NOV Inc. - Quarter Report: 2011 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.)

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 (Do not check if a smaller reporting company)		Smaller reporting company o

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

As of August 1, 2011 the registrant had 423,677,637 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,
		2011				2010
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	3,440			$	3,333
Receivables, net			2,849				2,425
Inventories, net			3,756				3,388
Costs in excess of billings			499				815
Deferred income taxes			301				316
Prepaid and other current assets			381				258
Total current assets			11,226				10,535
Property, plant and equipment, net			1,921				1,840
Deferred income taxes			179				341
Goodwill			5,949				5,790
Intangibles, net			4,063				4,103
Investment in unconsolidated affiliate			361				386
Other assets			57				55
Total assets		$	23,756			$	23,050
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	745			$	628
Accrued liabilities			2,179				2,105
Billings in excess of costs			778				511
Current portion of long-term debt and short-term borrowings			2				373
Accrued income taxes			178				468
Deferred income taxes			368				451
Total current liabilities			4,250				4,536
Long-term debt			511				514
Deferred income taxes			1,815				1,885
Other liabilities			275				253
Total liabilities			6,851				7,188
Commitments and contingencies
Stockholders’ equity:
Common stock — par value $.01; 423,228,599 and 421,141,751 shares issued and outstanding at June 30, 2011 and December 31, 2010			4				4
Additional paid-in capital			8,466				8,353
Accumulated other comprehensive income			225				91
Retained earnings			8,095				7,300
Total Company stockholders’ equity			16,790				15,748
Noncontrolling interests			115				114
Total stockholders’ equity			16,905				15,862
Total liabilities and stockholders’ equity		$	23,756			$	23,050

See notes to unaudited consolidated financial statements.

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

		Three Months Ended June 30,								Six Months Ended June 30,
		2011				2010				2011				2010
Revenue		$	3,513			$	2,941			$	6,659			$	5,973
Cost of revenue			2,430				2,013				4,601				4,083
Gross profit			1,083				928				2,058				1,890
Selling, general and administrative			375				338				741				663
Operating profit			708				590				1,317				1,227
Interest and financial costs			(9	)			(13	)			(23	)			(26	)
Interest income			4				3				8				5
Equity income in unconsolidated affiliate			10				8				23				14
Other income (expense), net			(7	)			(3	)			(26	)			(19	)
Income before income taxes			706				585				1,299				1,201
Provision for income taxes			226				186				415				383
Net income			480				399				884				818
Net loss attributable to noncontrolling interests			(1	)			(2	)			(4	)			(5	)
Net income attributable to Company		$	481			$	401			$	888			$	823
Net income attributable to Company per share:
Basic		$	1.14			$	0.96			$	2.11			$	1.97
Diluted		$	1.13			$	0.96			$	2.10			$	1.96
Cash dividends per share		$	0.11			$	0.10			$	0.22			$	0.20
Weighted average shares outstanding:
Basic			422				417				421				417
Diluted			425				419				424				419

See notes to unaudited consolidated financial statements.

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

		Six Months Ended
		June 30,
		2011				2010
Cash flows from operating activities:
Net income		$	884			$	818
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			273				251
Deferred income taxes			(9	)			(85	)
Equity income in unconsolidated affiliate			(23	)			(14	)
Dividend from unconsolidated affiliate			45				17
Other, net			33				5
Change in operating assets and liabilities, net of acquisitions:
Receivables			(379	)			(205	)
Inventories			(363	)			29
Costs in excess of billings			316				(62	)
Prepaid and other current assets			(110	)			(6	)
Accounts payable			88				13
Billings in excess of costs			267				(636	)
Other assets/liabilities, net			(135	)			157
Net cash provided by operating activities			887				282
Cash flows from investing activities:
Purchases of property, plant and equipment			(192	)			(78	)
Business acquisitions, net of cash acquired			(259	)			(62	)
Dividend from unconsolidated affiliate			13				16
Other			14				16
Net cash used in investing activities			(424	)			(108	)
Cash flows from financing activities:
Repayments on debt			(372	)			(9	)
Cash dividends paid			(93	)			(84	)
Proceeds from stock options exercised			71				8
Other, net			16				3
Net cash used in financing activities			(378	)			(82	)
Effect of exchange rates on cash			22				(26	)
Increase in cash and cash equivalents			107				66
Cash and cash equivalents, beginning of period			3,333				2,622
Cash and cash equivalents, end of period		$	3,440			$	2,688
Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest		$	30			$	28
Income taxes		$	712			$	262

See notes to unaudited consolidated financial statements.

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

1. Basis of Presentation

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

The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (the “Company”) present information in accordance with GAAP in the United States for interim financial information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not include all information or footnotes required by GAAP in the United States for complete consolidated financial statements and should be read in conjunction with our 2010 Annual Report on Form 10-K.

In our opinion, the consolidated financial statements include all adjustments, all of which are of a normal recurring nature, necessary for a fair presentation of the results for the interim periods. The results of operations for the three and six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year.

Fair Value of Financial Instruments

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

2. Inventories, net

Inventories consist of (in millions):

		June 30,				December 31,
		2011				2010
Raw materials and supplies		$	772			$	661
Work in process			1,139				953
Finished goods and purchased products			1,845				1,774
Total		$	3,756			$	3,388

3. Accrued Liabilities

Accrued liabilities consist of (in millions):

		June 30,				December 31,
		2011				2010
Customer prepayments and billings		$	675			$	387
Accrued purchase orders			522				597
Compensation			288				403
Warranty			230				215
Taxes (non income)			91				93
Insurance			67				49
Fair value of derivatives			19				22
Interest			5				11
Other			282				328
Total		$	2,179			$	2,105

Service and Product Warranties

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

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

Balance at December 31, 2010		$	215
Net provisions for warranties issued during the year			33
Amounts incurred			(20	)
Foreign currency translation and other			2
Balance at June 30, 2011		$	230

4. Costs and Estimated Earnings on Uncompleted Contracts

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

		June 30,				December 31,
		2011				2010
Costs incurred on uncompleted contracts		$	6,868			$	6,676
Estimated earnings			4,743				4,665
			11,611				11,341
Less: Billings to date			11,890				11,037
		$	(279	)		$	304
Costs and estimated earnings in excess of billings on uncompleted contracts		$	499			$	815
Billings in excess of costs and estimated earnings on uncompleted contracts			(778	)			(511	)
		$	(279	)		$	304

5. Comprehensive Income

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Net income		$	480			$	399			$	884			$	818
Currency translation adjustments			28				(62	)			92				(76	)
Changes in derivative financial instruments, net of tax			5				(55	)			42				(81	)
Comprehensive income			513				282				1,018				661
Comprehensive loss attributable to noncontrolling interest			(1	)			(2	)			(4	)			(5	)
Comprehensive income attributable to Company		$	514			$	284			$	1,022			$	666

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 and six months ended June 30, 2011, a majority of these local currencies strengthened against the U.S. dollar resulting in a net increase to Other Comprehensive Income of $28 million and $92 million, respectively, upon the translation of their financial statements from their local currency to the U.S. dollar.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of accumulated Other Comprehensive Income related to the fair value of derivatives that have settled in the current or prior periods. The accumulated effect is an increase in Other Comprehensive Income of $5 million (net of tax of $2 million) and $42 million (net of tax of $16 million) for the three and six months ended June 30, 2011, respectively.

6. Business Segments

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Revenue:
Rig Technology		$	1,894			$	1,672			$	3,502			$	3,558
Petroleum Services & Supplies			1,359				1,033				2,624				1,956
Distribution Services			423				365				833				699
Elimination			(163	)			(129	)			(300	)			(240	)
Total Revenue		$	3,513			$	2,941			$	6,659			$	5,973
Operating Profit:
Rig Technology		$	514			$	505			$	933			$	1,086
Petroleum Services & Supplies			249				138				480				251
Distribution Services			25				13				52				24
Unallocated expenses and eliminations			(80	)			(66	)			(148	)			(134	)
Total Operating Profit		$	708			$	590			$	1,317			$	1,227
Operating Profit %:
Rig Technology			27.1	%			30.2	%			26.6	%			30.5	%
Petroleum Services & Supplies			18.3	%			13.4	%			18.3	%			12.8	%
Distribution Services			5.9	%			3.6	%			6.2	%			3.4	%
Total Operating Profit %			20.2	%			20.1	%			19.8	%			20.5	%

The Company had revenues of 12% of total revenue from one of its customers for each of the three and six months ended June 30, 2011, and revenues of 17% and 19% of total revenue from one of its customers for the three and six months ended June 30, 2010, respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.

7. Debt

Debt consists of (in millions):

		June 30,				December 31,
		2011				2010
Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011		$	—			$	150
Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011			—				201
Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012			200				200
Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012			150				151
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015			151				151
Other			12				34
Total debt			513				887
Less current portion			2				373
Long-term debt		$	511			$	514

Senior Notes

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

Revolving Credit Facilities

On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2 billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility which was terminated early in February 2009. At June 30, 2011 there were no borrowings against the remaining credit facility, and there were $559 million in outstanding letters of credit issued under this facility, resulting in $1,441 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% subject to a ratings-based grid, or the prime rate. The credit facility contains a financial covenant regarding maximum debt to capitalization and the Company was in compliance at June 30, 2011.

The Company also had $1,716 million of additional outstanding letters of credit at June 30, 2011, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds.

8. Tax

The effective tax rate for the three and six months ended June 30, 2011 was 32.0% and 31.9%, respectively, compared to 31.8% and 31.9% for the same period in 2010. The effective tax rate was positively impacted in the period by an increase in income earned in foreign jurisdictions with tax rates lower than the U.S. federal statutory rate, which are indefinitely reinvested. This was offset by an increase in nondeductible expenses incurred in foreign jurisdictions.

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,
		2011				2010				2011				2010
Federal income tax at U.S. federal statutory rate		$	247			$	205			$	455			$	420
Foreign income tax rate differential			(41	)			(18	)			(65	)			(58	)
State income tax, net of federal benefit			5				5				11				7
Nondeductible expenses			14				5				24				24
Tax benefit of manufacturing deduction			(6	)			(3	)			(12	)			(6	)
Foreign dividends, net of foreign tax credits			5				6				10				7
Tax rate change on temporary differences			—				—				(13	)			—
Change in uncertain tax positions and other			2				(14	)			5				(11	)
Provision for income taxes		$	226			$	186			$	415			$	383

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

The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The Company has significant operations in the U.S., Canada, the U.K., the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdiction vary by legal entity, but are generally open in the U.S. for the tax years after 2006 and outside the U.S. for tax years ending after 2004.

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

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

9. Stock-Based Compensation

The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights. The number of shares authorized under the Plan is 25.5 million. As of June 30, 2011, 5,647,612 shares remain available for future grants under the Plan, all of which are available for grants of stock options, performance-based share awards, restricted stock awards, phantom shares, stock payments and stock appreciation rights. Total stock-based compensation for all stock-based compensation arrangements under the Plan was $19 million and $36 million for the three and six months ended June 30, 2011, respectively, and $16 million and $33 million for the three and six months ended June 30, 2010, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $6 million and $11 million for the three and six months ended June 30, 2011, respectively, and $5 million and $10 million for the three and six months ended June 30, 2010, respectively.

During the six months ended June 30, 2011, the Company granted 2,277,946 stock options and 374,425 shares of restricted stock and restricted stock units, which includes 131,300 performance-based restricted stock awards. Out of the total number of stock options granted, 2,255,322 were granted February 22, 2011 with an exercise price of $79.80. These options generally vest over a three-year period from the grant date. The remaining 22,624 options were granted May 19, 2011 to the non-employee members of the board of directors at an exercise price of $67.93. These options generally vest over a three-year period from the grant date. Out of the total number of restricted stock and restricted stock units, 234,620 were granted February 22, 2011 and vest on the third anniversary of the date of grant. On May 19, 2011, 8,505 restricted stock awards were granted to the non-employee members of the board of directors. These restricted stock awards vest in equal thirds over three years on the anniversary of the grant date. The performance-based restricted stock awards were granted February 22, 2011. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s operating income growth, measured on a percentage basis, from January 1, 2011 through December 31, 2013 exceeding the median operating income level growth of a designated peer group over the same period.

10. Derivative Financial Instruments

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

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

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

At June 30, 2011, the Company has determined that its financial assets of $95 million and liabilities of $20 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At June 30, 2011, the net fair value of the Company’s foreign currency forward contracts totaled an asset of $75 million.

As of June 30, 2011, the Company did not have any interest rate swaps and its financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

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

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

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

		Currency Denomination
		June 30,				December 31,
Foreign Currency		2011				2010
British Pound Sterling		£	12			£	4
Danish Krone		DKK	74			DKK	31
Euro		€	262			€	122
Norwegian Krone		NOK	5,274			NOK	4,983
U.S. Dollar		$	379			$	247
Japanese Yen		¥	122			¥	-
Singapore Dollar		SGD	5			SGD	-

Fair Value Hedging Strategy

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

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

The Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency fair values of firm commitments of revenues and costs (in millions):

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

Non-designated Hedging Strategy

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

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

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

		Currency Denomination
		June 30,				December 31,
Foreign Currency		2011				2010
British Pound Sterling		£	6			£	8
Danish Krone		DKK	48			DKK	115
Euro		€	72			€	97
Norwegian Krone		NOK	1,130			NOK	1,442
U.S. Dollar		$	635			$	328
Russian Ruble		RUB	711			RUB	780
Brazilian Real		BRL	38			BRL	—
Japanese Yen		¥	244			¥	—
Singapore Dollar		SGD	37			SGD	—

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

		Asset Derivatives												Liability Derivatives
						Fair Value												Fair Value
		Balance Sheet				June 30,				December 31,				Balance Sheet				June 30,				December 31,
		Location				2011				2010				Location				2011				2010
Derivatives designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets				$	58			$	28			Accrued liabilities				$	12			$	12
Foreign exchange contracts		Other Assets					24				12			Other Liabilities					1				1
Total derivatives designated as hedging instruments under ASC Topic 815						$	82			$	40							$	13			$	13
Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets				$	13			$	7			Accrued liabilities				$	7			$	10
Total derivatives not designated as hedging instruments under ASC Topic 815						$	13			$	7							$	7			$	10
Total derivatives						$	95			$	47							$	20			$	23

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

																						Location of Gain (Loss)
																						Recognized in Income on				Amount of Gain (Loss)
										Location of Gain (Loss)												Derivative (Ineffective				Recognized in Income on
										Reclassified from				Amount of Gain (Loss)								Portion and Amount				Derivative (Ineffective
Derivatives in ASC Topic 815		Amount of Gain (Loss)								Accumulated OCI into				Reclassified from								Excluded from				Portion and Amount
Cash Flow Hedging		Recognized in OCI on								Income				Accumulated OCI into								Effectiveness				Excluded from
Relationships		Derivative (Effective Portion) (a)								(Effective Portion)				Income (Effective Portion)								Testing)				Effectiveness Testing) (b)
		Six Months Ended												Six Months Ended												Six Months Ended
		June 30,												June 30,												June 30,
		2011				2010								2011				2010								2011				2010
										Revenue					21				6
Foreign exchange contracts			87				(116	)		Cost of revenue					9				(16	)		Other income (expense), net					(2	)			8
Total			87				(116	)							30				(10	)							(2	)			8

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,

2011

2010

2011

2010

Foreign exchange contracts

Revenue

—

(2

)

Firm commitments

Revenue

—

2

Total

—

(2

)

—

2

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,

2011

2010

Foreign exchange contracts

Other income (expense), net

(15

)

22

Total

(15

)

22

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,
		2011				2010				2011				2010
Numerator:
Net income attributable to Company		$	481			$	401			$	888			$	823
Denominator:
Basic—weighted average common shares outstanding			422				417				421				417
Dilutive effect of employee stock options and other unvested stock awards			3				2				3				2
Diluted outstanding shares			425				419				424				419
Net income attributable to Company per share:
Basic		$	1.14			$	0.96			$	2.11			$	1.97
Diluted		$	1.13			$	0.96			$	2.10			$	1.96
Cash dividends per share		$	0.11			$	0.10			$	0.22			$	0.20

In addition, the Company had stock options outstanding that were anti-dilutive totaling 2 million and 3 million shares for the three and six months ended June 30, 2011, respectively, and 6 million and 5 million shares for the three and six months ended June 30, 2010, respectively.

12. Cash Dividends

On May 11, 2011 the Company’s Board of Directors approved a cash dividend of $0.11 per share. The cash dividend was paid on June 24, 2011 to each stockholder of record on June 10, 2011. Cash dividends aggregated $47 million and $93 million for the three and six months ended June 30, 2011, respectively, and $42 million and $84 million for the three and six months ended June 30, 2010, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.

13. Subsequent Event

Subsequent to June 30, 2011, the Company entered into an agreement to acquire Ameron International Corporation (“Ameron”) for approximately $772 million. Under the agreement, Ameron’s stockholders would receive $85.00 per share in cash in return for each of the approximately 9.1 million shares outstanding. The boards of directors of the Company and Ameron have unanimously approved the transaction, which is subject to customary closing conditions, including the approval of holders of at least a majority of Ameron’s outstanding shares and approval from various regulatory agencies.

14. Recently Issued Accounting Standards

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

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

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

Introduction

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

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

Rig Technology

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

Petroleum Services & Supplies

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

Distribution Services

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

Critical Accounting Estimates

In our annual report on Form 10-K for the year ended December 31, 2010, we identified our most critical accounting policies. In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are most critical in nature which are related to revenue recognition under long-term construction contracts; allowance for doubtful accounts; inventory reserves; impairments of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets; service and product warranties and income taxes. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. The combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates and those differences may be material.

EXECUTIVE SUMMARY

National Oilwell Varco generated $481 million in net income attributable to Company, or $1.13 per fully diluted share, on $3.51 billion in revenue in its second quarter ended June 30, 2011. Compared to the first quarter of 2011, revenue increased 12 percent and net income attributable to Company increased 18 percent. Compared to the second quarter of 2010, revenue increased 19 percent and net income attributable to Company increased 20 percent.

The second quarter of 2011 included pre-tax transaction charges of $4 million, the first quarter of 2011 included pre-tax transaction charges and Libya asset write-downs of $19 million, and the second quarter of 2010 included pre-tax transaction charges of $4 million. Excluding these charges from all periods, second quarter 2011 earnings were $1.14 per fully diluted share, compared to $1.00 per fully diluted share last quarter and $0.97 per fully diluted share a year ago. Operating profit excluding these charges was $712 million or 20.3 percent of sales in the second quarter of 2011, compared to $628 million or 20.0 percent of sales last quarter, and $594 million or 20.2 percent of sales a year ago.

Revenues increased both sequentially and year-over-year for all three of the Company’s segments. The Company’s largest segment, Rig Technology, generated higher operating profit sequentially and year-over-year, on sales growth of 18 percent and 13 percent, respectively. Both Petroleum Services & Supplies and Distribution Services segments generated higher year-over-year operating profit and higher operating margins in the second quarter of 2011, owing to higher levels of drilling activity worldwide as compared to the second quarter of 2010. Compared to the first quarter of 2011, operating profit increased slightly for the Petroleum Services & Supplies segment, and decreased slightly for the Distribution Services segment. Operating margins for both declined slightly sequentially, due in part to the seasonal downturn in drilling activity in Canada due to breakup, when authorities enact road transport bans on heavy rig moves to prevent road damage as the ground thaws, and due to flooding in the upper midwest of the U.S.

Oil & Gas Equipment and Services Market

Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks responded vigorously through 2009, but economic growth in many developed economies continues to be weak. As a result asset and commodity prices, including oil and gas prices, declined in 2009. After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to average $43 per barrel (West Texas Intermediate Crude Prices) during the first quarter of 2009, but recovered to $76 per barrel range by the end of 2009 and increased to $102 per barrel by the second quarter of 2011, partly due to unrest in the Middle East. North American gas prices declined to $3.17 per mmbtu in the third quarter of 2009 but recovered to average $4.36 per mmbtu in the second quarter of 2011. The steadily rising oil and gas prices seen between 2003 and 2008 led to high levels of exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit availability. However, higher commodity prices led to a recovery in drilling activity through the past six quarters.

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 1,908 at July 29, 2011, and averaged 1,829 rigs during the second quarter of 2011. Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity in 2009, but drilling recovered across North America as gas prices firmed above $4 per mmbtu and, more recently, as operators began to drill unconventional shale plays targeting oil, rather than gas. For the first time in over 16 years oil drilling has risen to over 50 percent of the total domestic drilling effort.

Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings, but the international rig count exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 947 in August 2009, but recently climbing back to 1,157 in the second quarter of 2011.

During 2009 the Company saw its Petroleum Services & Supplies and its Distribution Services margins affected most acutely by a drilling downturn, through both volume and price declines; nevertheless, both of these segments saw pricing stabilize and revenues recover since third quarter 2009 lows. The Company’s Rig Technology segment increased revenues and margins through 2009 owing to its high level of contracted backlog which it executed on very well since the economic downturn. In the first half of 2010 the segment posted operating margins of more than 30 percent, but saw its margins decline modestly since then, due to a declining mix of higher margin sales made in the 2007-2008 timeframe, and a rising mix of more recent sales made at lower pricing.

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

The industry responded by launching many new rig construction projects since 2005, to 1.) retool the existing fleet of jackup rigs (according to Offshore Data Services, 70 percent of the existing 476 jackup rigs are more than 25 years old); 2.) 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.

As a result of these trends, the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at March 31, 2005, to $11.8 billion at September 30, 2008. The credit crisis and slowing drilling activity led to lower orders in 2009, causing the backlog to decline to $4.9 billion by June 30, 2010. Orders have risen sharply since then, lifting the segment’s backlog to $7.7 billion as of June 30, 2011. Orders totaled $3.0 billion for the second quarter of 2011, double the revenue out of backlog, and represents a record level for the Rig Technology segment’s capital equipment sales. Approximately $2.8 billion of backlog orders are scheduled to flow out as revenue during the second half of 2011; $4.3 billion in 2012, and the balance thereafter. The land rig backlog comprised 16 percent and equipment destined for offshore operations comprised 84 percent of the total backlog as of June 30, 2011. Equipment destined for international markets totaled 84 percent of the backlog.

Segment Performance

The Rig Technology segment revenues of $1,894 million in the second quarter of 2011 increased 18 percent sequentially and increased 13 percent compared to the second quarter of 2010. Segment operating profit was $514 million and operating margins were 27.1 percent during the second quarter. Compared to the first quarter of 2011, incremental operating leverage or flow-through (the change in operating profit divided by the change in revenue) was 33 percent, and compared to the second quarter of 2010 incremental operating leverage was four percent. The reason for the low year-over-year incremental leverage was a mix shift away from higher margin offshore projects won a few years ago, toward lower-priced offshore work, and more land business, which typically carries lower margins. Many offshore projects were contracted at high prices in 2007 and 2008 and subsequently manufactured in much lower cost environments in 2009 and 2010. Year-over-year operating margin declined 310 basis points due to this mix effect. Sequentially, margins improved mostly due to lower costs experienced on the fabrication of drilling risers the segment is building for the many offshore rigs in its backlog. The transfer late last year of drilling riser fabrication operations to South Korea improved proximity to the shipyards and reduced manufacturing expense, leading to favorable cost estimate adjustments for new rig construction projects. Sequentially, revenue out of backlog improved 24 percent and aftermarket spares and services revenues improved four percent. Compared to the

second quarter of 2010 revenue out of backlog grew 11 percent and aftermarket spares and services revenues improved 13 percent. Demand for stimulation equipment, complete land rig packages for North American markets, six jackup rigs and eight drillship packages contributed to the record order level during the second quarter. The second quarter did not include orders for new deepwater rigs for Brazil, and the Company continues to bid seven deepwater drillships to be built for Petrobras. 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.

The Petroleum Services & Supplies (“PSS”) segment generated total sales of $1,359 million in the second quarter of 2011, up seven percent from the first quarter of 2011 and up 32 percent from the second quarter of 2010. The increase in PSS revenue was mainly due to strong U.S. activity where the rig count averaged 1,829 rigs during the second quarter of 2011 (its highest level since the fourth quarter of 2008) and helped to offset the drop in Canada rig count which declined from a first quarter 2011 average of 587 rigs to an average of 188 rigs in the second quarter of 2011. Operating profit was $249 million or 18.3 percent of sales for the second quarter, compared to 18.3 percent in the first quarter of 2011 and 13.4 percent in the second quarter of 2010. Operating leverage or flow-through was 19 percent from the first quarter of 2011, and 34 percent from the second quarter of 2010 to the second quarter of 2011. Lower sequential flow-throughs and margins were due to the impact of the seasonal breakup in Canada and flooding in the Bakken region, which reduced revenues at high margins, mostly affecting NOV Downhole Tools and Wellsite Services. These declines were offset by higher revenues from recent acquisitions, and modestly lower margins on increased sales in Mission, drillpipe, and conductor pipe connections, owing to mix. Additionally, the segment posted higher startup costs for a number of new locations. Operations in North Africa and the Middle East continue to face low levels of activity due to continuing unrest in that region. Tuboscope posted sharply higher coating and pipe inspection revenues at strong incremental margins.

The Distribution Services segment generated $423 million in revenue during the second quarter of 2011, up three percent from the first quarter of 2011 and increasing 16 percent from the second quarter of 2010. Operating profit was $25 million, and operating margin was 5.9 percent of sales, down slightly from the first quarter of 2011, but double year ago levels. Operating leverage or flow-through was 21 percent year-over-year. The segment posted sharp declines in Canada due to seasonal breakup, but was nevertheless able to maintain good profitability. U.S. and international sales both increased sequentially, with international operations helped by the segment’s acquisition of a business in the U.K. The U.S. and international accounted for 51 percent and 36 percent of the segment’s mix, respectively. Domestic margins declined slightly due to new facility startup costs in South Texas, Pennsylvania and the mid-continent. Industrial products margins declined in Argentina and Europe, but the group is experiencing rising demand for artificial lift products in international markets.

Outlook

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

Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution Services segment remains closely tied to the rig count, particularly in North America. If the rig count continues at current or higher levels, we expect these segments to benefit from higher demand for the services, consumables and capital items they supply. Many products are beginning to see higher steel, alloy, resin and fiberglass costs impact their business, and are attempting to raise prices to offset rising costs. Continuing tight iron ore supplies to the steel mills could adversely affect margins as the year unfolds.

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

As of early August 2011, the recovery of the world economy continues to move forward with a great deal of uncertainty as the world watches the sovereign debt crisis in several European countries unfold, the U.S. government’s continued struggles with its own sovereign debt levels and a potential credit downgrade, and general global economic worries and market turbulence. If such global economic uncertainties develop adversely, world oil and gas prices could be impacted which in turn could negatively impact the worldwide rig count and the Company’s future financial results.

Operating Environment Overview

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

														%				%
														2Q11 v				2Q11 v
		2Q11*				1Q11*				2Q10*				1Q11				2Q10
Active Drilling Rigs:
U.S.			1,829				1,717				1,508				6.5	%			21.3	%
Canada			188				587				166				(68.0	%)			13.3	%
International			1,147				1,166				1,088				(1.6	%)			5.4	%
Worldwide			3,164				3,470				2,762				(8.8	%)			14.6	%
West Texas Intermediate Crude Prices (per barrel)		$	102.23			$	93.54			$	77.79				9.3	%			31.4	%
Natural Gas Prices ($/mmbtu)		$	4.36			$	4.18			$	4.32				4.3	%			0.9	%

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, 2011 on a quarterly basis:

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

The quarterly average rig count decreased 9% (from 3,470 to 3,164) worldwide while the U.S. average increased 7% (from 1,717 to 1,829), in the second quarter of 2011 compared to the first quarter of 2011. The average per barrel price of West Texas Intermediate Crude increased 9% (from $93.54 per barrel to $102.23 per barrel) and natural gas prices increased 4% (from $4.18 per mmbtu to $4.36 per mmbtu) in the second quarter of 2011 compared to the first quarter of 2011.

U.S. rig activity at July 29, 2011 was 1,908 rigs compared to the second quarter average of 1,829 rigs, increasing 5%. The price for West Texas Intermediate Crude was at $99.87 per barrel as of July 22, 2011, decreasing 2% from the second quarter average. The price for natural gas was at $4.26 per mmbtu as of July 29, 2011, increasing 1% from the second quarter average.

Results of Operations

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Revenue:
Rig Technology		$	1,894			$	1,672			$	3,502			$	3,558
Petroleum Services & Supplies			1,359				1,033				2,624				1,956
Distribution Services			423				365				833				699
Elimination			(163	)			(129	)			(300	)			(240	)
Total Revenue		$	3,513			$	2,941			$	6,659			$	5,973
Operating Profit:
Rig Technology		$	514			$	505			$	933			$	1,086
Petroleum Services & Supplies			249				138				480				251
Distribution Services			25				13				52				24
Unallocated expenses and eliminations			(80	)			(66	)			(148	)			(134	)
Total Operating Profit		$	708			$	590			$	1,317			$	1,227
Operating Profit %:
Rig Technology			27.1	%			30.2	%			26.6	%			30.5	%
Petroleum Services & Supplies			18.3	%			13.4	%			18.3	%			12.8	%
Distribution Services			5.9	%			3.6	%			6.2	%			3.4	%
Total Operating Profit %			20.2	%			20.1	%			19.8	%			20.5	%

Rig Technology

Three Months Ended June 30, 2011 and 2010. Rig Technology revenue in the second quarter of 2011 was $1,894 million, an increase of $222 million (13.3%) compared to the same period in 2010. This increase is primarily due to the increase of revenue out of backlog of $139 million as well as an increase in non backlog revenue of $83 million. Backlog was $7.7 billion at June 30, 2011, a 59% increase from June 30, 2010.

Operating profit from Rig Technology was $514 million for the second quarter ended June 30, 2011, an increase of $9 million (1.8%) over the same period of 2010. Operating profit percentage decreased to 27.1%, from 30.2% for the same prior year period primarily due to a decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008.

Six Months Ended June 30, 2011 and 2010. Rig Technology revenue for the first six months of 2011 was $3,502 million, a decrease of $56 million (1.6%) compared to the same period in 2010. This decrease is primarily due to the decrease of revenue out of backlog of $243 million offset by the increase in non backlog revenue of $187 million.

Operating profit from Rig Technology was $933 million for the first six months of 2011, a decrease of $153 million (14.1%) over the same period of 2010. Operating profit percentage decreased to 26.6%, from 30.5% for the same prior year period primarily due to a decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008.

Petroleum Services & Supplies

Three Months Ended June 30, 2011 and 2010. Revenue from Petroleum Services & Supplies was $1,359 million for the second quarter of 2011 compared to $1,033 million for the second quarter of 2010, an increase of $326 million (31.6%). The increase was primarily attributable to shale plays leading to a strong U.S. market with a 21.3% increase in U.S. rig activity compared to the second quarter of 2010.

Operating profit from Petroleum Services & Supplies was $249 million for the second quarter ended June 30, 2011, an increase of $111 million (80.4%) over the same period of 2010. Operating profit percentage increased to 18.3%, up from 13.4% for the same prior year period primarily due to increased volume with a strong domestic demand fueled by an increase in rig count.

Six Months Ended June 30, 2011 and 2010. Revenue from Petroleum Services & Supplies was $2,624 million for the first half of 2011 compared to $1,956 million for the first half of 2010, an increase of $668 million (34.2%). The increase was primarily attributable to shale plays leading to a strong U.S. market with increased U.S. rig activity compared to the first half of 2010.

Operating profit from Petroleum Services & Supplies was $480 million for the six months ended June 30, 2011, an increase of $229 million (91.2%) over the same period of 2010. Operating profit percentage increased to 18.3%, up from 12.8% for the same prior year period primarily due to increased volume with a strong domestic demand fueled by an increase in rig count. The increase was offset by the write-down, in the first quarter, of Libyan assets of $15 million, mostly related to accounts receivable affected by sanctions enacted during the quarter along with the write off of certain inventory and fixed assets in the country. The Company’s Rig Technology and Distribution Services segments incurred $2 million of such asset write-downs during the first quarter for a total of $17 million in Libyan asset write-downs incurred by the Company.

Distribution Services

Three Months Ended June 30, 2011 and 2010. Revenue from Distribution Services was $423 million for the second quarter of 2011 compared to $365 million for the second quarter of 2010, an increase of $58 million (15.9%). This increase was primarily attributable to increased U.S. rig count activity.

Operating profit from Distribution Services was $25 million for the second quarter ended June 30, 2011, an increase of $12 million (92.3%) over the same period of 2010. Operating profit percentage increased to 5.9%, up from 3.6% for the same prior year period primarily due to better pricing related to strong demand fueled by an increase in U.S. rig count activity.

Six Months Ended June 30, 2011 and 2010. Revenue from Distribution Services was $833 million for the first six months of 2011 compared to $699 million for the first six months of 2010, an increase of $134 million (19.2%). This increase was primarily attributable to increased U.S. rig count activity.

Operating profit from Distribution Services was $52 million for the first six months of 2011 compared to $24 million for the same period in 2010, an increase of $28 million (116.7%). Operating profit percentage increased to 6.2%, up from 3.4% for the same prior year period primarily due to greater cost efficiencies and better pricing related to strong demand fueled by an increase in U.S. rig count activity.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $80 million and $148 million for the three and six months ended June 30, 2011, respectively, compared to $66 million and $134, respectively, for the same periods in 2010. This increase is primarily due to higher tax consulting expenses, legal costs associated with acquisitions and intersegment eliminations.

Interest and financial costs

Interest and financial costs were $9 million and $23 million for the three and six months ended June 30, 2011, respectively, compared to $13 million and $26 million, respectively, for the same periods in 2010. The decrease in interest and financial costs was due to an overall decrease in debt levels for the three and six months ended June 30, 2011 compared to the same periods in 2010.

Other income (expense), net

Other income (expense), net were expenses of $7 million and $26 million for the three and six months ended June 30, 2011, respectively, compared to $3 million and $19 million, respectively for the same periods in 2010. The increase for the three and six months ended June 30, 2011, was mainly due to higher foreign exchange losses during 2011 as a result of exchange rate movements, primarily related to the weakening of the U.S. dollar.

Provision for income taxes

The effective tax rate for the three and six months ended June 30, 2011 was 32.0% and 31.9%, respectively, compared to 31.8% and 31.9% for the same period in 2010. The effective tax rate was positively impacted in the period by an increase in income earned in foreign jurisdictions with tax rates lower than the U.S. federal statutory rate, which are indefinitely reinvested. This was offset by an increase in non-deductible expenses incurred in foreign jurisdictions.

Non-GAAP Financial Measures and Reconciliations

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

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

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Reconciliation of operating profit:
GAAP operating profit		$	708			$	590			$	1,317			$	1,227
Other costs:
Transaction costs			4				4				6				4
Libya asset write-down			—				—				17				—
Devaluation costs			—				—				—				11
Operating profit excluding other costs		$	712			$	594			$	1,340			$	1,242

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Reconciliation of operating profit %:
GAAP operating profit %			20.2	%			20.1	%			19.8	%			20.5	%
Other costs %			0.1	%			0.1	%			0.3	%			0.3	%
Operating profit % excluding other costs			20.3	%			20.2	%			20.1	%			20.8	%

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Reconciliation of diluted earnings per share:
GAAP earnings per share		$	1.13			$	0.96			$	2.10			$	1.96
Other costs			0.01				0.01				0.05				0.10
Earnings per share excluding other costs		$	1.14			$	0.97			$	2.15			$	2.06

Liquidity and Capital Resources

Overview

At June 30, 2011, the Company had cash and cash equivalents of $3,440 million, and total debt of $513 million. At December 31, 2010, cash and cash equivalents were $3,333 million and total debt was $887 million. A significant portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. Rather than repatriating this cash, the Company may choose to borrow against its credit facility. The Company’s outstanding debt at June 30, 2011 consisted of $200 million of 5.65% Senior Notes due 2012, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $12 million.

There were no borrowings against the Company’s unsecured revolving credit facility, and there were $559 million in outstanding letters of credit issued under the facility, resulting in $1,441 million of funds available under the Company’s unsecured revolving credit facility at June 30, 2011.

The Company had $1,716 million of additional outstanding letters of credit at June 30, 2011, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. The Company was in compliance with all covenants at June 30, 2011.

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

		Six Months Ended
		June 30,
		2011				2010
Net cash provided by operating activities		$	887			$	282
Net cash used in investing activities			(424	)			(108	)
Net cash used in financing activities			(378	)			(82	)

Operating Activities

For the first six months of 2011, cash provided by operating activities was $887 million, an increase of $605 million compared to cash provided by operating activities of $282 million in the same period of 2010. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $884 million plus non-cash charges of $273 million and $45 million of the dividend received from the Company’s unconsolidated affiliate less $23 million in equity income from the Company’s unconsolidated affiliate.

Net changes in operating assets and liabilities, net of acquisitions, used $316 million for the first six months of 2011 compared to $710 million used in the same period in 2010. Due to an increase in market activity during the first six months of 2011 compared to the same period in 2010, revenue and backlog (milestone invoicing) increased which is reflected in increased accounts receivable coupled with a buildup in inventory, partially offset by a decrease in costs in excess of billings and an increase in billings in excess of costs. Incentive compensation and tax payments contributed to the reduction in other assets/liabilities, net for the first six months of 2011 compared to the same period in 2010.

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

Investing Activities

For the first six months of 2011, cash used in investing activities was $424 million compared to cash used in investing activities of $108 million for the same period of 2010. The primary reason for the increase related to the increase in cash paid for acquisitions to approximately $259 million during the first six months of 2011 compared to $62 million during the same period of 2010. In addition, capital expenditures increased to approximately $192 million as capital was spent on several U.S. and international expansion projects during the first six months of 2011 compared to $78 million used in the same period of 2010.

Financing Activities

For the first six months of 2011, cash used in financing activities was $378 million compared to cash used in financing activities of $82 million for the same period of 2010. The $296 million increase in cash used in financing activities for the first six months of 2011 primarily related to the repayment of $150 million in Senior Notes that were due late in the first quarter, $200 million in Senior Notes that were due in the second quarter as well as $20 million in other current borrowings. The Company increased its dividend slightly to $93 million for the first six months of 2011 compared to $84 million for the same period of 2010. The increase in cash used was offset by $71 million in proceeds from stock options exercised during the first six months of 2011 compared to $8 million in proceeds from stock options exercised during the same period in 2010. For the first six months of 2011, the Company used its cash on hand to fund its acquisitions.

The effect of the change in exchange rates on cash flows was a positive $22 million and a negative $26 million for the six months ended June 30, 2011 and 2010, respectively.

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

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

Recently Issued Accounting Standards

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

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

Forward-Looking Statements

Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward-looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products, difficulties encountered in integrating mergers and acquisitions, and worldwide economic activity. You should also consider carefully the statements under “Risk Factors,” as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. We recorded a foreign exchange loss in our income statement of approximately $16 million in the first six months of 2011, compared to a $14 million foreign exchange loss in the same period of the prior year. The gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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

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

		As of June 30, 2011																December 31,
Functional Currency		2011				2012				2013				Total				2010
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)			331				—				—				331				267
Average CAD to USD contract rate			0.9773				—				—				0.9773				1.0072
Fair Value at June 30, 2011 in U.S. dollars			—				—				—				—				(1	)
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)			122				50				—				172				55
Average CAD to USD contract rate			0.9886				0.9805				—				0.9841				1.0237
Fair Value at June 30, 2011 in U.S. dollars			1				—				—				1				1
DKK Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)			99				—				—				99				113
Average DKK to USD contract rate			5.1835				—				—				5.1835				5.6618
Fair Value at June 30, 2011 in U.S. dollars			—				—				—				—				—
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)			3				—				—				3				1
Average USD to EUR contract rate			1.4114				—				—				1.4114				1.3884
Fair Value at June 30, 2011 in U.S. dollars			—				—				—				—				—
Sell USD/Buy EUR:
Notional amount to buy (in euros)			124				37				—				161				74
Average USD to EUR contract rate			1.3844				1.3806				—				1.3835				1.3172
Fair Value at June 30, 2011 in U.S. dollars			6				2				—				8				1