NOV Inc. - Quarter Report: 2010 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.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

As of August 2, 2010 the registrant had 419,081,502 shares of common stock, par value $.01 per share, outstanding.

 

 

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

NATIONAL OILWELL VARCO, INC.

		June 30,				December 31,
		2010				2009
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	2,688			$	2,622
Receivables, net			2,387				2,187
Inventories, net			3,443				3,490
Costs in excess of billings			802				740
Deferred income taxes			230				290
Prepaid and other current assets			276				269
Total current assets			9,826				9,598
Property, plant and equipment, net			1,792				1,836
Deferred income taxes			169				92
Goodwill			5,532				5,489
Intangibles, net			3,928				4,052
Investment in unconsolidated affiliate			358				393
Other assets			43				72
Total assets		$	21,648			$	21,532
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	598			$	584
Accrued liabilities			2,300				2,267
Billings in excess of costs			454				1,090
Current portion of long-term debt and short-term borrowings			352				7
Accrued income taxes			233				226
Total current liabilities			3,937				4,174
Long-term debt			519				876
Deferred income taxes			2,091				2,091
Other liabilities			264				163
Total liabilities			6,811				7,304
Commitments and contingencies
Stockholders’ equity:
Common stock — par value $.01; 419,054,572 and 418,451,731 shares issued and outstanding at June 30, 2010 and December 31, 2009			4				4
Additional paid-in capital			8,247				8,214
Accumulated other comprehensive income (loss)			(67	)			90
Retained earnings			6,544				5,805
Total Company stockholders’ equity			14,728				14,113
Noncontrolling interests			109				115
Total stockholders’ equity			14,837				14,228
Total liabilities and stockholders’ equity		$	21,648			$	21,532

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
Revenue		$	2,941			$	3,010			$	5,973			$	6,491
Cost of revenue			2,013				2,135				4,083				4,577
Gross profit			928				875				1,890				1,914
Selling, general and administrative			338				334				663				653
Intangible asset impairment			—				147				—				147
Transaction and restructuring costs			—				8				—				8
Operating profit			590				386				1,227				1,106
Interest and financial costs			(13	)			(13	)			(26	)			(26	)
Interest income			3				2				5				4
Equity income in unconsolidated affiliate			8				16				14				44
Other income (expense), net			(3	)			(38	)			(19	)			(74	)
Income before income taxes			585				353				1,201				1,054
Provision for income taxes			186				131				383				359
Net income			399				222				818				695
Net income (loss) attributable to noncontrolling interests			(2	)			2				(5	)			5
Net income attributable to Company		$	401			$	220			$	823			$	690
Net income attributable to Company per share:
Basic		$	0.96			$	0.53			$	1.97			$	1.66
Diluted		$	0.96			$	0.53			$	1.96			$	1.65
Cash dividends per share		$	0.10			$	—			$	0.20			$	—
Weighted average shares outstanding:
Basic			417				416				417				416
Diluted			419				418				419				417

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

		Six Months Ended
		June 30,
		2010				2009
Cash flows from operating activities:
Net income		$	818			$	695
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			251				238
Equity income in unconsolidated affiliate			(14	)			(44	)
Dividend from unconsolidated affiliate			17				86
Intangible asset impairment			—				147
Other, net			5				(5	)
Change in operating assets and liabilities, net of acquisitions:
Receivables			(205	)			590
Inventories			29				75
Costs in excess of billings			(62	)			28
Prepaid and other current assets			(6	)			(108	)
Accounts payable			13				(152	)
Billings in excess of costs			(636	)			(80	)
Other assets/liabilities, net			72				(185	)
Net cash provided by operating activities			282				1,285
Cash flows from investing activities:
Purchases of property, plant and equipment			(78	)			(143	)
Business acquisitions, net of cash acquired			(62	)			(389	)
Dividend from unconsolidated affiliate			16				8
Other			16				—
Net cash used in investing activities			(108	)			(524	)
Cash flows from financing activities:
Repayments on debt			(9	)			(34	)
Cash dividends paid			(84	)			—
Other, net			11				1
Net cash used in financing activities			(82	)			(33	)
Effect of exchange rates on cash			(26	)			15
Increase in cash equivalents			66				743
Cash and cash equivalents, beginning of period			2,622				1,543
Cash and cash equivalents, end of period		$	2,688			$	2,286
Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest		$	28			$	27
Income taxes		$	262			$	409

See notes to unaudited consolidated financial statements.

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

1. Basis of Presentation

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

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

In our opinion, the consolidated financial statements include all adjustments, all of which are of a normal, recurring nature, necessary for a fair presentation of the results for the interim periods. The results of operations for the three and six months ended June 30, 2010 are not necessarily indicative of the results to be expected for the full year.

Fair Value of Financial Instruments

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

2. Inventories, net

Inventories consist of (in millions):

		June 30,				December 31,
		2010				2009
Raw materials and supplies		$	703			$	704
Work in process			1,109				1,307
Finished goods and purchased products			1,631				1,479
Total		$	3,443			$	3,490

3. Accrued Liabilities

Accrued liabilities consist of (in millions):

		June 30,				December 31,
		2010				2009
Compensation		$	250			$	272
Customer prepayments and billings			409				500
Warranty			214				217
Interest			11				11
Taxes (non income)			73				95
Insurance			56				58
Accrued purchase orders			947				853
Fair value of derivatives			96				61
Other			244				200
Total		$	2,300			$	2,267

Service and Product Warranties

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

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

Balance at December 31, 2009		$	217
Net provisions for warranties issued during the year			32
Amounts incurred			(22	)
Foreign currency translation and other			(13	)
Balance at June 30, 2010		$	214

4. Costs and Estimated Earnings on Uncompleted Contracts

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

		June 30,				December 31,
		2010				2009
Costs incurred on uncompleted contracts		$	6,968			$	6,276
Estimated earnings			4,486				3,735
			11,454				10,011
Less: Billings to date			11,106				10,361
		$	348			$	(350	)
Costs and estimated earnings in excess of billings on uncompleted contracts		$	802			$	740
Billings in excess of costs and estimated earnings on uncompleted contracts			(454	)			(1,090	)
		$	348			$	(350	)

5. Comprehensive Income

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
Net income		$	399			$	222			$	818			$	695
Currency translation adjustments, net of tax			(62	)			112				(76	)			57
Changes in derivative financial instruments, net of tax			(55	)			83				(81	)			105
Changes in defined benefit plans, net of tax			—				(1	)			—				(1	)
Comprehensive income			282				416				661				856
Comprehensive income (loss) attributable to noncontrolling interest			(2	)			2				(5	)			5
Comprehensive income attributable to Company		$	284			$	414			$	666			$	851

The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in Other Comprehensive Income in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three months ended June 30, 2010, a majority of these local currencies weakened against the U.S. dollar resulting in a net decrease to Other Comprehensive Income of $62 million upon the translation of their financial statements from their local currency to the U.S. dollar.

During the first quarter of 2010, the Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar. As a result the Company converted its Venezuela ledgers to U.S. dollar functional currency, devalued monetary assets resulting in a $27 million charge, and wrote-down certain accounts receivable in view of deteriorating business conditions in Venezuela, resulting in an additional $11 million charge. The Company’s net investment in Venezuela was $38 million at June 30, 2010.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of accumulated Other Comprehensive Income related to the fair value of derivatives that have settled in the current or prior periods. The accumulated effect is a decrease in Other Comprehensive Income of $55 million (net of tax of $21 million) for the three months ended June 30, 2010.

6. Business Segments

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
Revenue:
Rig Technology		$	1,672			$	1,917			$	3,558			$	4,116
Petroleum Services & Supplies			1,033				913				1,956				1,927
Distribution Services			365				305				699				713
Elimination			(129	)			(125	)			(240	)			(265	)
Total Revenue		$	2,941			$	3,010			$	5,973			$	6,491
Operating Profit:
Rig Technology		$	505			$	534			$	1,086			$	1,140
Petroleum Services & Supplies			138				(51	)			251				113
Distribution Services			13				10				24				35
Unallocated expenses and eliminations			(66	)			(99	)			(134	)			(174	)
Transaction costs			—				(8	)			—				(8	)
Total Operating Profit		$	590			$	386			$	1,227			$	1,106
Operating Profit %:
Rig Technology			30.2	%			27.9	%			30.5	%			27.7	%
Petroleum Services & Supplies			13.4	%			(5.6	)%			12.8	%			5.9	%
Distribution Services			3.6	%			3.3	%			3.4	%			4.9	%
Total Operating Profit %			20.1	%			12.8	%			20.5	%			17.0	%

The Company had revenues of 17% and 19% of total revenue from one of its customers for the three and six months ended June 30, 2010, respectively, and revenues of 20% and 16% of total revenue from one of its customers for the three and six months ended June 30, 2009, respectively. 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.

7. Debt

Debt consists of (in millions):

		June 30,				December 31,
		2010				2009
Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011		$	150			$	150
Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011			202				205
Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012			200				200
Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012			151				151
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015			151				151
Other			17				26
Total debt			871				883
Less current portion			352				7
Long-term debt		$	519			$	876

Revolving Credit Facilities

On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2 billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility which was terminated early in February 2009. At June 30, 2010, there were no borrowings against the remaining credit facility, and there were $556 million in outstanding letters of credit issued under this facility, resulting in $1,444 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% subject to a ratings-based grid, or the prime rate.

The Company also had $1,604 million of additional outstanding letters of credit at June 30, 2010, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. The Company was in compliance with all covenants at June 30, 2010.

Other

Other debt includes approximately $3 million in promissory notes due to former owners of businesses acquired who remain employed by the Company.

8. Tax

The effective tax rate for the three and six months ended June 30, 2010 was 31.8% and 31.9%, respectively, compared to 37.1% and 34.1% for the same period in 2009. The effective tax rate was positively impacted by earnings taxed at lower rates in foreign jurisdictions, and the reversal of reserves associated with uncertain tax positions in prior years for which the statute of limitations expired during the period.

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
Federal income tax at U.S. federal statutory rate		$	205			$	124			$	420			$	369
Foreign income tax rate differential			(18	)			(26	)			(58	)			(58	)
State income tax, net of federal benefit			5				2				7				8
Foreign dividends, net of foreign tax credits			6				6				7				7
Benefit of U.S. Manufacturing Deduction			(3	)			(3	)			(6	)			(7	)
Nondeductible expenses			5				4				24				12
Prior year tax on revaluation gains in Norway			—				21				—				21
Other			(14	)			3				(11	)			7
Provision for income taxes		$	186			$	131			$	383			$	359

The Company accounts for uncertainty in income taxes in accordance with ASC Topic 740, “Income Taxes” (“ASC Topic 740”). ASC Topic 740 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a return. Under ASC Topic 740, the impact of an uncertain income tax position, in management’s opinion, on the income tax return must be recognized at the largest amount that is more-likely-than-not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has a less than 50% likelihood of being sustained. The balance of unrecognized tax benefits at June 30, 2010 was $117 million. Included in the change in the balance of unrecognized tax benefits was an increase of $73 million associated with a foreign tax position previously evaluated as more-likely-than-not to be sustained upon audit. Based on new information obtained in the first quarter of 2010, we now believe it is more-likely-than-not this foreign tax position may not be sustained. Tax payments for this liability can be claimed as a U.S. foreign tax credit due to sufficient excess limitation in prior years to cover the potential exposure. Accordingly, the company has recorded a corresponding deferred tax asset of $73 million, resulting in no impact to earnings.

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

Balance at December 31, 2009		$	58
Additions for tax positions of prior years			73
Reductions for lapse of applicable statutes of limitations			(14	)
Balance at June 30, 2010		$	117

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

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

9. Stock-Based Compensation

The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights. The number of shares authorized under the Plan is 25.5 million. As of June 30, 2010, 8,046,586 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 $16 million and $33 million for the three and six months ended June 30, 2010, respectively, and $15 million and $31 million for the three and six months ended June 30, 2009, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $5 million and $10 million for the three and six months ended June 30, 2010, respectively, and $7 million and $12 million for the three and six months ended June 30, 2009, respectively.

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

10. Derivative Financial Instruments

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

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

The Company records all derivative financial instruments at their fair value in 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, 2010, the Company has determined that its financial assets of $59 million and liabilities of $120 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At June 30, 2010, the net fair value of the Company’s foreign currency forward contracts totaled a liability of $61 million.

As of June 30, 2010, the Company did not have any interest rate swaps and our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

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

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

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

		Currency
Foreign Currency		Denomination
		(in millions)
British Pound Sterling		£	15
Danish Krone		DKK	74
Euro		€	137
Norwegian Krone		NOK	5,556
U.S. Dollar		$	326

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

		Currency
Foreign Currency		Denomination
		(in millions)
U.S. Dollar		$	17
Korean Won		KRW	5,479

Non-designated Hedging Strategy

For derivative instruments that are non-designated, the gain or loss on the derivative instrument subject to the hedged risk (i.e. nonfunctional currency monetary accounts) are recognized in 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, 2010, the Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts:

		Currency
Foreign Currency		Denomination
		(in millions)
British Pound Sterling		£	11
Danish Krone		DKK	112
Euro		€	156
Norwegian Krone		NOK	3,488
U.S. Dollar		$	472

As of June 30, 2010, the Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions):

		Asset Derivatives												Liability Derivatives
						Fair Value												Fair Value
		Balance Sheet				June 30,				December 31,				Balance Sheet				June 30,				December 31,
		Location				2010				2009				Location				2010				2009
Derivatives designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets				$	17			$	56			Accrued liabilities				$	55			$	39
Foreign exchange contracts		Other Assets					2				17			Other Liabilities					28				7
Total derivatives designated as hedging instruments under ASC Topic 815						$	19			$	73							$	83			$	46
Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets				$	40			$	30			Accrued liabilities				$	37			$	8
Foreign exchange contracts		Other Assets					—				1			Other Liabilities					—				1
Total derivatives not designated as hedging instruments under ASC Topic 815						$	40			$	31							$	37			$	9
Total derivatives						$	59			$	104							$	120			$	55

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

																						Location of Gain (Loss)
																						Recognized in Income on				Amount of Gain (Loss)
										Location of Gain (Loss)												Derivative (Ineffective				Recognized in Income on
										Reclassified from				Amount of Gain (Loss)								Portion and Amount				Derivative (Ineffective
Derivatives in ASC Topic 815		Amount of Gain (Loss)								Accumulated OCI into				Reclassified from								Excluded from				Portion and Amount
Cash Flow Hedging		Recognized in OCI on								Income				Accumulated OCI into								Effectiveness				Excluded from
Relationships		Derivative (Effective Portion) (a)								(Effective Portion)				Income (Effective Portion)								Testing)				Effectiveness Testing) (b)
		Six Months Ended												Six Months Ended												Six Months Ended
		June 30,												June 30,												June 30,
		2010				2009								2010				2009								2010				2009
										Revenue					6				10
Foreign exchange contracts			(116	)			74			Cost of revenue					(16	)			(44	)		Other income (expense), net					8				(24	)
Total			(116	)			74								(10	)			(34	)							8				(24	)

Derivatives in ASC Topic 815		Location of Gain (Loss)				Amount of Gain (Loss)								ASC Topic 815				Location of Gain (Loss)				Recognized in Income on
Fair Value		Recognized in Income				Recognized in Income on								Fair Value Hedge				Recognized in Income on				Related Hedged
Hedging Relationships		on Derivative				Derivative								Relationships				Related Hedged Item				Items
						Six Months Ended																Six Months Ended
						June 30,																June 30,
						2010				2009												2010				2009
Foreign exchange contracts		Revenue					(2	)			(2	)		Firm commitments				Revenue					2				2
Foreign exchange contracts		Cost of revenue					—				(1	)		Firm commitments				Cost of revenue					—				1
Total							(2	)			(3	)											2				3

Derivatives Not Designated as

Location of Gain (Loss)

Amount of Gain (Loss)

Hedging Instruments under

Recognized in Income

Recognized in Income on

ASC Topic 815

on Derivative

Derivative

Six Months Ended

June 30,

2010

2009

Foreign exchange contracts

Other income (expense), net

22

(26

)

Total

22

(26

)

11. Net Income Attributable to Company Per Share

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
Numerator:
Net income attributable to Company		$	401			$	220			$	823			$	690
Denominator:
Basic—weighted average common shares outstanding			417				416				417				416
Dilutive effect of employee stock options and other unvested stock awards			2				2				2				1
Diluted outstanding shares			419				418				419				417
Net income attributable to Company per share:
Basic		$	0.96			$	0.53			$	1.97			$	1.66
Diluted		$	0.96			$	0.53			$	1.96			$	1.65
Cash dividends per share		$	0.10			$	—			$	0.20			$	—

In addition, the Company had stock options outstanding that were anti-dilutive totaling 6 million and 5 million shares for the three and six months ended June 30, 2010, respectively, and 4 million and 10 million for the three and six months ending June 30, 2009, respectively.

12. Cash Dividends

On May 12, 2010, the Company’s Board of Directors approved a cash dividend of $0.10 per share. The cash dividend was paid on June 25, 2010 to each stockholder of record on June 11, 2010. Cash dividends aggregated $42 million and $84 million for the three and six months ended June 30, 2010, respectively, and nil for both the three and six months ended June 30, 2009. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Board of Directors.

13. Recently Issued Accounting Standards

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

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

Introduction

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

Rig Technology

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

Petroleum Services & Supplies

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

Distribution Services

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

Critical Accounting Estimates

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

EXECUTIVE SUMMARY

National Oilwell Varco generated $401 million in net income attributable to Company or $0.96 per fully diluted share on $2.9 billion in revenue in its second quarter ended June 30, 2010. Compared to the first quarter of 2010 revenue declined three percent and net income attributable to Company declined five percent. The first quarter of 2010 included impairment and devaluation charges of $38 million related to currency devaluations in Venezuela. Compared to the second quarter of 2009 revenue decreased two percent but net income attributable to the Company increased 82 percent, due in part to higher transaction, devaluation, voluntary retirement charges, and an intangible asset impairment charge during the second quarter of 2009 as compared to the second quarter of 2010.

Operating profit excluding transaction charges of $4 million was $594 million or 20.2 percent of sales in the second quarter of 2010, compared to $648 million or 21.4 percent of sales in the first quarter of 2010 excluding transaction and Venezuela devaluation charges of $11 million. Operating leverage or flow-through, the change in operating profit divided by the change in revenue, was 59 percent decremental from the first quarter of 2010 to the second quarter of 2010. Operating profit excluding transaction, impairment and voluntary retirement charges was $589 million or 19.6 percent of sales for the second quarter of 2009. Operating profit increased $5 million year-over-year, despite a decrease in revenues of $69 million.

Revenues, operating profit and operating margins increased both sequentially and year-over-year for the Company’s Petroleum Services & Supplies and Distribution Services segments. The Company’s Rig technology segment posted 11 percent lower revenues sequentially and 13 percent lower revenues compared to the prior year second quarter, due primarily to lower revenues from the segment’s backlog of capital equipment orders. The Company generally benefitted from initiatives undertaken throughout all three segments to reduce operating costs in view of depressed market conditions during 2009.

A moratorium on deepwater drilling in the Gulf of Mexico was enacted during the second quarter of 2010 following the Macondo well blowout and oil spill, which had a small impact on our financial results in the quarter. The Petroleum Services & Supplies segment discontinued several solids control and waste management jobs on affected rigs, but was able to largely redeploy the field crews into new areas elsewhere onshore. The Distribution Services segment posted higher sales in the Gulf Coast as it helped outfit the massive response effort with basic supplies. The Rig Technology group saw modestly lower purchases of spares and consumables among the affected rigs, but many of the affected rigs appear to be utilizing this period to conduct upgrade and maintenance activities, potentially resulting in higher sales of spares in coming months. Nevertheless we expect to see a larger negative impact overall, across all three segments, in the second half of the year as customers deal with more difficult permitting requirements, and are generally pausing to see the ultimate resolution of new pressure control equipment requirements. Consequently some specific purchases, such as drill pipe and conductor pipe connections, are at risk pending the outcome of this moratorium.

Oil & Gas Equipment and Services Market

Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks responded vigorously through 2009, but credit and financial markets have not yet fully recovered by mid-2010, and a credit-driven worldwide economic recession continues to dampen economic growth in many developed economies. As a result asset and commodity prices, including oil and gas prices, declined. After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to average $42.91 per barrel (West Texas Intermediate Crude Prices) during the first quarter of 2009, but recovered into the $70 to $80 per barrel range by the end of 2009 where they are holding steady (the second quarter of 2010 averaged $77.79 per barrel). North American gas prices declined to $3.17 per mmbtu in the third quarter of 2009 but recovered to average $4.32 per mmbtu in the second quarter of 2010. The steadily rising oil and gas prices seen between 2003 and 2008 led to high levels of exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit availability.

The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a low of 876 in June, 2009. U.S. rig count has since increased to 1,585 in late July 2010, and averaged 1,508 rigs during the second quarter of 2010. Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity in 2009, but drilling recovered across North America as gas prices firmed above $4.00 per mmbtu. Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings, but the international rig count has exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 986 in September 2009, but recently climbing back to 1,099 in June 2010.

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

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

The industry responded by launching many new rig construction projects since 2005, to 1.) retool the existing fleet of jackup rigs (according to Offshore Data Services, 71 percent of the existing 459 jackup rigs are more than 25 years old); 2.) 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 3.) 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 $4.9 billion by June 30, 2010. Approximately $2.4 billion of these orders are scheduled to flow out as revenue during the second half of 2010.

The land rig backlog comprised 19 percent and equipment destined for offshore operations comprised 81 percent of the total backlog as of June 30, 2010. Equipment destined for international markets totaled 86 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. Nevertheless since the third quarter of 2008 the Company removed $453 million in orders due to cancellations, adjustments, and changes requested by customers, which represents 3.8 percent of the starting backlog balance. We do not expect the credit crisis or softer market to result in additional material cancellation of contracts or abandonment of major projects; however, there can be no assurance that such discontinuance of projects will not occur.

Segment Performance

The Rig Technology segment revenues of $1.7 billion in the second quarter of 2010 declined 11 percent sequentially and declined 13 percent compared to the second quarter of 2009. Segment operating profit was $505 million and operating margins were 30.2 percent during the second quarter. Compared to the first quarter of 2010 decremental operating leverage or flow-through (the change in operating profit divided by the change in revenue) was 36 percent. Project margins increased again slightly as favorable cost experience on completed rig construction projects was applied to remaining estimated costs on ongoing projects, resulting in margins rising above original expectations. Many of these projects were contracted at high prices in 2007 and 2008, and are now being manufactured in much lower cost environments, and benefitting from greater project execution experience within the group. Additionally, downsizing in certain portions of our Rig Technology manufacturing infrastructure in the second half of 2009 contributed to the segment’s overall margin performance, which improved 230 basis points from the second quarter of 2009, but declined 60 basis points sequentially due to lower volumes. Non-backlog revenue improved 10 percent from the first quarter to the second quarter of 2010, led by higher sales of aftermarket spares and services. Orders for stimulation equipment, top drives, handling and lifting equipment, complete land rig packages for both domestic and international markets, and an order for one deepwater rig drilling equipment package for Brazil led to $689 million in gross orders booked into the backlog, which was slightly offset by $29 million in cancellations and negative change orders, resulting in net order additions of $660 million for the second quarter of 2010. Revenue out of backlog was $1,251 million, down 17 percent from the first quarter of 2010. Large shale play fracture stimulation jobs in North America are consuming equipment at a more rapid pace owing to the upturn in oilfield activity and higher equipment intensity in these types of jobs. Additionally, demand is shifting to larger diameter coiled tubing strings to stimulate wells and drill out

plugs, which led to demand for the Company’s well-intervention equipment in the quarter. Offshore rig sales have remained muted, with progress on a handful of projects on which the Company was bidding slowing during the second quarter as drilling contractors paused to monitor the impact of the deepwater moratorium. An exception to this is Brazil where the Company continues to pursue a large 28 deepwater rig tender. Tenders for these rigs were submitted to Petrobras by shipyards and drilling contractors during June and July 2010. The Company does not expect to book many orders from this tender until 2011. The orders from this tender will require a high and rising level of local content in the construction of new rigs. Additionally, a handful of drilling contractors have launched exploratory studies of new rig projects, soliciting budgetary quotes from shipyards for new deepwater rig build projects, in recent weeks. Customer inquiries for pressure control equipment are also trending higher, and orders for pressure control components, spares, repair and services rose during the second quarter, in response to the Macondo blowout. Accordingly we have ordered a substantial quantity of long lead-time Blowout Preventer (“BOP”) body forgings, to be in a position to quickly supply any needed replacements, additional cavities to enhance existing BOP stacks, as well as for additional capital spares.

The Petroleum Services & Supplies segment generated total sales of $1.0 billion in the second quarter of 2010, up 12 percent or $110 million from the first quarter of 2010 and up 13 percent or $120 million from the second quarter of 2009. Operating profit was $138 million or 13.4 percent of sales during the second quarter of 2010, compared to 12.2 percent in the first quarter and (5.6) percent in the second quarter of 2009. The second quarter of 2009 includes a $147 million impairment charge on the carrying value of a trade name. Operating leverage or flow-through was 23 percent from the first quarter of 2010 to the second quarter of 2010. Strong U.S. rig activity led to 17 percent sequentially higher revenues in the U.S. across most business lines within the segment. International sales increased 16 percent, and Canadian sales declined 22 percent, due principally to season declines in rig activity related to breakup, from the first quarter of 2010 to the second. Drill pipe sales improved significantly due to higher demand for premium drill pipe for shale drilling in the U.S. and higher sales in Asia. Sales of composite pipe rose sharply on large domestic and international project sales, and coiled tubing sales increased on rising demand from pressure pumping customers in North America. Sales of Mission pumps, Tuboscope inspection and coating services, solids control equipment, waste management services and drilling fluids also posted sequential increases largely due to higher domestic activity. Sales of bits and downhole tools increased in the U.S, as well, but were offset by lower international sales. Overall the U.S. accounted for 45 percent, Canada seven percent, and international markets accounted for 48 percent of the segment’s second quarter 2010 sales.

The Distribution Services segment generated $365 million in revenue during the second quarter of 2010, increasing 9 percent from the first quarter and increasing 20 percent from the second quarter of 2009. Operating profit was $13 million, and operating margin was 3.6 percent of sales. Operating leverage or flow-through was six percent sequentially and five percent year-over-year for the second quarter. The segment posted 24 percent sequential revenue increases in the U.S., led by higher sales into increased shale play well hookups, higher sales of consumables to outfit newly constructed land rigs, and higher sales into the Gulf of Mexico cleanup effort. Canadian sales declined 19 percent due to the seasonal second quarter breakup, which drove rig counts 65 percent lower during the quarter. International and Mono industrial sales improved modestly but margins declined due to mix.

Outlook

While the credit market downturn, global recession, and lower commodity prices presented challenges to our business in 2009, we believe we are seeing signs of stabilization in many of our markets. Specifically we are encouraged by higher drilling activity in North America on gas price strengthening, and steadily higher international activity on higher oil prices. Order levels for new drilling rigs declined significantly in 2009 as compared to 2008 due to credit market conditions and softer rig activity, but we were able to secure an order for one Brazil deepwater rig during the second quarter. We have signed two more contracts which are expected to flow into backlog during the third quarter of 2010, but are cancellable without penalty subject to our receipt of a down payment from our customer. We also continue to bid up to 28 new offshore floating rigs to be built in Brazil. We are hopeful that these will translate into orders in 2011. Nevertheless the events in the Gulf of Mexico during the second quarter are likely to slow orders, except for Brazil and recent high interest in pressure control equipment. We expect lower backlogs to lead to modest declines in Rig Technology revenues and margins over the next few quarters before new offshore rig construction projects can translate into higher revenues.

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

The Company believes it is well positioned to continue to manage through this downturn, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders which are expected to continue to generate earnings during the remainder of year. The Company has a long history of cost-control and downsizing in response to depressed market conditions, and of executing strategic acquisitions during difficult periods. Such a period may present opportunities to the Company to effect new organic growth and acquisition initiatives, and we remain hopeful that the current downturn will continue to 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 2010 and 2009, and the first quarter of 2010 include the following:

														%				%
														2Q10 v				2Q10 v
		2Q10*				1Q10*				2Q09*				1Q10				2Q09
Active Drilling Rigs:
U.S.			1,508				1,345				936				12.1	%			61.1	%
Canada			166				470				90				(64.7	)%			84.4	%
International			1,088				1,063				983				2.4	%			10.7	%
Worldwide			2,762				2,878				2,009				(4.0	)%			37.5	%
West Texas Intermediate Crude Prices (per barrel)		$	77.79			$	78.64			$	59.44				(1.1	)%			30.9	%
Natural Gas Prices ($/mmbtu)		$	4.32			$	5.15			$	3.71				(16.1	)%			16.4	%

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, 2010 on a quarterly basis:

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

The worldwide and U.S. quarterly average rig count decreased 4% (from 2,878 to 2,762) and increased 12% (from 1,345 to 1,508), respectively, in the second quarter compared to the first quarter of 2010. The average per barrel price of West Texas Intermediate Crude decreased 1% (from $78.64 per barrel to $77.79 per barrel) and natural gas prices decreased 16% (from $5.15 per mmbtu to $4.32 per mmbtu) in the second quarter compared to the first quarter of 2010.

U.S. rig activity at July 23, 2010 was 1,585 rigs compared to the first quarter average of 1,508 rigs, increasing 5%. The price for West Texas Intermediate Crude was at $78.98 per barrel as of July 23, 2010, increasing 2% from the second quarter 2010 average. The price for natural gas was at $4.58 per mmbtu as of July 23, 2010, increasing 6% from the second quarter 2010 average.

Results of Operations

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
Revenue:
Rig Technology		$	1,672			$	1,917			$	3,558			$	4,116
Petroleum Services & Supplies			1,033				913				1,956				1,927
Distribution Services			365				305				699				713
Elimination			(129	)			(125	)			(240	)			(265	)
Total Revenue		$	2,941			$	3,010			$	5,973			$	6,491
Operating Profit:
Rig Technology		$	505			$	534			$	1,086			$	1,140
Petroleum Services & Supplies			138				(51	)			251				113
Distribution Services			13				10				24				35
Unallocated expenses and eliminations			(66	)			(99	)			(134	)			(174	)
Transaction costs			—				(8	)			—				(8	)
Total Operating Profit		$	590			$	386			$	1,227			$	1,106
Operating Profit %:
Rig Technology			30.2	%			27.9	%			30.5	%			27.7	%
Petroleum Services & Supplies			13.4	%			(5.6	)%			12.8	%			5.9	%
Distribution Services			3.6	%			3.3	%			3.4	%			4.9	%
Total Operating Profit %			20.1	%			12.8	%			20.5	%			17.0	%

Rig Technology

Three Months Ended June 30, 2010 and 2009. Rig Technology revenue in the second quarter of 2010 was $1,672 million, a decrease of $245 million (12.8%) compared to the same period in 2009, primarily due to the decrease of revenue out of backlog of $183 million as total backlog declined 44% to $4.9 billion.

Operating profit from Rig Technology was $505 million for the second quarter ended June 30, 2010, a decrease of $29 million (5.4%) over the same period of 2009. Operating profit percentage increased to 30.2%, up from 27.9% for the same prior year period primarily due to declining costs resulting in estimate revisions on large rig projects and improved manufacturing efficiencies.

Six Months Ended June 30, 2010 and 2009. Rig Technology revenue for the first half of 2010 was $3,558 million, a decrease of $558 million (13.6%) compared to the same period in 2009. Revenue out of backlog decreased 11.7% due to the decline in overall and non-backlog revenue decreased 19.4% primarily due to lower small capital equipment shipments in 2010.

Operating profit from Rig Technology for the first half of 2010 was $1,086 million, a decrease of $54 million (4.7%) over the same period of 2009. Operating profit percentage increased to 30.5%, up from 27.7% for the same prior year period primarily due to declining costs resulting in estimate revisions on large rig projects as well as improved manufacturing efficiencies.

Petroleum Services & Supplies

Three Months Ended June 30, 2010 and 2009. Revenue from Petroleum Services & Supplies was $1,033 million for the second quarter of 2010 compared to $913 million for the second quarter of 2009, an increase of $120 million (13.1%). The increase was primarily attributable to a strong U.S. market with a 61% increase in rig activity compared to the second quarter of 2009.

Operating  profit from Petroleum Services & Supplies was $138 million for the second quarter of 2010 compared to an operating loss of $51 million for the same period in 2009, an increase of $189 million (370.6%). Operating profit percentage increased to 13.4% compared to a negative 5.6% in the same period of 2009. The second quarter 2009 results included a $147 million impairment charge on the carrying value of a trade name associated with this segment. In addition, strong domestic demand fueled by an increase in rig count contributed to increased operating profit.

Six Months Ended June 30, 2010 and 2009. Revenue from Petroleum Services & Supplies was $1,956 million for the first half of 2010 compared to $1,927 million for the first half of 2009, an increase of $29 million (1.5%). The increase was primarily attributable to a higher level of rig activity in the U.S. market.

Operating profit from Petroleum Services & Supplies was $251 million for the first half of 2010 compared to $113 million for the same period in 2009, an increase of $138 million (122.1%), and operating profit percentage increased to 12.8% up from 5.9% in the same period of 2009. The first half of 2009 results included a $147 million impairment charge on the carrying value of a trade name associated with this segment. In addition, strong demand fueled by an increase in domestic rig count contributed to the increase in operating profit.

Distribution Services

Three Months Ended June 30, 2010 and 2009. Revenue from Distribution Services was $365 million, an increase of $60 million (19.7%) during the second quarter of 2010 over the comparable 2009 period. This increase was primarily attributable to increased U.S. rig count activity in general and due to the oil-spill in the Gulf of Mexico, which drove significant emergency project work during the period.

Operating profit from Distribution Services was $13 million for the second quarter of 2010, an increase of $3 million over the same period in 2009. Operating profit percentage increased to 3.6%, from 3.3% for the same prior year period as a result of the increased volumes in the quarter.

Six Months Ended June 30, 2010 and 2009. Revenue from Distribution Services was $699 million, a decrease of $14 million (2.0%) during the first half of 2010 over the comparable 2009 period. This decrease was primarily attributable to increased bidding by customers in the International arena, resulting in reduced revenues.

Operating profit from Distribution Services was $24 million for the first half of 2010, a decrease of $11 million over the same period in 2009. Operating profit percentage decreased to 3.4%, from 4.9% for the same prior year period primarily as a result of pricing pressures and reduced demand for artificial lift products internationally.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $66 million and $134 million for the three and six months ended June 30, 2010, respectively, compared to $99 million and $174, respectively, for the same periods in 2009. This decrease is primarily due to $46 million of voluntary retirement costs that were taken in the three and six months ended June 30, 2009. This was slightly offset by higher intercompany profit elimination related to sales between the segments and an $11 million write-down of certain accounts receivable in Venezuela during the first half of 2010.

Interest and financial costs

Interest and financial costs remained constant at $13 million and $26 million for both the three and six months ended June 30, 2010 and 2009, respectively, due to overall debt levels and interest rates remaining constant for the same respective periods.

Other income (expense), net

Other income (expense), net were expenses, net of $3 million and $19 million for the three and six months ended June 30, 2010, respectively, compared to $38 million and $74 million, respectively for the same periods in 2009. The decrease in other expense was mainly due to lower foreign exchange losses in 2010 as a result of favorable exchange rate movements in 2010, primarily related to the strengthening of the U.S. dollar. The decrease for the six months ended June 30, 2010 was offset by a $27 million charge relating to the devaluation of monetary assets the Company has in Venezuela. The charge was a result of the Venezuela bolivar being officially devalued against the U.S. dollar.

Provision for income taxes

The effective tax rate for the three and six months ended June 30, 2010 was 31.8% and 31.9%, respectively, compared to 37.1% and 34.1% for the same period in 2009. The effective tax rate was positively impacted by earnings taxed at lower rates in foreign jurisdictions, and the reversal of reserves associated with uncertain tax positions in prior years for which the statute of limitations expired during the period.

Liquidity and Capital Resources

Overview

At June 30, 2010, the Company had cash and cash equivalents of $2,688 million, and total debt of $871 million. At December 31, 2009, cash and cash equivalents were $2,622 million and total debt was $883 million. A significant portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. Rather than repatriating this cash, the Company may choose to borrow against our credit facility. The Company’s outstanding debt at June 30, 2010 consisted of $200 million of 5.65% Senior Notes due 2012, $200 million of 7.25% Senior Notes due 2011, $150 million of 6.5% Senior Notes due 2011, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $20 million.

There were no borrowings against the Company’s unsecured credit facility, and there were $556 million in outstanding letters of credit issued under the facility, resulting in $1,444 million of funds available under the Company’s unsecured revolving credit facility at June 30, 2010.

The Company had $1,604 million of additional outstanding letters of credit at June 30, 2010, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. The Company was in compliance with all covenants at June 30, 2010.

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

		Six Months
		Ended
		June 30,
		2010				2009
Net cash provided by operating activities		$	282			$	1,285
Net cash used in investing activities			(108	)			(524	)
Net cash used in financing activities			(82	)			(33	)

Operating Activities

For the first six months of 2010, cash provided by operating activities decreased $1,003 million to $282 million compared to cash provided by operating activities of $1,285 million in the same period of 2009. The primary reason for the decrease relates to total customer financing on projects, in the form of prepayments and billings in excess of costs, less costs in excess of billings being down approximately $790 million from December 31, 2009 due to the increase in revenues out of backlog during the first half of 2010. In addition, a $205 million increase in accounts receivable contributed to the overall decrease in cash provided by operating activities.

Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations during the first half of 2010 primarily through net income of $818 million plus non-cash charges of $251 million and dividends from the Company’s unconsolidated affiliate of $17 million less $14 million in equity income from the Company’s unconsolidated affiliate. During the first six months of 2010, net changes in operating assets and liabilities, net of acquisitions, decreased cash provided by operating activities by $963 million.

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

Investing Activities

For the first six months of 2010, cash used in investing activities was $108 million compared to cash used in investing of $524 million for the same period of 2009. The primary reason for the decrease in cash used in investing activities for the first six months of 2010 related to a decrease in business acquisitions to approximately $62 million compared to $389 million used in the same period of 2009. Capital expenditures decreased to approximately $78 million compared to $143 million used in the same period of 2009. The decreases in cash used in investing activities were offset by an increase in the portion of a dividend received by the Company’s unconsolidated affiliate during the first six months of 2010 that related to investing activities.

Financing Activities

For the first six months of 2010, cash used in financing activities was $82 million compared to cash used in financing activities of $33 million for the same period of 2009. The increase in cash used in financing activities for the first six months of 2010 primarily related to $84 million in cash dividends paid. No such dividends were paid in the same period of 2009. This increase was partially offset by a decrease in payments on debt to approximately $9 million for the first six months of 2010 compared to $34 million for the same period in 2009. For the first six months of 2010, the Company used its cash on hand to fund its acquisitions.

The effect of the change in exchange rates on cash flows was a negative $26 million and a positive $15 million for the six months ended June 30, 2010 and 2009, respectively.

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

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

Recently Issued Accounting Standards

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

Forward-Looking Statements

Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward-looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products, difficulties encountered in integrating mergers and acquisitions, and worldwide economic activity. You should also consider carefully the statements under “Risk Factors,” as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Item 3.		Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that do impact income. We recorded a foreign exchange loss in our income statement of approximately $14 million in the first six months of 2010, compared to a $56 million foreign exchange loss in the same period of the prior year. The gains/losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of the current economic environment. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods as of June 30, 2010 (in millions, except contract rates):

		As of June 30, 2010																December 31,
Functional Currency		2010				2011				2012				Total				2009
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)			261				—				—				261				291
Average CAD to USD contract rate			1.0020				—				—				1.0020				1.0418
Fair Value at June 30, 2010 in U.S. dollars			12				—				—				12				2
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)			84				14				—				98				69
Average CAD to USD contract rate			1.0546				1.0466				—				1.0535				1.1109
Fair Value at June 30, 2010 in U.S. dollars			1				—				—				1				4
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)			78				—				—				78				98
Average USD to EUR contract rate			1.3615				—				—				1.3615				1.4356
Fair Value at June 30, 2010 in U.S. dollars			11				—				—				11				—
Sell USD/Buy EUR:
Notional amount to buy (in euros)			34				55				—				89				91
Average USD to EUR contract rate			1.4469				1.2934				—				1.3517				1.3896
Fair Value at June 30, 2010 in U.S. dollars			(8	)			(4	)			—				(12	)			4
KRW Sell EUR/Buy KRW:
Notional amount to buy (in South Korean won)			1,364				273				—				1,637				5,050
Average KRW to EUR contract rate			1,742.53				1,742.53				—				1,742.53				1,639.00
Fair Value at June 30, 2010 in U.S. dollars			—				—				—				—				—

		As of June 30, 2010																December 31,
Functional Currency		2010				2011				2012				Total				2009
Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)			46,074				61,779				3,264				111,117				153,226
Average KRW to USD contract rate			1,024.73				1,083.50				1,118.05				1,059.27				1,046.00
Fair Value at June 30, 2010 in U.S. dollars			(7	)			(6	)			—				(13	)			(18	)
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)			16				—				—				16				11
Average USD to GBP contract rate			1.5437				—				—				1.5437				1.5880
Fair Value at June 30, 2010 in U.S. dollars			1				—				—				1				—
Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)			39				26				—				65				2
Average USD to GBP contract rate			1.4787				1.4415				—				1.4638				1.5313
Fair Value at June 30, 2010 in U.S. dollars			1				2				—				3				—
USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)			24				2				—				26				44
Average DKK to USD contract rate			5.4400				5.7934				—				5.4700				5.1219
Fair Value at June 30, 2010 in U.S. dollars			(3	)			—				—				(3	)			(1	)
Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)			255				36				—				291				382
Average USD to EUR contract rate			1.3500				1.2859				—				1.3416				1.4578
Fair Value at June 30, 2010 in U.S. dollars			(24	)			(2	)			—				(26	)			(7	)
Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)			36				1				—				37				76
Average USD to GBP contract rate			1.5553				1.4368				—				1.5528				1.6348
Fair Value at June 30, 2010 in U.S. dollars			(1	)			—				—				(1	)			(2	)
Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)			467				388				151				1,006				1,094
Average NOK to USD contract rate			6.2084				6.2329				6.1740				6.2127				6.2269
Fair Value at June 30, 2010 in U.S. dollars			(22	)			(20	)			(9	)			(51	)			67
Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)			6				—				—				6				6
Average DKK to USD contract rate			6.0790				—				—				6.0790				5.0009
Fair Value at June 30, 2010 in U.S. dollars			—				—				—				—				—
Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)			89				4				—				93				56
Average USD to EUR contract rate			1.2433				1.2757				—				1.2447				1.4324
Fair Value at June 30, 2010 in U.S. dollars			2				—				—				2				—
Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)			417				28				4				449				408
Average NOK to USD contract rate			6.2537				6.1162				6.1366				6.2442				5.8307
Fair Value at June 30, 2010 in U.S. dollars			17				2				—				19				—
Other Currencies
Fair Value at June 30, 2010 in U.S. dollars			(3	)			(1	)			—				(4	)			—
Total Fair Value at June 30, 2010 in U.S. dollars			(23	)			(29	)			(9	)			(61	)			49