total debt of $881 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 June 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 $30 million.

The Company had $2,414 million of additional outstanding letters of credit at June 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 June 30, 2009.

There were no borrowings against the Company’s unsecured credit facilities, and there were $636 million in outstanding letters of credit issued under such facilities, resulting in $1,364 million of funds available under the Company’s unsecured revolving credit facilities at June 30, 2009.

Operating Activities

For the first six months of 2009, cash provided by operating activities increased $41 million to $1,285 million compared to cash provided by operating activities of $1,244 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 $695 million plus non-cash charges of $385 million and dividends from unconsolidated affiliates of $86 million less $44 million in equity income from the Company’s unconsolidated affiliate. Net changes in operating assets and liabilities, net of acquisitions, contributed another $168 million in cash provided by operating activities, a $93 million decrease from the same period in 2008. The decrease is primarily due to lower receivables, inventory and accounts payable.

Investing Activities

For the first six months of 2009, cash used in investing activities was $524 million compared to cash used in investing of $2,209 million for the same period of 2008. The primary reason for the decrease in cash used in investing activities for the first six months of 2009 related to a decrease in size of business acquisitions, net of cash acquired, to approximately $389 million compared to $2,945 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 $784 million received related to the disposition of certain Grant Prideco tubular businesses. In addition, the Company decreased its capital expenditures for the first six months of 2009 by $17 million, received $19 million less in dividends from its unconsolidated affiliate compared to the same period in 2008 and included $86 million of the dividends from unconsolidated affiliate received in 2009 in operating activities.

Financing Activities

For the first six months of 2009, cash used in financing activities was $33 million compared to cash provided by financing activities of $762 million for the same period of 2008. The cash used in financing activities for the first six months of 2009 related to $34 million cash payments on debt primarily acquired in the second quarter 2009 acquisitions, offset by cash proceeds from exercised stock options in the amount of $1 million. The borrowings and payments of debt in the first six months of 2008 primarily relates to the financing of the Grand Prideco acquisition. For the first six 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 $15 million and $13 million for the six months ended June 30, 2009 and 2008, respectively.

The Company’s cash balance as of June 30, 2009 was $2,286 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 also believe any significant increases in capital expenditures caused by any need to increase manufacturing capacity can be funded from operations or through debt financing.

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. 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”). SFAS 141R 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. SFAS 141R also expands required disclosures surrounding the nature and financial effects of business combinations. SFAS 141R is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted SFAS 141R. 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”). SFAS 160 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. SFAS 160 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 SFAS 160, and reclassified noncontrolling interests in the amounts of $88 million and $96 million from the mezzanine section to equity in the June 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”). SFAS 161 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. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. On January 1, 2009, the Company adopted SFAS 161. 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”). FSP SFAS 142-3 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 FSP 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. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted FSP SFAS 142-3. There was no significant impact to the Company’s consolidated financial statements from the adoption of FSP SFAS 142-3.

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”). FSP 141R-1 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 FSP 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. FSP 141R-1 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 FSP 141R-1 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”). FSP SFAS 107-1 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. FSP SFAS 107-1 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 FSP 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 FSP SFAS 107-1. There was no significant impact to the Company’s consolidated financial statements from the adoption of FSP SFAS 107-1.

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

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.” SFAS 168 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, SFAS 168 will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in SFAS 168 will become non-authoritative. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company is currently assessing the impact SFAS 168 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.

Forward-Looking Statements

Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward-looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products, difficulties encountered in integrating mergers and acquisitions, and worldwide economic activity. You should also consider carefully the statements under “Risk Factors,” as disclosed in our Annual Report on Form 10-K for the year ended December 31, 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 $56 million in the first six months of 2009, compared to a $7 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 June 30, 2009 (in millions, except contract rates):

		As of June 30, 2009																December 31,
Functional Currency		2009				2010				2011				Total				2008
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)			323				—				—				323				527
Average CAD to USD contract rate			1.2034				—				—				1.2034				1.1843
Fair Value at June 30, 2009 in U.S. dollars			(11	)			—				—				(11	)			14
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)			71				52				—				123				241
Average CAD to USD contract rate			1.0700				1.0961				—				1.0809				1.1196
Fair Value at June 30, 2009 in U.S. dollars			(5	)			(2	)			—				(7	)			(18	)
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)			66				—				—				66				11
Average USD to EUR contract rate			1.3570				—				—				1.3570				1.4397
Fair Value at June 30, 2009 in U.S. dollars			(3	)			—				—				(3	)			—
Sell USD/Buy EUR:
Notional amount to buy (in euros)			81				50				1				132				245
Average USD to EUR contract rate			1.3846				1.3317				1.4431				1.3647				1.3986
Fair Value at June 30, 2009 in U.S. dollars			2				4				—				6				1
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)			43				—				—				43				—
Average USD to GBP contract rate			1.5026				—				—				1.5026				—
Fair Value at June 30, 2009 in U.S. dollars			(6	)			—				—				(6	)			—