NOV (NOV) 10-Q 2014 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2014

OR

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

Commission File Number 1-12317

NATIONAL OILWELL VARCO, INC.

(Exact name of registrant as specified in its charter)

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

7909 Parkwood Circle Drive

Houston, Texas

77036-6565

(Address of principal executive offices)

(713) 346-7500

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	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  ¨    No  x

As of May 1, 2014 the registrant had 429,047,822 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)

	March 31,			December 31,
	2014			2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	3,688		$	3,436
Receivables, net		5,310			4,896
Inventories, net		5,659			5,603
Costs in excess of billings		1,520			1,539
Deferred income taxes		325			373
Prepaid and other current assets		709			576
Total current assets		17,211			16,423
Property, plant and equipment, net		3,437			3,408
Deferred income taxes		479			372
Goodwill		8,875			9,049
Intangibles, net		4,953			5,055
Investment in unconsolidated affiliates		402			390
Other assets		123			115
Total assets	$	35,480		$	34,812
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,391		$	1,275
Accrued liabilities		2,717			2,763
Billings in excess of costs		2,079			1,771
Current portion of long-term debt and short-term borrowings		—			1
Accrued income taxes		484			556
Deferred income taxes		427			312
Total current liabilities		7,098			6,678
Long-term debt		3,149			3,149
Deferred income taxes		2,088			2,292
Other liabilities		353			363
Total liabilities		12,688			12,482
Commitments and contingencies
Stockholders’ equity:
Common stock—par value $.01; 1 billion shares authorized; 428,852,227 and 428,433,703 shares issued and outstanding at March 31, 2014 and December 31, 2013		4			4
Additional paid-in capital		8,933			8,907
Accumulated other comprehensive loss		(41	)		(4	)
Retained earnings		13,801			13,323
Total Company stockholders’ equity		22,697			22,230
Noncontrolling interests		95			100
Total stockholders’ equity		22,792			22,330
Total liabilities and stockholders’ equity	$	35,480		$	34,812

See notes to unaudited consolidated financial statements.

2

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(In millions, except per share data)

	Three Months Ended March 31,
	2014			2013
Revenue	$	5,777		$	5,307
Cost of revenue		4,381			4,043
Gross profit		1,396			1,264
Selling, general and administrative		535			513
Operating profit		861			751
Interest and financial costs		(26	)		(28	)
Interest income		4			3
Equity income in unconsolidated affiliates		10			19
Other income (expense), net		—			(21	)
Income before income taxes		849			724
Provision for income taxes		260			224
Net income		589			500
Net loss attributable to noncontrolling interests		—			(2	)
Net income attributable to Company	$	589		$	502
Net income attributable to Company per share:
Basic	$	1.38		$	1.18
Diluted	$	1.37		$	1.17
Cash dividends per share	$	0.26		$	0.13
Weighted average shares outstanding:
Basic		428			426
Diluted		429			428

See notes to unaudited consolidated financial statements.

3

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(In millions)

	Three Months Ended March 31,
	2014			2013
Net income	$	589		$	500
Currency translation adjustments		(51	)		(117	)
Changes in derivative financial instruments, net of tax		14			(48	)
Comprehensive income		552			335
Comprehensive loss attributable to noncontrolling interest		—			(2	)
Comprehensive income attributable to Company	$	552		$	337

See notes to unaudited consolidated financial statements.

4

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In millions)

	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	589		$	500
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		195			174
Deferred income taxes		38			(33	)
Equity income in unconsolidated affiliates		(10	)		(19	)
Other, net		61			18
Change in operating assets and liabilities, net of acquisitions:
Receivables		(418	)		208
Inventories		(90	)		(13	)
Costs in excess of billings		20			(108	)
Prepaid and other current assets		(133	)		130
Accounts payable		116			(8	)
Billings in excess of costs		307			(97	)
Income taxes payable		(72	)		51
Other assets/liabilities, net		(115	)		(297	)
Net cash provided by operating activities		488			506
Cash flows from investing activities:
Purchases of property, plant and equipment		(131	)		(168	)
Business acquisitions, net of cash acquired		(2	)		(2,375	)
Other		7			8
Net cash used in investing activities		(126	)		(2,535	)
Cash flows from financing activities:
Borrowings against lines of credit and other debt		—			1,386
Repayments on debt		(1	)		(186	)
Cash dividends paid		(111	)		(56	)
Proceeds from stock options exercised		5			5
Other		2			13
Net cash provided by (used in) financing activities		(105	)		1,162
Effect of exchange rates on cash		(5	)		(11	)
Increase (decrease) in cash and cash equivalents		252			(878	)
Cash and cash equivalents, beginning of period		3,436			3,319
Cash and cash equivalents, end of period	$	3,688		$	2,441
Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	7		$	7
Income taxes	$	314		$	171

See notes to unaudited consolidated financial statements.

5

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. (“NOV” or 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 2013 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 months ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year.

Fair Value of Financial Instruments

The carrying amounts of 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. See Note 7 for the fair value of long-term debt and Note 10 for the fair value of derivative financial instruments.

2. Inventories, net

Inventories consist of (in millions):

	March 31,		December 31,
	2014		2013
Raw materials and supplies	$	1,414	$	1,175
Work in process		655		798
Finished goods and purchased products		3,590		3,630
Total	$	5,659	$	5,603

6

3. Accrued Liabilities

Accrued liabilities consist of (in millions):

	March 31,		December 31,
	2014		2013
Customer prepayments and billings	$	755	$	673
Accrued vendor costs		562		531
Compensation		348		516
Warranty		248		228
Insurance		137		131
Taxes (non income)		128		188
Accrued Commissions		92		97
Interest		30		11
Fair value of derivatives		21		31
Other		396		357
Total	$	2,717	$	2,763

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, 2013	$	228
Net provisions for warranties issued during the year		29
Amounts incurred		(11	)
Currency translation adjustments and other		2
Balance at March 31, 2014	$	248

7

4. Costs and Estimated Earnings on Uncompleted Contracts

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

	March 31,			December 31,
	2014			2013
Costs incurred on uncompleted contracts	$	8,521		$	7,608
Estimated earnings		3,909			3,553
		12,430			11,161
Less: Billings to date		12,989			11,393
	$	(559	)	$	(232	)
Costs and estimated earnings in excess of billings on uncompleted contracts	$	1,520		$	1,539
Billings in excess of costs and estimated earnings on uncompleted contracts		(2,079	)		(1,771	)
	$	(559	)	$	(232	)

5. Accumulated Other Comprehensive Income (Loss)

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

				Derivative			Defined
	Currency			Financial			Benefit
	Translation			Instruments,			Plans,
	Adjustments			Net of Tax			Net of Tax			Total
Balance at December 31, 2013	$	17		$	5		$	(26	)	$	(4	)
Accumulated other comprehensive income (loss) before reclassifications		(51	)		21			—			(30	)
Amounts reclassified from accumulated other comprehensive income (loss)		—			(7	)		—			(7	)
Balance at March 31, 2014	$	(34	)	$	19		$	(26	)	$	(41	)

The components of amounts reclassified from accumulated other comprehensive income (loss) are as follows (in millions):

	Three Months Ended March 31,
	2014										2013
	Currency Translation Adjustments		Derivative Financial Instruments			Defined Benefit Plans		Total			Currency Translation Adjustments		Derivative Financial Instruments			Defined Benefit Plans		Total
Revenue	$	—	$	(13	)	$	—	$	(13	)	$	—	$	(2	)	$	—	$	(2	)
Cost of revenue		—		3			—		3			—		(3	)		—		(3	)
Tax effect		—		3			—		3			—		1			—		1
	$	—	$	(7	)	$	—	$	(7	)	$	—	$	(4	)	$	—	$	(4	)

The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, currency translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in Other Comprehensive Income or Loss in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three months ended March 31, 2014 and March 31, 2013, a majority of these local currencies weakened against the U.S. dollar resulting in net Other Comprehensive Loss of $51 million and $117 million, respectively, upon the translation from local currencies to the U.S. dollar.

8

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in Other Comprehensive Income or Loss, net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in Other Comprehensive Income or Loss from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of Other Comprehensive Income or Loss related to cumulative changes in the fair value of derivatives that have settled in the current or prior periods. The accumulated effect was Other Comprehensive Income of $14 million (net of tax of $6 million) for the three months ended March 31, 2014 and $48 million Other Comprehensive Loss (net of tax of $19 million) for the three months ended March 31, 2013.

6. Business Segments

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

	Three Months Ended March 31,
	2014			2013
Revenue:
Rig Technology	$	3,009		$	2,628
Petroleum Services & Supplies		1,789			1,701
Distribution & Transmission		1,281			1,227
Eliminations		(302	)		(249	)
Total Revenue	$	5,777		$	5,307
Operating Profit:
Rig Technology	$	634		$	550
Petroleum Services & Supplies		321			255
Distribution & Transmission		55			63
Unallocated expenses and eliminations		(149	)		(117	)
Total Operating Profit	$	861		$	751
Operating Profit %:
Rig Technology		21.1	%		20.9	%
Petroleum Services & Supplies		17.9	%		15.0	%
Distribution & Transmission		4.3	%		5.1	%
Total Operating Profit %		14.9	%		14.2	%

Included in operating profit are other costs related to acquisitions, such as transaction costs, the amortization of backlog and inventory that was stepped up to fair value during purchase accounting, the costs of the proposed spin-off of the Company’s distribution business and certain legal costs. Other costs by segment are as follows (in millions):

	Three Months Ended March 31,
	2014		2013
Other costs:
Rig Technology	$	1	$	7
Petroleum Services & Supplies		5		56
Distribution & Transmission		13		2
Total other costs	$	19	$	65

9

7. Debt

Debt consists of (in millions):

	March 31,		December 31,
	2014		2013
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015	$	151	$	151
Senior Notes, interest at 1.35% payable semiannually, principal due on December 1, 2017		500		500
Senior Notes, interest at 2.6% payable semiannually, principal due on December 1, 2022		1,396		1,396
Senior Notes, interest at 3.95% payable semiannually, principal due on December 1, 2042		1,096		1,096
Other		6		7
Total debt		3,149		3,150
Less current portion		—		1
Long-term debt	$	3,149	$	3,149

The Company has a $3.5 billion, five-year unsecured revolving credit facility which expires September 28, 2018. The Company also has a commercial paper program that is supported by its revolving credit facility. At March 31, 2014, the Company had no commercial paper borrowings and no borrowings against its revolving credit facility. Funds available under the Company’s revolving credit facility were $2,509 million due to $991 million in outstanding letters of credit issued under the facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% 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 March 31, 2014.

The Company also had $3,223 million of additional outstanding letters of credit at March 31, 2014, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds.

The fair value of the Company’s debt is estimated using Level 2 inputs in the fair value hierarchy and is based on quoted prices for those or similar instruments. At March 31, 2014 and December 31, 2013, the fair value of the Company’s unsecured Senior Notes approximated $2,999 million and $2,896 million, respectively. At both March 31, 2014 and December 31, 2013, the carrying value of the Company’s unsecured Senior Notes approximated $3,143 million.

10

8. Tax

The effective tax rate for the three months ended March 31, 2014 was 30.6 %, compared to 30.9 % for the same period in 2013. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the periods by the effect of lower tax rates on income earned in foreign jurisdictions which are permanently reinvested, foreign exchange gains and losses for tax reporting in Norway, and the deduction in the U.S. for manufacturing activities.

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 March 31,
	2014			2013
Federal income tax at U.S. federal statutory rate	$	297		$	253
Foreign income tax rate differential		(47	)		(57	)
State income tax, net of federal benefit		6			8
Nondeductible expenses		11			8
Tax benefit of manufacturing deduction		(8	)		(8	)
Foreign dividends, net of foreign tax credits		9			4
Tax impact of foreign exchange		(8	)		18
Other		—			(2	)
Provision for income taxes	$	260		$	224

The balance of unrecognized tax benefits at March 31, 2014 was $127 million, $54 million of which if ultimately realized, would be recorded as an income tax benefit. The Company recognized no material changes in the balance of unrecognized tax benefits for the three months ended March 31, 2014.

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

The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The Company has significant operations in the United States, Canada, the United Kingdom, the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdiction vary by legal entity, but are generally open in the U.S. for tax years after 2007 and outside the U.S. for tax years after 2005.

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

11

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 39.5 million. At March 31, 2014, 10,341,009 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 $27 million and $17 million for the three months ended March 31, 2014 and 2013, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $8 million and $5 million for the three months ended March 31, 2014 and 2013, respectively.

During the three months ended March 31, 2014, the Company granted 3,113,607 stock options with a fair value of $25.60 per share and 426,272 shares of restricted stock and restricted stock units with a fair value of $74.83 per share. In addition, the Company granted performance share awards to senior management employees with potential payouts varying from zero to 436,390 shares. The stock options were granted February 25, 2014 with an exercise price of $74.83. These options generally vest over a three-year period from the grant date. The restricted stock and restricted stock units were granted February 25, 2014 and vest on the third anniversary of the date of grant. The performance share awards were granted on February 25, 2014 and can be earned based on performance against established goals over a three-year performance period. The performance share awards are divided into two equal, independent parts that are subject to two separate performance metrics: 50% with a TSR (total shareholder return) goal (the “TSR Award”) and 50% with an internal ROC (return on capital) goal (the “ROC Award”).

Performance against the TSR goal is determined by comparing the performance of the Company’s TSR with the TSR performance of the members of the OSX index for the three year performance period. Performance against the ROC goal is determined by comparing the performance of the Company’s actual ROC performance average for each of the three years of the performance period against the ROC goal set by the Company’s Compensation Committee.

12

10. Derivative Financial Instruments

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

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

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

At March 31, 2014, the Company has determined that the fair value of its derivative financial instruments representing assets of $68 million and liabilities of $24 million (primarily currency related derivatives) are determined using level 2 inputs (inputs other than quoted prices in active markets for identical assets and liabilities that are observable either directly or indirectly for substantially the full term of the asset or liability) in the fair value hierarchy as the fair value is based on publicly available foreign exchange and interest rates at each financial reporting date. At March 31, 2014, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $44 million.

At March 31, 2014, the Company did not have any interest rate swaps and its financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

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

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

13

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

	Currency Denomination
Foreign Currency	March 31,   2014		December 31, 2013
Norwegian Krone	NOK	10,172	NOK	10,503
Euro	€	500	€	406
U.S. Dollar	$	443	$	357
Danish Krone	DKK	266	DKK	278
British Pound Sterling	£	52	£	23
Singapore Dollar	SGD	36	SGD	17
Canadian Dollar	CAD	16	CAD	16

Non-designated Hedging Strategy

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

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

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

	Currency Denomination
Foreign Currency	March 31,   2014		December 31, 2013
Norwegian Krone	NOK	3,866	NOK	3,257
Russian Ruble	RUB	1,786	RUB	2,149
U.S. Dollar	$	801	$	715
Danish Krone	DKK	383	DKK	177
Euro	€	381	€	310
Singapore Dollar	SGD	15	SGD	3
British Pound Sterling	£	26	£	14
Swedish Krone	SEK	11	SEK	4
Canadian Dollar	CAD	5	CAD	3

14

The Company has the following gross fair values of its derivative instruments and their balance sheet classifications:

NATIONAL OILWELL VARCO, INC.

Fair Values of Derivative Instruments

(In millions)

	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet	March 31,		December 31,		Balance Sheet	March 31,		December 31,
	Location	2014		2013		Location	2014		2013
Derivatives designated as hedging instruments under ASC Topic 815
Foreign exchange contracts	Prepaid and other current assets	$	33	$	35	Accrued liabilities	$	8	$	18
Foreign exchange contracts	Other Assets		13		5	Other Liabilities		3		9
Total derivatives designated as hedging instruments under ASC Topic 815		$	46	$	40		$	11	$	27
Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts	Prepaid and other current assets	$	21	$	19	Accrued liabilities	$	13	$	13
Foreign exchange contracts	Other Assets		1		—	Other Liabilities		—		—
Total derivatives not designated as hedging instruments under ASC Topic 815		$	22	$	19		$	13	$	13
Total derivatives		$	68	$	59		$	24	$	40

The Effect of Derivative Instruments on the Consolidated Statements of Income

($ in millions)

Location of Gain (Loss)

Recognized in Income on

Amount of Gain (Loss)

Location of Gain (Loss)

Derivative (Ineffective

Recognized in Income on

Reclassified from

Amount of Gain (Loss)

Portion and Amount

Derivative (Ineffective

Derivatives in ASC Topic 815

Amount of Gain (Loss)

Accumulated OCI into

Reclassified from

Excluded from

Portion and Amount

Cash Flow Hedging

Recognized in OCI on

Income

Accumulated OCI into

Effectiveness

Excluded from

Relationships

Derivative (Effective Portion) (a)

(Effective Portion)

Income (Effective Portion)

Testing)

Effectiveness Testing) (b)

Three Months Ended March 31,

Three Months Ended March 31,

Three Months Ended March 31,

2014

2013

2014

2013

2014

2013

Revenue

13

2

Foreign exchange contracts

35

(61

)

Cost of revenue

(3

)

3

Other income (expense), net

13

3

Total

35

(61

)

10

5

13

3

(a) The Company expects that $(19) million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow.

(b) The amount of gain (loss) recognized in income represents nil related to the ineffective portion of the hedging relationships for each of the three months ended March 31, 2014 and 2013, respectively, and $13 million and $3 million related to the amount excluded from the assessment of the hedge effectiveness for the three months ended March 31, 2014 and 2013, respectively.

15

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 March 31,
	2014		2013
Numerator:
Net income attributable to Company	$	589	$	502
Denominator:
Basic—weighted average common shares outstanding		428		426
Dilutive effect of employee stock options and other unvested stock awards		1		2
Diluted outstanding shares		429		428
Net income attributable to Company per share:
Basic	$	1.38	$	1.18
Diluted	$	1.37	$	1.17
Cash dividends per share	$	0.26	$	0.13

ASC Topic 260, “Earnings Per Share” (“ASC Topic 260”) requires companies with unvested participating securities to utilize a two-class method for the computation of Net income attributable to Company per share. The two-class method requires a portion of Net income attributable to Company to be allocated to participating securities, which are unvested awards of share-based payments with non-forfeitable rights to receive dividends or dividend equivalents, if declared. Net income attributable to Company allocated to these participating securities was immaterial for three months ended March 31, 2014 and 2013 and therefore not excluded from Net income attributable to Company per share calculation.

In addition, the Company had stock options outstanding that were anti-dilutive totaling 10 million and 7 million shares for the three months ended March 31, 2014 and 2013, respectively.

12. Cash Dividends

On February 26, 2014, the Company’s Board of Directors approved a cash dividend of $0.26 per share. The cash dividend was paid on March 28, 2014, to each stockholder of record on March 14, 2014. Cash dividends aggregated $111 million and $56 million for the three months ended March 31, 2014 and 2013, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.

13. Commitments and Contingencies

We have received federal grand jury subpoenas and subsequent inquiries from governmental agencies requesting records related to our compliance with export trade laws and regulations. We have cooperated fully with agents from the U.S. Department of Justice (“DOJ”), the Department of Commerce Bureau of Industry and Security (“BIS”), the United States Department of Treasury, Office of Foreign Assets Control (“OFAC”), and U.S. Immigration and Customs Enforcement in responding to the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange Commission in connection with the inquiries previously made by the aforementioned federal agencies. We have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.

On February 20, 2013, the Company acquired Robbins & Myers, Inc. (“R&M”). R&M was subject to an ongoing investigation by the DOJ and the BIS regarding potential export controls violations arising from certain shipments by R&M’s Belgian subsidiary to one customer in Iran, Sudan and Syria in 2005 and 2006. R&M has cooperated with the investigation and is currently negotiating a joint settlement with the DOJ and BIS. We currently anticipate that any administrative fine or criminal penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.

16

In addition, we are involved in various other claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. As of March 31, 2014, the Company recorded an immaterial amount for contingent liabilities representing all contingencies believed to be probable. The Company has also assessed the potential for additional losses above the amounts accrued as well as potential losses for matters that are not probable but are reasonably possible. The total potential loss on these matters cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for and except for the specific cases referred to above, will not materially affect our financial position, cash flow or results of operations. As it relates to the specific cases referred to above we currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position, cash flow or results of operations. These estimated liabilities are based on the Company’s assessment of the nature of these matters, their progress toward resolution, the advice of legal counsel and outside experts as well as management’s intention and experience.

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

14. Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board issued Accounting Standard Update No. 2014-08 “Reporting Discontinued Operations and Disclosures of Disposals of Components of and Entity” (ASU No. 2014-08), which is an update for Accounting Standards Codification Topic No. 205 “Presentation of Financial Statements” and Topic No. 360 “Property, Plant and Equipment’. This update changes the requirements of reporting discontinued operations. Under the amended guidance, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update are effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years, with early adoption permitted. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements. The Company is currently assessing the impact of ASU No. 2014-08 on its consolidated financial position and results of operations.

15. Proposed Spin-off

On May 1, 2014, the Company announced that its Board of Directors had given final approval for the spin-off of its distribution business. The resulting company will be known as NOW Inc. (“NOW”), headquartered in Houston, Texas.

The separation will be completed by way of a pro rata distribution of all of the outstanding shares of NOW common stock to holders of NOV common stock. This distribution is expected to occur after market close on May 30, 2014 (the “Distribution Date”) to NOV stockholders of record as of the close of business on May 22, 2014 (the “Record Date”). On the Distribution Date, each NOV stockholder as of the Record Date will receive one share of NOW common stock for every four shares of NOV common stock held at the close of business on the Record Date.

Following the distribution of NOW common stock, NOW will be an independent, publicly traded company, and NOV will retain no ownership interest in NOW. NOW expects to receive approval soon for the listing of its common stock on the New York Stock Exchange under the symbol DNOW.

The Company expects to receive an opinion from its legal counsel to the effect that, based on certain facts, assumptions, representations and undertakings, for U.S. federal income tax purposes, the distribution of NOW common stock and certain related transactions generally will not be taxable to NOV or U.S. holders of NOV common stock. No action is required by NOV stockholders in order to receive shares of NOW common stock in the distribution.

16. Subsequent Event

In conjunction with the proposed spin-off of its distribution business, the Company reviewed its reporting and management structure, and beginning on April 1, 2014, reorganized its remaining reporting segments into four new reporting segments. The new reporting segments are Rig Systems, Rig Aftermarket, Completion & Production Solutions, and Wellbore Technologies. The Company is in the process of gathering the new segment information and will begin reporting the new segment information beginning in the second quarter of 2014.

17

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; blowout preventers; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; wireline trucks; cranes; flexible pipe for offshore production applications; 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, training and service capabilities, including adding additional operations in the United States, Canada, Norway, Denmark, the United Kingdom, Brazil, China, Belarus, India, Russia, the Netherlands, Singapore, South Korea, South Africa, and Angola.

Petroleum Services & Supplies

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

18

Distribution & Transmission

Our Distribution & Transmission segment provides pipe, maintenance, repair and operating supplies (“MRO”) and spare parts to drill sites and production locations, pipeline operations, processing plants, and industrial facilities worldwide. In addition to its comprehensive field location network, which supports land drilling operations throughout North America, the segment supports major land and offshore operations for all the major oil and gas producing regions throughout the world. The segment employs advanced information technologies to provide complete procurement, materials management and logistics services to its customers around the globe. The segment also has a global reach in oil and gas, waste water treatment, chemical, food and beverage, paper and pulp, mining, agriculture, and a variety of municipal markets and is a leading producer of water transmission pipe, fabricated steel products and specialized materials and products used in infrastructure projects. Demand for the segment’s services is determined primarily by the level of drilling, servicing, and oil and gas production activities. It is also influenced by the domestic economy in general, housing starts and government policies. This segment has benefited from several strategic acquisitions and other investments completed around the world during the past few years, including the acquisition of the Wilson distribution business segment from Schlumberger Limited and CE Franklin Ltd. in Canada, both of which were completed in 2012, as well as additional operations in the United States, Canada, the United Kingdom, Kazakhstan, Singapore, Russia, and Malaysia.

Critical Accounting Policies and Estimates

In our annual report on Form 10-K for the year ended December 31, 2013, 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; impairment of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets; purchase price allocation of acquisitions; 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.

19

EXECUTIVE SUMMARY

For its first quarter ended March 31, 2014, the Company generated $589 million in net income attributable to Company, or $1.37 per fully diluted share, on $5.8 billion in revenue. Compared to the fourth quarter of 2013, revenue decreased $395 million or 6% and net income attributable to Company decreased $69 million or 10%. Compared to the first quarter of 2013, revenue increased $470 million or 9%, and net income attributable to Company increased $87 million or 17%.

The first quarter of 2014 included pre-tax other costs of $19 million, the fourth quarter of 2013 included pre-tax other costs of $16 million, and the first quarter of 2013 included pre-tax other costs of $65 million. Excluding the other costs and pre-tax gains from all periods, first quarter 2014 earnings were $1.40 per fully diluted share, compared to $1.56 per fully diluted share in the fourth quarter of 2013 and $1.29 per fully diluted share in the first quarter of 2013.

Pre-tax other costs of $19 million, $16 million, and $73 million for the first quarter of 2014, the fourth quarter of 2013 and the first quarter of 2013, respectively, included costs related to legal, acquisition, DNOW spinoff and the amortization of backlog and inventory that was stepped up to fair value during purchase accounting.

Operating profit, excluding other costs, was $880 million or 15.2% of sales in the first quarter of 2014, compared to $973 million or 15.8% of sales in the fourth quarter of 2013, and $816 million or 15.4% of sales in the first quarter of 2013.

Oil & Gas Equipment and Services Market

Worldwide, developed economies turned down in late 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks responded vigorously through 2009, but a credit-driven worldwide economic recession developed nonetheless. Developed economies struggled to recover throughout 2010 and 2011, facing additional economic weakness related to potential sovereign debt defaults in Europe. As a result, commodity prices, including oil and gas prices, have been volatile. After rising steadily for six years to peak at around $140 per barrel (West Texas Intermediate Crude Prices) earlier in 2008, oil prices collapsed back to average $43 per barrel during the first quarter of 2009, but slowly recovered into the $100 per barrel range by mid-2011 where they held relatively steady since (although the fourth quarter of 2012 dipped to average $88 per barrel). After trading in the range of $6 to $9 an mmbtu from 2004 to 2008, North American gas prices declined to average $3.17 per mmbtu in the third quarter of 2009. Gas prices recovered modestly, trading up above $5 six months later, but then slowly settled into the $3 to $4 per mmbtu through 2011 before turning down sharply in early 2012 to the $2 range. However, the average quarterly price per mmbtu climbed steadily since the second quarter of 2012 to an average of $5.18 per mmbtu in the first quarter of 2014 significantly up from a full year 2013 average of $3.72 per mmbtu. Recent price upticks seem to be a product of relatively colder weather; and, as a result, the supply of natural gas stockpiles diminishing.

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. Since 2009, commodity prices and oil-drilling activity have improved.

The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a low of 876 in June, 2009. U.S. rig count increased steadily to 2,026 by late 2011, but began to decline with lower gas prices to average 1,781 rigs during the first quarter of 2014. Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity in 2009, but drilling recovered across North America as gas prices improved. Recently low gas prices have caused operators to trim drilling, driving the average U.S. gas rig count down 61% from the fourth quarter of 2011, to an average of 345 in the first quarter of 2014. However, with high oil prices, many have redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. For the first quarter of 2014, oil-directed drilling rose above 80% of the total domestic drilling effort, and remains at its highest levels in the U.S. since the early 1980’s.

Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings; but, the international rig count exhibited modest declines nonetheless, falling from its 1,108 in September 2008 to 947 in August 2009. Since that decline, international drilling activity has increased and averaged 1,337 rigs in the first quarter of 2014.

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

20

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 (a substantial portion of which are more than 25 years old); 2.) replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and 3.) build out additional deepwater floating drilling rigs, including semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet.

As a result of these trends the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at June 30, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $4.9 billion by June 30, 2010. The backlog increased steadily since, as drillers began ordering more than the Company shipped out of backlog, and finished the first quarter of 2014 at a record $16.3 billion. Approximately $7.2 billion of these orders are scheduled to flow out as revenue over the remainder of 2014, with the balance flowing out in 2015 and beyond. Of this backlog, 92% of the total is for equipment destined for offshore operations, with 8% destined for land. Equipment destined for international markets totaled 94% of the backlog.

Segment Performance

The Rig Technology segment generated $3.0 billion in revenues and $634 million in operating profit or 21.1% of sales in the first quarter of 2014. Compared to the prior quarter, revenues decreased $301 million, and operating profit decreased $58 million, representing 19% decremental operating leverage. Compared to the first quarter of 2013, segment revenues grew $381 million or 15%, and operating profit increased $84 million, representing 22% incremental leverage. Margins have moved down steadily since mid-2010 due to an adverse mix shift in the segment, the addition of lower-margin acquisitions, and incremental expenses to support several strategic growth initiatives. The mix shift arises from offshore projects contracted at high prices in 2007 and 2008, which were subsequently manufactured in low cost environments in 2009 and 2010, resulting in high margins for the group which peaked in the third quarter of 2010. As these projects have been completed and replaced with lower priced projects, margins have gradually declined. Margins have also been negatively impacted by the compression of delivery schedules from our shipyard customers, which have challenged the limits of our supply chain and increased our overall project costs. Revenue out of backlog declined 12% sequentially, and increased 12% year-over-year. Non-backlog revenue, which is predominantly aftermarket spares and services was flat sequentially, and increased 22% from the first quarter of 2013. Orders for three deepwater floating rig equipment packages, and seventeen drilling equipment packages for jackup rigs, contributed to total order additions to backlog of $2.3 billion during the first quarter of 2014.

The Petroleum Services & Supplies segment generated $1.8 billion in revenue and $321 million in operating profit, or 17.9% of sales, for the first quarter of 2014. Compared to the prior quarter, revenue decreased $136 million or 7%, and operating profit decreased $42 million, representing 31% decremental operating leverage. Although the segment’s North American revenues grew 7% sequentially, overall revenues declined due to large year-end shipments of drill pipe and solids control equipment that took place in the fourth quarter of 2013. Compared to the first quarter of 2013, revenues increased $88 million, and operating profit increased $66 million, representing 75% incremental leverage. Both revenues and operating profit were positively influenced by a higher average rig count year-over-year and the fact that our customers have worked through the excess inventory they carried into early 2013. For the first quarter of 2014, approximately 57% of the segment’s sales were into North American markets, and 43% of sales were into international markets.

The Distribution & Transmission segment generated $1.3 billion in revenue and $55 million in operating profit or 4.3% of sales during the first quarter of 2014. Revenues improved $28 million or 2% from the fourth quarter of 2013, and operating profit increased $3 million. Compared to the first quarter of 2013, revenues increased $54 million or 4% and operating profit decreased $8 million. Sequentially, the resumption of drilling and completions activities in Canada, coupled with continued growth in international markets, drove the increase. The year-over-year revenue growth was driven primarily by improvement in U.S. and international drilling and well service activity, which positively impacted day-to-day sales of maintenance, repair and operating consumables. For the first quarter of 2014, approximately 81% of the group’s sales were into North American markets and 19% into international markets.

21

Outlook

Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher drilling activity in North America and slowly improving international drilling activity. Order levels for new deepwater drilling rigs have rebounded, and the Rig Technology segment continues to experience a high level of interest as dayrates for deepwater offshore rigs remain high. Still, margins, which were 21.1% in the first quarter of 2014, may continue to be challenged to expand significantly beyond current levels due to lower-margin contributions from recent subsea production equipment acquisitions, weak workover and pressure pumping equipment markets in North America, higher costs of execution resulting from significantly compressed project timelines, continued flow through of lower priced projects, and incremental expenses to support long-term strategic growth initiatives. In contrast, several factors could positively impact margins over the long term including a more aggressive contract pricing strategy initiated in the second quarter of 2013, increased manufacturing capacity that will allow for reduced supply chain stress associated with aggressive delivery schedules, and increasing demand for pressure pumping and coiled tubing units along with continued growth in aftermarket sales and service.

Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution & Transmission segment remains closely tied to the rig count, particularly in North America. Average U.S. rig count during the first quarter of 2014 saw modest gains of 1% compared to both the fourth and first quarters of 2013. The first quarter of 2014 saw average Canadian rig count improve 39% sequentially but remain relatively flat year-over-year. As a result, revenues for both segments improved sequentially in Canada. Domestic land drilling and well service firms are increasing activity, which is leading to increased demand for drilling and stimulation equipment to develop unconventional shales. However, for both the U.S. and Canada, pricing and volumes remain stressed as pressure pumpers, drilling contractors and oil companies reduce operating and capital expenditures. Additionally, economic weakness may pressure oil prices, which could lead to further activity declines, particularly among North American operators which may rely on cash flows from gas production and/or external financing to fund their drilling operations. In contrast, activity generally seems to be continuing to increase in most international markets outside North America.

The Company believes it is well positioned, and should benefit from its strong balance sheet and capitalization, access to credit, global infrastructure, broad product and service offering, installed base of equipment, and a record level of contracted orders. In the event of a market downturn, the Company also believes that its long history of cost-control and downsizing in response to slowing market conditions, and of executing strategic acquisitions during difficult periods will enable it to capitalize on new opportunities.

22

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 first quarter of 2014 and 2013, and the fourth quarter of 2013 include the following:

							%			%
							1Q14 v			1Q14 v
	1Q14*		1Q13*		4Q13*		1Q13			4Q13
Active Drilling Rigs:
U.S.		1,781		1,758		1,757		1.3	%		1.4	%
Canada		526		536		378		(1.9	%)		39.2	%
International		1,337		1,274		1,321		4.9	%		1.2	%
Worldwide		3,644		3,568		3,456		2.1	%		5.4	%
West Texas Intermediate Crude Prices (per barrel)	$	98.75	$	94.34	$	97.34		4.7	%		1.4	%
Natural Gas Prices ($/mmbtu)	$	5.18	$	3.49	$	3.84		48.4	%		34.9	%

* Averages for the quarters indicated. See sources below.

The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended March 31, 2014, 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).

23

The worldwide quarterly average rig count increased 5.4% (from 3,456 to 3,644) and the U.S. increased 1.4% (from 1,757 to 1,781), in the first quarter of 2014 compared to the fourth quarter of 2013. The average per barrel price of West Texas Intermediate Crude increased 1.4% (from $97.34 per barrel to $98.75 per barrel) and natural gas prices increased 34.9% (from $3.84 per mmbtu to $5.18 per mmbtu) in the first quarter of 2014 compared to the fourth quarter of 2013.

U.S. rig activity at April 25, 2014 was 1,861 rigs increased four percent compared to the first quarter average of 1,781 rigs. The price for West Texas Intermediate Crude was at $100.60 per barrel at April 25, 2014, increasing two percent from the first quarter average. The price for natural gas was at $4.65 per mmbtu at April 25, 2014, decreasing 10 percent from the first quarter average.

Results of Operations

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

	Three Months Ended March 31,
	2014			2013
Revenue:
Rig Technology	$	3,009		$	2,628
Petroleum Services & Supplies		1,789			1,701
Distribution & Transmission		1,281			1,227
Eliminations		(302	)		(249	)
Total Revenue	$	5,777		$	5,307
Operating Profit:
Rig Technology	$	634		$	550
Petroleum Services & Supplies		321			255
Distribution & Transmission		55			63
Unallocated expenses and eliminations		(149	)		(117	)
Total Operating Profit	$	861		$	751
Operating Profit %:
Rig Technology		21.1	%		20.9	%
Petroleum Services & Supplies		17.9	%		15.0	%
Distribution & Transmission		4.3	%		5.1	%
Total Operating Profit %		14.9	%		14.2	%

Rig Technology

Three Months Ended March 31, 2014 and 2013. Revenue from Rig Technology was $3,009 million for the three months ended March 31, 2014, compared to $2,628 million for the three months ended March 31, 2013, an increase of $381 million (14.5%). Additional capacity enabled Rig Technology to generate revenue out of backlog of $2,221 million for the three months ended March 31, 2014, a 12% increase compared to the same period in 2013. Increases in the Company’s aftermarket and FPSO businesses also contributed to the increase in revenue for Rig Technology. Increased demand for land drilling equipment in North America was helped by a first quarter 2014 rig count average of 2,307 rigs slightly higher than the first quarter 2013 average of 2,294 rigs.

Operating profit from Rig Technology was $634 million for the three months ended March 31, 2014 compared to $550 million for the three months ended March 31, 2013, an increase of $84 million (15.3%). Operating profit percentage increased in the three months ended March 31, 2014 to 21.1%, from 20.9% in the three months ended March 31, 2013. Operating profit percentage remained relatively flat as the segment continues to work through lower priced backlog, faces more aggressive delivery schedules and incurs increasing installation and commissioning costs, as well as considerable start-up costs associated with expansion projects such as construction of an NOV Flexibles plant in Brazil.

24

The Rig Technology segment monitors its capital equipment backlog to plan its business. New orders are added to backlog only when the Company receives a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $16.3 billion at March 31, 2014, an increase of $3.4 billion (26.4%) from backlog of $12.9 billion at March 31, 2013. At March 31, 2014, approximately 92% of the capital equipment backlog was for offshore products and 8% was for land. In addition, at March 31, 2014, approximately 94% of the capital equipment backlog was for international markets and 6% was for domestic markets.

Petroleum Services & Supplies

Three Months Ended March 31, 2014 and 2013. Revenue from Petroleum Services & Supplies was $1,789 million for the three months ended March 31, 2014 compared to $1,701 million for the three months ended March 31, 2013, an increase of $88 million (5.2%). This increase is primarily due to a slight strengthening in the U.S. market as well as continued growth internationally and the full quarter effect of Robbins & Myers.

Operating profit from Petroleum Services & Supplies was $321 million for the three months ended March 31, 2014 compared to $255 million for the three months ended March 31, 2013, an increase of $66 million (25.9%). Operating profit percentage increased to 17.9% in the three months ended March 31, 2014, up from 15.0% in the three months ended March 31, 2013. This increase is primarily due to higher volumes and lower integration costs for the three months ended March 31, 2014 compared to the same period in 2013.

Distribution & Transmission

Three Months Ended March 31, 2014 and 2013. Revenue from Distribution & Transmission was $1,281 million for the three months ended March 31, 2014 compared to $1,227 million for the three months ended March 31, 2013, an increase of $54 million (4.4%). This increase was primarily attributable to a slight strengthening in the U.S. market as well as increased projects in the Middle East.

Operating profit from Distribution & Transmission was $55 million (which was negatively impacted by $13 million in other costs primarily associated with the proposed spin-off of the Company’s distribution business) for the three months ended March 31, 2014 compared to $63 million for the three months ended March 31, 2013, a decrease of $8 million (12.7%). Operating profit percentage decreased in the three months ended March 31, 2014 to 4.3%, from 5.1% in the three months ended March 31, 2013. This decrease was primarily attributable to other costs associated with the proposed spin-off of the Company’s distribution business.

Unallocated expenses and eliminations

Unallocated expenses and eliminations were $149 million and $117 million for the three months ended March 31, 2014 and 2013, respectively. This increase is primarily due to higher intersegment eliminations as a result of increased.

Other income (expense), net

Other income (expense), net were nil and expenses of $21 million for the three months ended March 31, 2014 and 2013, respectively. The decrease in expense is primarily due to exchange rate movements. During the first quarter of 2014, the Company recorded $5 million in currency exchange gains compared to $13 million in losses for the same period in 2013.

Provision for income taxes

The effective tax rate for the three months ended March 31, 2014 was 30.6 %, compared to 30.9 % for the same period in 2013. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the periods by the effect of lower tax rates on income earned in foreign jurisdictions, foreign exchange losses for tax reporting in Norway, and the deduction in the U.S. for manufacturing activities.

25

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 internally to evaluate and manage the Company’s operations because we believe it provides useful supplemental information regarding the Company’s on-going economic performance. 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
	March 31,						December 31,
	2014			2013			2013
Reconciliation of operating profit:
GAAP operating profit	$	861		$	751		$	957
Other costs (1):
Rig Technology		1			7			5
Petroleum Services & Supplies		5			56			3
Distribution & Transmission		13			2			8
Operating profit excluding other costs	$	880		$	816		$	973
	Three Months Ended
	March 31,						December 31,
	2014			2013			2013
Reconciliation of operating profit %:
GAAP operating profit %		14.9	%		14.2	%		15.5	%
Other costs %		0.3	%		1.2	%		0.3	%
Operating profit % excluding other costs		15.2	%		15.4	%		15.8	%
	Three Months Ended
	March 31,						December 31,
	2014			2013			2013
Reconciliation of diluted earnings per share:
GAAP earnings per share	$	1.37		$	1.17		$	1.53
Other costs (1)		0.03			0.12			0.03
Earnings per share excluding other costs	$	1.40		$	1.29		$	1.56

(1) Other costs primarily related to acquisitions, such as transaction costs, the amortization of backlog and inventory that was stepped up to fair value during purchase accounting, the costs of the proposed spin-off of the Company’s distribution business and certain legal costs, items which are included in operating profit. For the three months ended March 31, 2014 and 2013, other costs included in operating profit were $19 million and $65 million, respectively. Certain other costs are included in other income (expense), net were nil and $8 million for the three months ended March 31, 2014 and 2013, respectively. Other costs for the three months ended December 31, 2013 totaled $16 million.

26

Liquidity and Capital Resources

Overview

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

At March 31, 2014, the Company had cash and cash equivalents of $3,688 million, and total debt of $3,149 million. At December 31, 2013, cash and cash equivalents were $3,436 million and total debt was $3,150 million. A significant portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. Of the $3,688 million of cash and cash equivalents at March 31, 2014, approximately $3,262 million is held outside the U.S. If opportunities to invest in the U.S. are greater than available cash balances, rather than repatriating this cash, the Company may choose to borrow against its revolving credit facility or its commercial paper program.

The Company’s outstanding debt at March 31, 2014 was $3,149 million and consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,396 million in 2.60% Senior Notes, $1,096 million in 3.95% Senior Notes, and other debt of $6 million.

At March 31, 2014, the Company had no commercial paper borrowings and no borrowings against its $3.5 billion revolving credit facility. Funds available under the Company’s revolving credit facility were $2,509 million due to $991 million in outstanding letters of credit issued under the facility.

The Company also had $3,223 million of additional outstanding letters of credit at March 31, 2014, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds, advanced payment bonds and performance bonds.

The following table summarizes our net cash 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):

	Three Months Ended March 31,
	2014			2013
Net cash provided by operating activities	$	488		$	506
Net cash used in investing activities		(126	)		(2,535	)
Net cash provided by (used in) financing activities		(105	)		1,162

Operating Activities

For the first three months of 2014, cash provided by operating activities was $488 million compared to $506 million in the same period of 2013. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $589 million plus non-cash charges of $233 million, less $10 million in equity income.

Net changes in operating assets and liabilities, net of acquisitions, used $385 million for the first three months of 2014 compared to $134 million used in the same period in 2013. This increase in the first quarter of 2014 compared to the same period in 2013 was primarily the result of a temporary decrease in cash collections in our Distribution & Transmission segment, where the implementation of SAP led to slight delays in the collection process, and in our Rig Technology segment that experienced payment delays from some larger offshore rig customers. This increase was partially offset by continued customer financing, where prepayments and milestone invoicing on major projects outpaced costs incurred.

27

Investing Activities

For the first three months of 2014, net cash used in investing activities was $126 million compared to $2,535 million for the same period of 2013. Net cash used in investing activities continued to primarily be the result of acquisition activity and capital expenditures both of which decreased in the first three months of 2014 compared to the first three months of 2013. The Company used approximately $2 million for acquisitions in the first three months of 2014, a significant decrease compared to approximately $2.5 billion for the purpose of acquiring Robbins & Myers during the first three months of 2013. In addition, the Company used $131 million during the first three months of 2014 for capital expenditures compared to $168 million for the same period of 2013.

Financing Activities

For the first three months of 2014, net cash used in financing activities was $105 million compared to net cash provided by financing activities of $1,162 million for the same period of 2013. The change was primarily due to increased dividends and no borrowings during the first three months of 2014 compared to $1,200 million in net borrowings on the Company’s revolving credit facility, most of which was used to acquire Robbins & Myers, for the same period of 2013.

Other

The effect of the change in exchange rates on cash flows was a decrease of $5 million and $11 million for the first three months of 2014 and 2013, respectively.

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

We intend to pursue additional acquisition candidates, but the timing, size or success of any acquisition effort and the related potential capital commitments cannot be predicted. We continue to expect to fund future acquisitions primarily with cash flow from operations and borrowings, including the unborrowed portion of the credit facility, our commercial paper program 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 April 2014, the Financial Accounting Standards Board issued Accounting Standard Update No. 2014-08 “Reporting Discontinued Operations and Disclosures of Disposals of Components of and Entity” (ASU No. 2014-08), which is an update for Accounting Standards Codification Topic No. 205 “Presentation of Financial Statements” and Topic No. 360 “Property, Plant and Equipment’. This update changes the requirements of reporting discontinued operations. Under the amended guidance, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update are effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years, with early adoption permitted. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements. The Company is currently assessing the impact of ASU No. 2014-08 on its consolidated financial position and results of operations.

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,” “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, 2013, 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.

28

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 gain in our income statement of approximately $5 million in the first three months of 2014, compared to a $13 million foreign exchange loss in the same period of the prior year. The gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods at March 31, 2014 (in millions, except contract rates):

	As of March 31, 2014										December 31,
Functional Currency	2014			2015		2016		Total			2013
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		202			—		—		202			229
Average USD to CAD contract rate		1.1205			—		—		1.1205			1.0669
Fair Value at March 31, 2014 in U.S. dollars		(2	)		—		—		(2	)		1
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		205			48		—		253			51
Average USD to CAD contract rate		1.1131			1.1180		—		1.1140			1.0230
Fair Value at March 31, 2014 in U.S. dollars		—			—		—		—			(1	)
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		6			—		—		6			9
Average USD to EUR contract rate		0.7334			0.7405		—		0.7342			7.5900
Fair Value at March 31, 2014 in U.S. dollars		—			—		—		—			1
Sell USD/Buy EUR:
Notional amount to buy (in euros)		348			32		—		380			344
Average USD to EUR contract rate		0.7347			0.7340		—		0.7346			0.7401
Fair Value at March 31, 2014 in U.S. dollars		5			—		—		5			9
KRW Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)		195,421			—		—		195,421			195,020
Average USD to KRW contract rate		1,085			—		—		1,085			1,114
Fair Value at March 31, 2014 in U.S. dollars		2			—		—		2			10

29

	As of March 31, 2014											December 31,
Functional Currency	2014			2015			2016		Total			2013
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		—			—			—		—			11
Average USD to GBP contract rate		—			—			—		—			0.6142
Fair Value at March 31, 2014 in U.S. dollars		—			—			—		—			—
Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		57			11			—		68			73
Average USD to GBP contract rate		0.6157			0.6092			—		0.6146			0.6201
Fair Value at March 31, 2014 in U.S. dollars		2			—			—		2			2
USD Buy CAD/Sell USD:
Notional amount to buy (in U.S. dollars)		8			9			—		17			15
Average CAD to USD contract rate		0.9389			0.9399			—		0.9395			0.9431
Fair Value at March 31, 2014 in U.S. dollars		—			—			—		—			—
Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		61			24			—		85			71
Average DKK to USD contract rate		0.1811			0.1832			—		0.1817			0.1813
Fair Value at March 31, 2014 in U.S. dollars		1			—			—		1			1
Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		600			269			9		878			773
Average EUR to USD contract rate		1.3476			1.3637			1.3915		1.3529			1.3411
Fair Value at March 31, 2014 in U.S. dollars		12			3			—		15			21
Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		89			14			—		103			42
Average GBP to USD contract rate		1.6350			1.5978			—		1.6298			1.5779
Fair Value at March 31, 2014 in U.S. dollars		1			1			—		2			1
Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		1,067			724			100		1,891			1,877
Average NOK to USD contract rate		0.1647			0.1623			0.1578		0.1634			0.1642
Fair Value at March 31, 2014 in U.S. dollars		8			8			3		19			(28	)
Buy MXN/Sell USD:
Notional amount to buy (in U.S. dollars)		39			—			—		39			—
Average MXN to USD contract rate		0.0754			—			—		0.0754			—
Fair Value at March 31, 2014 in U.S. dollars		—			—			—		—			—
Buy SGD/Sell USD:
Notional amount to buy (in U.S. dollars)		32			6			1		39			15
Average SGD to USD contract rate		0.7887			0.7957			0.7874		0.7897			0.7966
Fair Value at March 31, 2014 in U.S. dollars		—			—			—		—			—
Sell CAD/Buy USD:
Notional amount to buy (in U.S. dollars)		2			—			—		2			2
Average CAD to USD contract rate		0.9614			—			—		1.0178			1.3625
Fair Value at March 31, 2014 in U.S. dollars		—			—			—		—			—
Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		32			—			—		32			11
Average DKK to USD contract rate		0.1828			—			—		0.1828			1.3625
Fair Value at March 31, 2014 in U.S. dollars		—			—			—		—			—
Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		321			—			—		321			190
Average EUR to USD contract rate		1.3894			—			—		1.3894			1.3109
Fair Value at March 31, 2014 in U.S. dollars		3			—			—		3			(2	)
Sell GBP/Buy USD:
Notional amount to sell (in U.S. dollars)		22			—			—		22			—
Average GBP to USD contract rate		1.6034			—			—		1.6034			—
Fair Value at March 31, 2014 in U.S. dollars		(1	)		—			—		(1	)		—
Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		331			71			—		402			385
Average NOK to USD contract rate		0.1650			0.1606			—		0.1642			0.1634
Fair Value at March 31, 2014 in U.S. dollars		(2	)		(1	)		—		(3	)		6

30

	As of March 31, 2014									December 31,
Functional Currency	2014		2015			2016		Total		2013
Sell SGD/Buy USD:
Notional amount to buy (in U.S. dollars)		2		—			—		2		1
Average SGD to USD contract rate		0.7910		—			—		0.7910		0.8000
Fair Value at March 31, 2014 in U.S. dollars		—		—			—		—		—
Sell RUB/Buy USD:
Notional amount to buy (in U.S. dollars)		49		—			—		49		64
Average RUB to USD contract rate		0.0274		—			—		0.0274		0.0298
Fair Value at March 31, 2014 in U.S. dollars		—		—			—		—		(1	)
Sell SEK/Buy USD:
Notional amount to buy (in U.S. dollars)		1		—			—		1		1
Average SEK to USD contract rate		0.1546		—			—		0.1546		0.1529
Fair Value at March 31, 2014 in U.S. dollars		—		—			—		—		—
DKK Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		104		—			—		104		111
Average DKK to USD contract rate		5.3927		—			—		5.3927		5.6126
Fair Value at March 31, 2014 in U.S. dollars		—		—			—		—		—
Other Currencies
Fair Value at March 31, 2014 in U.S. dollars		2		(1	)		—		1		(1	)
Total Fair Value at March 31, 2014 in U.S. dollars		31		10			3		44		19

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $732 million and translation exposures totaling $593 million as of March 31, 2014 excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on the transactional exposures financial market risk sensitive instruments could affect net income by $48 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $59 million.

The counterparties to forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.

Interest Rate Risk

At March 31, 2014, long term borrowings consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,400 million in 2.60% Senior Notes and $1,100 million in 3.95% Senior Notes, and no borrowings under our revolving credit facility or our commercial paper program. Occasionally a portion of borrowings under our credit facility could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to six months. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.

31

Item 4. Controls and Procedures

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

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

32

PART II — OTHER INFORMATION

Item 4. Mine Safety Disclosures

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

Item 6. Exhibits

Reference is hereby made to the Exhibit Index commencing on page 34.

SIGNATURE

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

Date: May 5, 2014	By: /s/ Jeremy D. Thigpen
	Jeremy D. Thigpen
	Senior Vice President and Chief Financial Officer
	(Duly Authorized Officer, Principal Financial and Accounting Officer)

33

INDEX TO EXHIBITS

(a) Exhibits

2.1	Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 between National-Oilwell, Inc. and Varco International, Inc. (4)
2.2	Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (8)
3.1	Fifth Amended and Restated Certificate of Incorporation of National Oilwell Varco, Inc. (Exhibit 3.1) (1)
3.2	Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (9)
10.1	Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2)
10.2	Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell. (Exhibit 10.2) (2)
10.3	Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3)
10.4	National Oilwell Varco Long-Term Incentive Plan, as amended and restated. (5)*
10.5	Form of Employee Stock Option Agreement. (Exhibit 10.1) (6)
10.6	Form of Non-Employee Director Stock Option Agreement. (Exhibit 10.2) (6)
10.7	Form of Performance-Based Restricted Stock. (18 Month) Agreement (Exhibit 10.1) (7)
10.8	Form of Performance-Based Restricted Stock. (36 Month) Agreement (Exhibit 10.2) (7)
10.9	Credit Agreement, dated as of September 28, 2012, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacities as Administrative Agent, Co-Lead Arranger and Joint Book Runner. (Exhibit 10.1) (10)
10.10	First Amendment to Employment Agreement dated as of December 22, 2008 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (11)
10.11	Second Amendment to Executive Agreement, dated as of December 22, 2008 of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (11)
10.12	First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (11)
10.13	Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (11)
10.14	Second Amendment to Employment Agreement dated as of December 31, 2009 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (12)
10.15	Third Amendment to Executive Agreement, dated as of December 31, 2009, of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (12)
10.16	Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (12)
10.17	First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (12)
10.18	Employment Agreement dated as of January 1, 2004 between Jeremy Thigpen and National Oilwell. (Exhibit 10.1) (13)
10.19	First Amendment to Employment Agreement dated as of December 22, 2008 between Jeremy Thigpen and National Oilwell Varco. (Exhibit 10.2) (13)

34

10.20	Second Amendment to Employment Agreement dated as of December 31, 2009 between Jeremy Thigpen and National Oilwell Varco. (Exhibit 10.3) (13)
10.21	Form of Performance Award Agreement (Exhibit 10.1) (14)
31.1	Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
31.2	Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
32.1	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95	Mine Safety Information pursuant to section 1503 of the Dodd-Frank Act.
101	The following materials from our Quarterly Report on Form 10-Q for the period ended March 31, 2014 formatted in eXtensible Business Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (15)

* Compensatory plan or arrangement for management or others.

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

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

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

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

(5) Filed as Appendix I to our Proxy Statement filed on April 10, 2013.

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

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

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

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

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

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

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

(13) Filed as an Exhibit to our Current Report on Form 8-K filed on December 7, 2012.

(14) Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2013.

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

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

35