Edgar Filing: NATIONAL OILWELL VARCO INC

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10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2018

☐	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 ☒ 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 ☒ No ☐

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

As of April 20, 2018 the registrant had 382,022,766 shares of common stock, par value $0.01 per share, outstanding.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In millions, except share data)


	March 31,			December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	1,236		$	1,437
Receivables, net		2,102			2,015
Inventories, net		3,146			3,003
Contract assets		415			495
Prepaid and other current assets		287			267

Total current assets		7,186			7,217
Property, plant and equipment, net		2,926			3,002
Deferred income taxes		13			13
Goodwill		6,217			6,227
Intangibles, net		3,215			3,301
Investment in unconsolidated affiliates		312			309
Other assets		141			137

Total assets	$	20,010		$	20,206

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	528		$	510
Accrued liabilities		965			1,238
Contract liabilities		598			519
Current portion of long-term debt and short-term borrowings		6			6
Accrued income taxes		35			81

Total current liabilities		2,132			2,354
Long-term debt		2,707			2,706
Deferred income taxes		685			677
Other liabilities		335			309

Total liabilities		5,859			6,046

Commitments and contingencies
Stockholders’ equity:
Common stock—par value $.01; 1 billion shares authorized; 381,900,610 and 380,104,970 shares issued and outstanding at March 31, 2018 and December 31, 2017		4			4
Additional paid-in capital		8,256			8,234
Accumulated other comprehensive loss		(1,061	)		(1,110	)
Retained earnings		6,883			6,966

Total Company stockholders’ equity		14,082			14,094
Noncontrolling interests		69			66

Total stockholders’ equity		14,151			14,160

Total liabilities and stockholders’ equity	$	20,010		$	20,206

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF LOSS (UNAUDITED)

(In millions, except per share data)


	Three Months Ended March 31,
	2018			2017
Revenue	$	1,795		$	1,741
Cost of revenue		1,508			1,532

Gross profit		287			209
Selling, general and administrative		288			306

Operating loss		(1	)		(97	)
Interest and financial costs		(24	)		(25	)
Interest income		7			4
Equity income in unconsolidated affiliates		2			—
Other income (expense), net		(47	)		(15	)

Loss before income taxes		(63	)		(133	)
Provision for income taxes		3			(13	)

Net loss		(66	)		(120	)
Net income attributable to noncontrolling interests		2			2

Net loss attributable to Company	$	(68	)	$	(122	)

Net loss attributable to Company per share:
Basic	$	(0.18	)	$	(0.32	)

Diluted	$	(0.18	)	$	(0.32	)

Cash dividends per share	$	0.05		$	0.05

Weighted average shares outstanding:
Basic		377			376

Diluted		377			376

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(In millions)


	Three Months Ended March 31,
	2018			2017
Net loss	$	(66	)	$	(120	)
Currency translation adjustments		36			90
Changes in derivative financial instruments, net of tax		13			5

Comprehensive loss		(17	)		(25	)
Comprehensive income attributable to noncontrolling interest		2			2

Comprehensive loss attributable to Company	$	(19	)	$	(27	)

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In millions)


	Three Months Ended March 31,
	2018			2017
Cash flows from operating activities:
Net loss	$	(66	)	$	(120	)
Adjustments to reconcile net loss to net cash provided (used) by operating activities:
Depreciation and amortization		173			175
Deferred income taxes		5			4
Equity income in unconsolidated affiliates		(2	)		—
Other, net		19			55
Change in operating assets and liabilities, net of acquisitions:
Receivables		(79	)		101
Inventories		(146	)		65
Contract assets		80			12
Prepaid and other current assets		(20	)		16
Accounts payable		14			(26	)
Accrued liabilities		(279	)		(72	)
Contract liabilities		77			(66	)
Income taxes payable		(46	)		(41	)
Other assets/liabilities, net		141			8

Net cash provided (used) by operating activities		(129	)		111

Cash flows from investing activities:
Purchases of property, plant and equipment		(39	)		(42	)
Business acquisitions, net of cash acquired		(36	)		(6	)
Other		14			6

Net cash used in investing activities		(61	)		(42	)

Cash flows from financing activities:
Payments against lines of credit and other debt		(2	)		(2	)
Cash dividends paid		(19	)		(19	)
Activity under stock incentive plans		3			9
Other		—			(1	)

Net cash used in financing activities		(18	)		(13	)
Effect of exchange rates on cash		7			15

Increase (decrease) in cash and cash equivalents		(201	)		71
Cash and cash equivalents, beginning of period		1,437			1,408

Cash and cash equivalents, end of period	$	1,236		$	1,479

Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	3		$	3
Income taxes	$	42		$	56

See notes to unaudited consolidated financial statements.

NATIONAL OILWELL VARCO, INC.

Notes to Consolidated Financial Statements (Unaudited)

1.	Basis of Presentation

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

The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (“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 2017 Annual Report on Form 10-K.

In our opinion, the consolidated financial statements include all adjustments, which are of a normal recurring nature, unless otherwise disclosed, necessary for a fair presentation of the results for the interim periods. Certain reclassifications have been made to the prior year financial statements in order for them to conform with the 2018 presentation. See Note 6. The results of operations for the three months ended March 31, 2018 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,
	2018		2017
Raw materials and supplies	$	659	$	656
Work in process		605		513
Finished goods and purchased products		1,882		1,834

Total	$	3,146	$	3,003

3.	Accrued Liabilities

Accrued liabilities consist of (in millions):


	March 31,		December 31,
	2018		2017
Compensation	$	214	$	345
Vendor costs		142		150
Warranty		129		135
Taxes (non-income)		84		152
Insurance		72		74
Commissions		45		58
Fair value of derivative financial instruments		8		8
Interest		27		7
Other		244		309

Total	$	965	$	1,238

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”. 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, 2017	$	135

Net provisions for warranties issued during the year		5
Amounts incurred		(12	)
Currency translation adjustments and other		1

Balance at March 31, 2018	$	129

4.	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, 2017	$	(1,104	)	$	7		$	(13	)	$	(1,110	)
Accumulated other comprehensive income (loss) before reclassifications		36			16			—			52
Amounts reclassified from accumulated other comprehensive income (loss)		—			(3	)		—			(3	)

Balance at March 31, 2018	$	(1,068	)	$	20		$	(13	)	$	(1,061	)

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


	Three Months Ended March 31,
	2018										2017
	Currency Translation Adjustments		Derivative Financial Instruments			Defined Benefit Plans		Total			Currency Translation Adjustments		Derivative Financial Instruments			Defined Benefit Plans		Total
Revenue	$	—	$	(1	)	$	—	$	(1	)	$	—	$	(5	)	$	—	$	(5	)
Cost of revenue		—		(4	)		—		(4	)		—		(4	)		—		(4	)
Tax effect		—		2			—		2			—		4			—		4

	$	—	$	(3	)	$	—	$	(3	)	$	—	$	(5	)	$	—	$	(5	)

The Company’s reporting currency is the U.S. dollar. For a majority of the Company’s international entities in which there is a substantial investment, the local currency is 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, 2018, a majority of these local currencies strengthened against the U.S. dollar resulting in net other comprehensive income of $36 million, upon the translation from local currencies to the U.S. dollar. For the three months ended March 31, 2017, a majority of these local currencies strengthened against the U.S. dollar resulting in net other comprehensive income of $90 million upon the translation from local currencies to the U.S. dollar.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in other comprehensive income 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 period. The accumulated effect was other comprehensive income of $13 million (net of tax of $4 million) and $5 million (net of tax of $1 million) for the three months ended March 31, 2018 and March 31, 2017, respectively.

5.	Business Segments

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


	Three Months Ended
	March 31,
	2018			2017
Revenue:
Wellbore Technologies	$	711		$	555
Completion & Production Solutions		670			648
Rig Technologies		483			582
Eliminations		(69	)		(44	)

Total revenue	$	1,795		$	1,741

Operating profit (loss):
Wellbore Technologies	$	12		$	(57	)
Completion & Production Solutions		16			8
Rig Technologies		18			13
Eliminations and corporate costs		(47	)		(61	)

Total operating profit (loss)	$	(1	)	$	(97	)

Operating profit (loss)%:
Wellbore Technologies		1.7	%		(10.3	%)
Completion & Production Solutions		2.4	%		1.2	%
Rig Technologies		3.7	%		2.2	%
Total operating profit (loss) %		(0.1	%)		(5.6	%)

Sales from one segment to another generally are priced at estimated equivalent commercial selling prices; however, segments originating an external sale are credited with the full profit to the Company. Eliminations include intercompany transactions conducted between the three reporting segments that are eliminated in consolidation. Intercompany transactions within each reporting segment are eliminated within each reporting segment.

Included in operating profit (loss) are other items primarily related to costs associated with severance, facility closures, and credits for the reversal of certain accruals.

6.	Revenue Recognition

The Company’s products and services are sold based upon purchase orders or contracts with customers that include fixed or determinable prices and do not generally include right of return or other significant post-delivery obligations. The majority of our revenue streams record revenue at a point in time when a performance obligation has been satisfied by transferring control of promised goods or services to the customer. Revenue is recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

Payment terms and conditions vary by contract type. In instances where the timing of revenue recognition differs from the timing of invoicing on contracts with a duration of one year or longer, we have determined our contracts generally do not include a significant financing component, as they are structured to include progress billings commensurate with revenue recognized over time. We have elected to apply the practical expedient that does not require an adjustment for a significant financing component if, at contract inception, the period between when we transfer the promised goods or service to the customer and when the customer pays for the goods or service is one year or less.

The Company elects to treat shipping and handling costs as costs to fulfill a performance obligation instead of as a separate performance obligation. We recognize the cost for shipping and handling when incurred, generally when control over the products has transferred to the customer, as an expense in cost of sales.

Our contracts with customers often include promises to transfer multiple products and services to a customer. Determining whether products and services are considered distinct performance obligations that should be accounted for separately versus together may require significant judgment. We take into consideration the degree of integration of the related products and services, the level of customization of the product for the customer, and the interdependency of the products and services.

Judgment is also required to determine the stand-alone selling price (“SSP”) for each distinct performance obligation. To determine the SSP, the Company uses the price at which the products and services would be sold separately to the customer. We also review past sales transactions to confirm invoice prices for each distinct performance obligation reasonably approximate SSP and that there are no significant deviations. A discount, when provided, is also allocated based on the relative SSP of the various products and services.

We may provide other credits or incentives, which are accounted for as variable consideration when determining the transaction price. These credits or incentives are estimated at contract inception and updated at the end of each reporting period as additional information becomes available and recognized only to the extent that it is probable that a significant reversal of any incremental revenue will not occur.

For revenue that is not recognized at a point in time, the Company follows accounting guidance for revenue recognized over time, as follows:

Revenue Recognition under Long-term Construction Contracts

The Company uses the over-time method to account for certain long-term construction contracts in the Completion & Production Solutions and Rig Technologies segments. These long-term construction contracts include the following characteristics:

•

the contracts include custom designs for customer specific applications;

•

the structural design is unique and requires significant engineering efforts; and

•

the Company has an enforceable right to payment for performance completed to date including a reasonable profit.

Because of control transferring over time, revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost (input) measure of progress for our contracts because it best depicts the transfer of assets to the customer which occurs as we incur costs on our contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of costs incurred to date to the total estimated costs at completion of the performance obligation. Revenues, including estimated fees or profits, are recorded proportionally as costs are incurred. Costs to fulfill include labor, materials and subcontractors’ costs, and other direct costs. If estimates of total costs to be incurred on a performance obligation exceed total estimates of revenue to be earned, a provision for the entire loss on the performance obligation is recognized in the period the loss is determined.

For most of our contracts, the customer contracts with us to provide a significant service of integrating a complex set of tasks and components into a single project or capability. Hence, the entire contract is accounted for as one performance obligation.

Due to the nature of the work required to be performed on many of our performance obligations, the estimation of total revenue and cost at completion is complex, subject to many variables and requires significant judgment. It is common for our long-term contracts to contain late delivery fees, work performance guarantees, and other provisions that can either increase or decrease the transaction price. We estimate variable consideration at the most likely amount to which we expect to pay or be entitled to. We include variable consideration in the estimated transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur or when the uncertainty associated with the variable consideration is resolved. Our estimates of variable consideration and determination of whether to include estimated amounts in the transaction price are based largely on an assessment of our anticipated performance and all information (historical, current and forecasted) that is reasonably available to us. Net revenue recognized from our performance obligations satisfied in previous periods was $22 million for the three months ended March 31, 2018 primarily due to change orders.

Service and Repair Work

For those contracts in which we are providing a service to the customer, the output method is utilized to measure progress due to the manner in which the customer receives and derives value from the services being provided. For repair contracts, we generally use the cost-to-cost measure of progress for our contracts because it best depicts the transfer of assets to the customer which occurs as we incur costs on our contracts.

Remaining Performance Obligations

Remaining performance obligations represents the transaction price of firm orders for all revenue streams for which work has not been performed on contracts with an original expected duration of one year or more. The optional disclosures for the remaining performance obligations of royalty contracts, service contracts for which there is a right to invoice, and short-term contracts that are expected to have a duration of one year or less have not been disclosed.

As of March 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was $2,523 million. The Company expects to recognize approximately $895 million in revenue for the remaining performance obligations in 2018 and $1,628 million in 2019 and thereafter.

Costs to Obtain and Fulfill a Contract

We recognize an asset for the incremental costs of obtaining a contract, such as sales commissions, with a customer when we expect the benefit of those costs to be longer than one year. Costs to fulfill a contract, such as set-up and mobilization costs, are also capitalized when we expect to recover those costs. These contract costs are deferred and amortized over the period of contract performance. Total capitalized costs to obtain and fulfill a contract and the related amortization were immaterial during the periods presented and are included in other current and long-term assets on our consolidated balance sheets.

We apply the practical expedient to expense costs as incurred for costs to obtain a contract with a customer when the amortization period would have been one year or less.

Disaggregation of Revenue

The following tables disaggregate our revenue by destinations, as we believe it best depicts how the nature, amount, timing and uncertainty of our revenue and cash flows are affected by economic factors. In the tables below, North America includes only the U.S. and Canada. (in millions):


	Three Months Ended March 31, 2018
	Wellbore Technologies		Completion & Production Solutions		Rig Technologies		Eliminations			Total
North America	$	415	$	292	$	135	$	—		$	842
International		282		358		313		—			953
Eliminations		14		20		35		(69	)		—

	$	711	$	670	$	483	$	(69	)	$	1,795

Land	$	583	$	446	$	172	$	—		$	1,201
Offshore		114		204		276		—			594
Eliminations		14		20		35		(69	)		—

	$	711	$	670	$	483	$	(69	)	$	1,795


	Three Months Ended March 31, 2017
	Wellbore Technologies		Completion & Production Solutions		Rig Technologies		Eliminations			Total
North America	$	295	$	233	$	120	$	—		$	648
International		248		402		443		—			1,093
Eliminations		12		13		19		(44	)		—

	$	555	$	648	$	582	$	(44	)	$	1,741

Land	$	436	$	403	$	161	$	—		$	1,000
Offshore		107		232		402		—			741
Eliminations		12		13		19		(44	)		—

	$	555	$	648	$	582	$	(44	)	$	1,741

Contract Assets and Liabilities

Contract assets include unbilled amounts typically resulting from sales under long-term contracts when the cost-to-cost method of revenue recognition is utilized and revenue recognized exceeds the amount billed to the customer, and right to payment is not only subject to the passage of time. There were no impairment losses recorded on contract assets for the periods ending March 31, 2018 or 2017.

Contract liabilities consist of advance payments and billings in excess of revenue recognized and deferred revenue. For the balance at December 31, 2017, we reclassified $240 million of advance payments and deferred revenue from accrued liabilities to contract liabilities to conform with the 2018 presentation.

The changes in the carrying amount of contract assets and contract liabilities are as follows (in millions):


Contract Assets
Balance at December 31, 2017	$	495
Additions and Milestone Billings		(213	)
Revenue Recognized		206
Currency translation adjustments and other		(73	)

Balance at March 31, 2018	$	415

Contract Liabilities
Balance at December 31, 2017	$	519
Additions		273
Revenue Recognized		(205	)
Currency translation adjustments and other		11

Balance at March 31, 2018	$	598

Debt

Debt consists of (in millions):


	March 31, 2018		December 31, 2017
$1.4 billion in Senior Notes, interest at 2.60% payable semiannually, principal due on December 1, 2022	$	1,393	$	1,392
$1.1 billion in Senior Notes, interest at 3.95% payable semiannually, principal due on December 1, 2042		1,088		1,088
Other		232		232

Total debt		2,713		2,712
Less current portion		6		6

Long-term debt	$	2,707	$	2,706

The Company has a $3.0 billion, five-year unsecured revolving credit facility, which expires on June 27, 2022. The Company has the right to increase the aggregate commitments under this agreement to an aggregate amount of up to $4.0 billion upon the consent of only those lenders holding any such increase. Interest under the multicurrency facility is based upon LIBOR, NIBOR or CDOR plus 1.125% subject to a ratings-based grid or the U.S. prime rate. The credit facility contains a financial covenant regarding maximum debt-to-capitalization ratio of 60%. As of March 31, 2018, the Company was in compliance with a debt-to-capitalization ratio of 16.1%.

The Company has a commercial paper program under which borrowings are classified as long-term since the program is supported by the $3.0 billion, five-year credit facility. At March 31, 2018, there were no commercial paper borrowings, and there were no outstanding letters of credit issued under the credit facility, resulting in $3.0 billion of funds available under this credit facility.

The Company had $567 million of outstanding letters of credit at March 31, 2018, primarily in the U.S. and Norway, that are under various bilateral committed letter of credit facilities. Letters of credit are issued as bid bonds, advanced payment bonds and performance bonds.

At March 31, 2018 and December 31, 2017, the fair value of the Company’s unsecured Senior Notes approximated $2,323 million and $2,346 million, respectively. 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, 2018 and December 31, 2017, the carrying value of the Company’s unsecured Senior Notes approximated $2,481 million and $2,480 million, respectively.

8.	Income Taxes

The Tax Cuts and Jobs Act (the “Act”) was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%, effective January 1, 2018. At March 31, 2018 and December 31, 2017, we had not completed our accounting for the tax effects of enactment of the Act; however, in certain cases, as described below, we made reasonable estimates of the effects and recorded provisional amounts. We will continue to make and refine our calculations as additional analysis is completed. We recognized an income tax benefit of $242 million in the year ended December 31, 2017 associated with the revaluation of our net deferred tax liability. Our provisional estimate of the one-time transition tax resulted in no additional tax expense. Our provisional estimate on Global Intangible Low Taxed Income (“GILTI”), Foreign Derived Intangible Income (“FDII”), Base Erosion and Anti-Abuse Tax (“BEAT”), and IRC Section 163(j) interest limitation do not impact our effective tax rate for the three months ended March 31, 2018. The accounting for the tax effects of the Act will be completed in 2018 as provided by the U.S. Securities and Exchange Commission’s SAB No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act.

For the three months ended March 31, 2018, the Company utilized the discrete-period method to compute its interim tax provision due to significant variations in the relationship between income tax expense and pre-tax accounting loss. For the three months ended March 31, 2017, the Company estimated and recorded tax based on a full year effective tax rate.

The effective tax rate for the three months ended March 31, 2018 and 2017 was (4.8)% and 9.8%, respectively. The change in effective tax rate was due primarily to the decrease in the U.S. federal corporate tax rate from 35% in 2017 to 21% in 2018. In addition, the Company established valuation allowances on deferred tax assets for losses and tax credits generated in each year, which, when applied to losses resulted in lower effective tax rates than the U.S. statutory rate.

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 (“SARs”). The number of shares authorized under the Plan is 69.4 million. The Plan is subject to a fungible ratio concept, such that the issuance of stock options and SARs reduces the number of available shares under the Plan on a 1-for-1 basis, and the issuance of other awards reduces the number of available shares under the Plan on a 3-for-1 basis. At March 31, 2018, 9,135,374 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 SARs.

On February 28, 2018, the Company granted 1,610,599 stock options with a fair value of $10.01 per share and an exercise price of $35.09 per share; 2,391,933 shares of restricted stock and restricted stock units with a fair value of $35.09 per share; performance share awards to senior management employees with potential payouts varying from zero to 449,532 shares; and 14,228 SARs. The stock options vest over a three-year period from the grant date. The restricted stock and restricted stock units vest in three equal annual installments commencing on the first anniversary of the date of grant. The performance share awards can be earned based on performance against established goals over a three-year performance period. The performance share awards are based entirely on a TSR (total shareholder return) goal. 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.

Total stock-based compensation for all stock-based compensation arrangements under the Plan was $27 million and $30 million for the three months ended March 31, 2018 and 2017, respectively. The total income tax benefit recognized in the Consolidated Statements of Loss for all stock-based compensation arrangements under the Plan was $2 million and $4 million for the three months ended March 31, 2018 and 2017, respectively.

10.

Derivative Financial Instruments

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 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, 2018, the Company has determined that the fair value of its derivative financial instruments representing assets of $42 million and liabilities of $9 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, 2018, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $33 million.

At March 31, 2018, 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 or weakens against the foreign currencies, the change in present value of future foreign currency revenues and expenses is offset by changes in the fair value of the forward contracts designated as hedges.

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 (loss) 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 Loss during the current period.

For the three months ended March 31, 2018, the Company recognized no gains or losses as a result of the discontinuance of certain cash flow hedges when it became probable that the original forecasted transactions would not occur by the end of the originally specified time period. At March 31, 2018, there were $27 million in pre-tax losses recorded in accumulated other comprehensive income (loss). Significant changes in forecasted operating levels or delays in large capital construction projects, whereby certain hedged transactions associated with these projects are no longer probable of occurring by the end of the originally specified time period, could result in losses or gains due to the de-designation of existing hedge contracts.

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


	Currency Denomination
Foreign Currency	March 31, 2018		December 31, 2017
Norwegian Krone	NOK	3,556	NOK	4,013
Japanese Yen	JPY	968	JPY	982
U.S. Dollar	USD	113	USD	163
Euro	EUR	83	EUR	120
Danish Krone	DKK	19	DKK	30
British Pound Sterling	GBP	9	GBP	11

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, 2018		December 31, 2017
Russian Ruble	RUB	2,903	RUB	2,699
Norwegian Krone	NOK	1,407	NOK	1,734
U.S. Dollar	USD	469	USD	463
South African Rand	ZAR	176	ZAR	150
Euro	EUR	106	EUR	99
Danish Krone	DKK	33	DKK	15
British Pound Sterling	GBP	4	GBP	3

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


	Asset Derivatives						Liability Derivatives
			Fair Value						Fair Value
	Balance Sheet Location		March 31, 2018		December 31, 2017		Balance Sheet Location		March 31, 2018		December 31, 2017
Derivatives designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets	$	23	$	13		Accrued liabilities	$	3	$	3
Foreign exchange contracts		Other Assets		11		8		Other liabilities		—		2

Total derivatives designated as hedging instruments under ASC Topic 815			$	34	$	21			$	3	$	5

Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts		Prepaid and other current assets	$	6	$	10		Accrued liabilities	$	5	$	5
Foreign exchange contracts		Other Assets		2		2		Other Liabilities		1		1

Total derivatives not designated as hedging instruments under ASC Topic 815			$	8	$	12			$	6	$	6

Total derivatives			$	42	$	33			$	9	$	11

The Effect of Derivative Instruments on the Consolidated Statements of Income

($ in millions)


Derivatives in ASC Topic 815 Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion) (a)					Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)					Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (b)
	Three Months Ended March 31,									Three Months Ended March 31,							Three Months Ended March 31,
	2018			2017						2018		2017					2018			2017
Foreign exchange contracts		22			13		Revenue Cost of revenue				1 4		5 (11	)		Cost of revenue Other income (expense), net		0 (1	)		15 8

Total		22			13						5		(6	)				(1	)		23


Derivatives Not Designated as Hedging Instruments under ASC Topic 815	Location of Gain (Loss) Recognized in Income on Derivative					Amount of Gain (Loss) Recognized in Income on Derivative
						Three Months Ended March 31,
						2018		2017
Foreign exchange contracts		Other income	(expense), net				11		9

Total							11		9

(a)	The Company expects that $17 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 and $15 million related to the ineffective portion of the hedging relationships for the three months ended March 31, 2018 and 2017, respectively, and $(1) million and $8 million related to the amount excluded from the assessment of the hedge effectiveness for the three months ended March 31, 2018 and 2017, respectively.

11.

Net Loss 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,
	2018			2017
Numerator:
Net loss attributable to Company	$	(68	)	$	(122	)

Denominator:
Basic—weighted average common shares outstanding		377			376
Dilutive effect of employee stock options and other unvested stock awards		—			—

Diluted outstanding shares		377			376

Net loss attributable to Company per share:
Basic	$	(0.18	)	$	(0.32	)

Diluted	$	(0.18	)	$	(0.32	)

Cash dividends per share	$	0.05		$	0.05

ASC Topic 260, “Earnings Per Share” 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 loss attributable to Company allocated to these participating securities was immaterial for the three months ended March 31, 2018 and 2017 and therefore not excluded from net income attributable to Company per share calculation.

The Company had stock options outstanding that were anti-dilutive totaling 19 million and 13 million for the three months ended March 31, 2018 and 2017, respectively.

12.

Cash Dividends

On February 23, 2018, the Company’s Board of Directors approved a cash dividend of $0.05 per share. The cash dividend was paid on March 30, 2018, to each stockholder of record on March 16, 2018. Cash dividends were $19 million for each of the three months ended March 31, 2018 and 2017, 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

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. Our business is also subject to trade regulations that may restrict or prohibit trade with certain countries, companies and/or individuals, such as trade sanctions applicable to Russia, Syria and Iran. We are also subject to increasing local content and localization requirements in various jurisdictions and increasing trade tariff activities, all of which could result in material negative impacts 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 may not result in additional, presently unquantifiable, costs or liabilities to us.

The Company is involved in various other claims, internal investigations, regulatory agency audits and pending or threatened legal actions involving a variety of matters. In many instances, the Company maintains insurance that covers claims arising from risks associated with the business activities of the Company, including claims for premises liability, product liability and other such claims. The Company carries substantial insurance to cover such risks above a self-insured retention. The Company believes and the Company’s experience has been that such insurance has been sufficient to cover such risks. See Item 1A. Risk Factors.

The Company is also a party to claims, threatened and actual litigation, and private arbitration arising from ordinary day to day business activities, in which parties assert claims against the Company for a broad spectrum of potential liabilities, including: individual employment law claims, collective actions under federal employment laws, intellectual property claims, including alleged patent infringement, and/or misappropriation of trade secrets, premises liability claims, personal injuries arising from allegedly defective products, alleged improper payments under anti-corruption and anti-bribery laws and other commercial claims seeking recovery for alleged actual or exemplary damages. From time to time, in litigation adverse parties assert claims for large damages as a tactic to assert leverage to pressure the Company to pay to settle such claims. The Company staunchly resists such litigation tactics. Due to the inherent risks and uncertainty of litigation, an unexpected adverse result may occur from time to time. For many such contingent claims, the Company’s insurance coverage is inapplicable or an exclusion to coverage may apply. In such instances, settlement or other resolution of such contingent claims could have a material financial or reputational impact on the Company.

As of March 31, 2018, the Company recorded reserves in an amount believed to be sufficient for contingent liabilities representing all contingencies believed to be probable to cover liabilities. 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. 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.

Further, in some instances, direct or indirect consumers of our products and services, entities providing financing for purchases of our products and services or members of the supply chain for our products and services have become involved in governmental investigations, internal investigations, political or other enforcement matters. In such circumstances, such investigations may adversely impact the ability of consumers of our products, entities providing financial support to such consumers or entities in the supply chain to timely perform their business plans or to timely perform under agreements with us. We may also become involved in these investigations, at substantial cost to the Company.

14.

New Accounting Pronouncements

Recently Adopted Accounting Standards

In March 2017, the FASB issued Accounting Standard Update No. 2017-07 “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). This update requires that an employer report the service cost component in the same line item as other compensation costs and separately from other components of net benefit cost. ASU 2017-07 is effective for fiscal periods beginning after December 15, 2017, and for interim periods within those fiscal years. The Company adopted this update on January 1, 2018 with no material impact.

In August 2016, the FASB issued Accounting Standard Update No. 2016-15 “Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). This update amends Accounting Standard Codification Topic No. 230 “Statement of Cash Flows” and provides guidance and clarification on presentation of certain cash flow issues. ASU No. 2016-15 is effective for fiscal years beginning after December 15, 2017, and for interim periods within those fiscal years. The Company adopted this update on January 1, 2018 with no material impact.

In May 2014, the FASB issued Accounting Standard Update No. 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09), which supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU proscribes a five-step model for determining when and how revenue is recognized. Under the model, an entity will recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services.

ASU 2014-09 is effective for fiscal periods beginning after December 15, 2017. The Company adopted this update on January 1, 2018, using the modified retrospective approach, in which an immaterial cumulative effect adjustment was made to retained earnings. The adoption of ASU 2014-09 did not have a material impact on the Company’s consolidated financial position, results of operations, equity or cash flows as of the adoption date or for the three months ended March 31, 2018. See Note 6 for additional details of the adoption of this standard.

Recently Issued Accounting Standards

In August 2017, the FASB issued Accounting Standard Update No. 2017-12 “Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). This update improves the financial reporting of hedging relationships and simplifies the application of the hedge accounting guidance. ASU 2017-12 is effective for fiscal periods beginning after December 15, 2018, and for interim periods within those fiscal years. Early adoption is permitted in any interim period after issuance of ASU 2017-12. The Company is currently assessing the impact of the adoption of ASU No. 2017-12 on its consolidated financial position and results of operations.

In March 2016, the FASB issued ASC Topic 842, “Leases” (ASC Topic 842), which supersedes the lease requirements in ASC Topic No. 840 “Leases” and most industry-specific guidance. This update increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASC Topic 842 is effective for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years.

In preparing for the adoption of this new standard, the Company has established an internal team to centralize the implementation process as well as engaged external resources to assist in our approach. We are currently utilizing a software program to consolidate and accumulate leases with documentation as required by the new standard. We have assessed the changes to the Company’s current accounting practices and are investigating the related tax impact and process changes. We are also in process of quantifying the impact of the new standard on our balance sheet.

Item

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

Introduction

National Oilwell Varco, Inc. (the “Company”) is a leading independent provider of equipment and technology to the upstream oil and gas industry. The Company designs, manufactures and services a comprehensive line of drilling and well servicing equipment; sells and rents drilling motors, specialized downhole tools, and rig instrumentation; performs inspection and internal coating of oilfield tubular products; provides drill cuttings separation, management and disposal systems and services; and provides expendables and spare parts used in conjunction with the Company’s large installed base of equipment. The Company also manufactures coiled tubing and high-pressure fiberglass and composite tubing, and sells and rents advanced in-line inspection equipment to makers of oil country tubular goods. The Company has a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety, and environmental impact of oil and gas operations.

Unless indicated otherwise, results of operations are presented in accordance with accounting principles generally accepted in the United States (“GAAP”). Certain reclassifications have been made to the prior year financial statements in order for them to conform with the 2018 presentation. The Company discloses Adjusted EBITDA (defined as Operating Profit excluding Depreciation, Amortization and Other Items) in its periodic earnings press releases and other public disclosures to provide investors additional information about the results of ongoing operations. 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.

Wellbore Technologies

The Company’s Wellbore Technologies segment designs, manufactures, rents, and sells a variety of equipment and technologies used to perform drilling operations, and offers services that optimize their performance, including: solids control and waste management equipment and services; drilling fluids; portable power generation; premium drill pipe; wired pipe; drilling optimization and automation services; tubular inspection, repair and coating services; rope access inspection; instrumentation; measuring and monitoring; downhole and fishing tools; steerable technologies; hole openers; and drill bits.

Wellbore Technologies focuses on oil and gas companies and supports drilling contractors, oilfield service companies, and oilfield equipment rental companies. Demand for the segment’s products and services depends on the level of oilfield drilling activity by oil and gas companies, drilling contractors, and oilfield service companies.

Completion & Production Solutions

The Company’s Completion & Production Solutions segment integrates technologies for well completions and oil and gas production. The segment designs, manufactures, and sells equipment and technologies needed for hydraulic fracture stimulation, including pressure pumping trucks, blenders, sanders, hydration units, injection units, flowline, and manifolds; well intervention, including coiled tubing units, coiled tubing, and wireline units and tools; onshore production, including composite pipe, surface transfer and progressive cavity pumps, and artificial lift systems; and, offshore production, including floating production systems and subsea production technologies.

Completion & Production Solutions supports service companies and oil and gas companies. Demand for the segment’s products depends on the level of oilfield completions and workover activity by oilfield service companies and drilling contractors, and capital spending plans by oil and gas companies and oilfield service companies.

Rig Technologies

The Company’s Rig Technologies segment makes and supports the capital equipment and integrated systems needed to drill oil and gas wells on land and offshore. The segment designs, manufactures and sells land rigs, offshore drilling equipment packages, including installation and commissioning services, and drilling rig components that mechanize and automate the drilling process and rig functionality. Equipment and technologies in Rig Technologies include: substructures, derricks, and masts; cranes; pipe lifting, racking, rotating, and assembly systems; fluid transfer technologies, such as mud pumps; pressure control equipment, including blowout preventers; power transmission systems, including drives and generators; and rig instrumentation and control systems. The segment also provides spare parts, repair, and rentals as well as comprehensive remote equipment monitoring, technical support, field service, and customer training through an extensive network of aftermarket service and repair facilities strategically located in major areas of drilling operations around the world.

Rig Technologies supports land and offshore drillers. Demand for the segment’s products depends on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig construction and refurbishment; and secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts, service, and repair for the segment’s large installed base of equipment.

Critical Accounting Policies and Estimates

In our annual report on Form 10-K for the year ended December 31, 2017, 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 (See Note 6 for new accounting policy on revenue recognition); 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.

EXECUTIVE SUMMARY

For its first quarter ended March 31, 2018, the Company had a $68 million net loss, or $0.18 per fully diluted share, on $1.8 billion in revenue. Compared to the fourth quarter of 2017, revenue decreased $174 million or 9% and net loss increased $54 million or 386%. Compared to the first quarter of 2017, revenue increased $54 million or 3%, and net loss decreased $54 million or 44%.

Operating loss for the first quarter of 2018 was $1 million, or (0.1)% of sales, compared to an operating loss of $111 million in the fourth quarter of 2017 and $97 million in the first quarter of 2017.

During the first quarter of 2018, fourth quarter of 2017, and first quarter of 2017, pre-tax other items (severance, facility closures, reversals of certain reserves and accruals, and other) were a credit of $12 million, and expenses of $133 million and $27 million, respectively. Excluding the other items from all periods, first quarter 2018 Adjusted EBITDA was $160 million, compared to $197 million in the fourth quarter of 2017 and $105 million in the first quarter of 2017.

Oil & Gas Equipment and Services Market

Over the past decade, technological advancements in the oilfield equipment and service space unlocked production from formations that were previously deemed uneconomic, especially in North America. From 2004 to 2014 global oil and liquids supply increased dramatically from U.S. unconventional resources, deep-water (defined as water depths greater than 400 feet) resources and from other sources. The advances in technology combined with relatively high commodity prices caused by growing demand enabled and sustained an increase in global drilling activity. Global supply started to catch up to demand, and, in the latter half of 2014, demand growth in areas such as Asia, Europe and the U.S. weakened while drilling activity remained strong and production continued to grow. As a result, global inventories of crude and refined products grew and the price of oil declined significantly during early 2015, remaining depressed throughout the year and undergoing another major reduction toward the end of 2015. In early 2016, the market witnessed oil trading in the high $20 per barrel range, prices not seen since 2003.

In response to rapidly deteriorating market conditions, operators acutely reduced both operating and capital expenditures. Orders for NOV’s equipment and services slowed and rig counts declined rapidly with active U.S. drilling rig counts hitting 70 year lows, and international rig counts reaching decade lows, during the second quarter of 2016. As a result of the sharp cutback in activity, production declined in certain areas of the world, global inventories began to decline and commodity prices started to rebound as oil markets began to re-balance. The market downturn began to stabilize during the second half of 2016 and showed early signs of improvement as the year ended. During 2017 and into the first quarter of 2018, land drilling in North America continued to increase, while international markets stabilized and offshore activity remained depressed. The average price of West Texas Intermediate Cushing Crude for the first quarter of 2018 was $62.88 a barrel.

Segment Performance

Wellbore Technologies

Wellbore Technologies generated revenues of $711 million in the first quarter of 2018, a decrease of one percent from the fourth quarter of 2017 and an increase of 28% from the first quarter of 2017. The sequential decrease in revenue was the result of a slow start to the year in the Eastern Hemisphere and a fall-off in drill pipe sales, partially offset by strong growth from the segment’s operations in the Western Hemisphere. Operating profit was $12 million, or 1.7 percent of sales. Adjusted EBITDA was $103 million, or 14.5 percent of sales, a decrease of 3.7 percent sequentially and an increase of $65 million from the prior year.

Completion & Production Solutions

Completion & Production Solutions generated revenues of $670 million, a decrease of three percent from the fourth quarter of 2017 and an increase of three percent from the first quarter of 2017. Customer deferred deliveries of well servicing and stimulation equipment as well as subsea flexible pipe negatively impacted first quarter revenue conversion. Operating profit was $16 million or 2.4 percent of sales. Adjusted EBITDA was $73 million, or 10.9 percent of sales, a decrease of one percent sequentially and a decrease of five percent from the prior year.

Backlog for capital equipment orders for Completion & Production Solutions at March 31, 2018 was $1.01 billion. New orders during the quarter were $324 million, representing a book-to-bill of 84 percent when compared to the $384 million of orders shipped from backlog. The order book included a sizeable order of corrosion-proof fiberglass pipe for a salt-water gathering system and improved bookings for coiled tubing units and pressure pumping equipment.

Rig Technologies

Rig Technologies generated revenues of $483 million, a decrease of 21 percent from the fourth quarter of 2017 and a decrease of 17 percent from the first quarter of 2017. The segment was adversely affected by reduced progress on new offshore rig construction, deferring revenue out of backlog to subsequent quarters. While service and repair contributions were down sequentially, as customers finalized annual budgets, spares revenue continued its recent upward trajectory. Operating profit was $18 million, or 3.7 percent of sales. Adjusted EBITDA was $45 million, or 9.3 percent of sales, a decrease of 36 percent sequentially and a decrease of four percent from the prior year.

Backlog for capital equipment orders for Rig Technologies at March 31, 2018 was $2.05 billion. New orders booked during the quarter, which included two land rig packages and several land rig equipment upgrades, totaled $201 million.

Outlook

Activity in North America increased sharply off historical lows during the last two quarters of 2016 and through 2017. Declines in supply appear to have rebalanced the market; however, commodity prices and global activity levels remain relatively low and challenging conditions persist offshore. Consequently, the Company anticipates that its customers will continue to moderate capital expenditures to the extent they remain uncertain of a sustainable recovery in commodity prices.

While North America land drilling has increased, activity levels remain well below prior cyclical highs. International activity, which has been slower to fall than North American activity, may have reached the bottom of its cycle during 2017, though strong signs of recovery are not yet apparent. Offshore activity, which has longer project cycle times and, in certain instances, more challenged economics, may continue to decline for the remainder of 2018.

Low activity levels result in an oversupply of service capacity and capital equipment, creating challenging prospects for many of NOV’s customers and reducing demand for the Company’s products. In this environment, contractors have been hesitant to invest in their existing equipment to conserve as much capital as possible. Equipment has been neglected and idle fleets have been stripped of parts to sustain assets that remain active. Additionally, certain equipment becomes less desirable and obsolete as equipment manufacturers develop new technologies and produce more efficient equipment that improves efficiencies and lowers the marginal cost of supply for oil and gas operating companies. The Company believes that the sharp spending reductions its customers have had in place for an extended period have created pent up demand for NOV’s products that began to show in certain areas during the second half of 2017 as industry activity levels began to improve. Demand slowed during the first quarter of 2018 as protracted customer budgeting cycles deferred deliveries to the second quarter.

NOV’s global customer base includes national oil companies, international oil companies, independent oil and gas companies, onshore and offshore service companies and others whose strategies and reactions to low commodity prices vary. Likewise, the Company expects the timing and slope of revenue stabilization and recovery will be different across its operating regions and its three business segments. NOV’s Wellbore Technologies segment and certain elements of its Completion & Production Solutions and Rig Technologies segments are realizing a faster recovery as drilling of new wells increases, while a strong recovery for the more capital equipment oriented businesses are expected to come later in the cycle.

NOV will continue to adjust the size of its operations to fit anticipated levels of activity while investing in developing and acquiring new products, technologies and operations that advance the Company’s longer term strategic goals. NOV has a history of implementing cost-control measures and downsizing in response to depressed market conditions as well as cost effectively ramping operations to capitalize on rapidly increasing demand. The Company has closed, or is in the process of closing, 408 locations over the past three years. It has reduced its annual expenses relating to salaries, wages, outside services, contractors, travel and entertainment by approximately $3.0 billion. The Company remains optimistic regarding longer-term market fundamentals as existing oil and gas fields continue to deplete and numerous major projects to replenish supply have been deferred or canceled while global demand continues to grow.

Though the Company benefited from a high concentration of orders for offshore drilling equipment and services in the preceding years, significant contraction in the offshore market during the recent downturn adversely effected the Company’s performance. Offshore market dynamics and equipment oversupply are expected to cause slower recovery there than in our land business, however, it is in NOV’s strategic interest to maintain a leading position in offshore drilling equipment. The Company has intentionally and successfully pivoted towards onshore and non-drilling related activities in recent years, highly responsive to the industry’s increased focus on onshore unconventional developments. Approximately 65% of consolidated revenues were derived from onshore businesses in 2017, compared to approximately 40% in 2014.

NOV expects unconventional shale resources to continue to gain a greater share of global production, and the Company will continue to enhance its offering into unconventional resource focused products and technologies, including advanced, automated drilling rigs; premium drillpipe and directional drilling technologies; hydraulic fracture stimulation equipment; and multistage completion tools. NOV expects big data and predictive analytics to improve uptime and operating efficiency, and the Company remains at the forefront of applying this promising technology to oilfield drilling and completion equipment. NOV expects the oil and gas industry to adopt more efficient supply chain practices that the Company is pioneering to construct floating production facilities to produce the immense resources discovered offshore. The Company has used the recent downturn to vigorously advance these strategic initiatives, and is encouraged by its progress.

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 2018 and 2017, and the fourth quarter of 2017 include the following:


	1Q18*		1Q17*		4Q17*		% 1Q18 1Q17			% 1Q18 4Q17
Active Drilling Rigs:
U.S.		965		739		921		30.6	%		4.8	%
Canada		273		299		205		(8.7	%)		33.2	%
International		970		939		948		3.3	%		2.3	%

Worldwide		2,208		1,977		2,074		11.7	%		6.5	%
West Texas Intermediate Crude Prices (per barrel)	$	62.88	$	51.77	$	55.37		21.5	%		13.6	%
Natural Gas Prices ($/mmbtu)	$	3.04	$	2.98	$	2.89		2.0	%		5.2	%

*	Averages for the quarters indicated. See sources below.

The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Crude Oil prices for the past nine quarters ended March 31, 2018, on a quarterly basis:

LOGO

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

The worldwide quarterly average rig count increased 6.5% (from 2,074 to 2,208), and the U.S. increased 4.8% (from 921 to 965), in the first quarter of 2018 compared to the fourth quarter of 2017. The average per barrel price of West Texas Intermediate Crude Oil increased 13.6% (from $55.37 per barrel to $62.88 per barrel) and natural gas prices increased 5.2% (from $2.89 per mmbtu to $3.04 per mmbtu) in the first quarter of 2018 compared to the fourth quarter of 2017.

U.S. rig activity at April 20, 2018 was 1,013 rigs, increasing 5% compared to the first quarter of 2018 average of 965 rigs. The price for West Texas Intermediate Crude Oil was at $68.38 per barrel at April 20, 2018, increasing 9% from the first quarter of 2018 average. The price for natural gas was at $2.74 per mmbtu at April 20, 2018, decreasing 10% from the first quarter of 2018 average.

Results of Operations

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


	Three Months Ended March 31,
	2018			2017
Revenue:
Wellbore Technologies	$	711		$	555
Completion & Production Solutions		670			648
Rig Technologies		483			582
Eliminations		(69	)		(44	)

Total revenue	$	1,795		$	1,741

Operating profit (loss):
Wellbore Technologies	$	12		$	(57	)
Completion & Production Solutions		16			8
Rig Technologies		18			13
Eliminations and corporate costs		(47	)		(61	)

Total operating profit (loss)	$	(1	)	$	(97	)

Operating profit (loss)%:
Wellbore Technologies		1.7	%		(10.3	%)
Completion & Production Solutions		2.4	%		1.2	%
Rig Technologies		3.7	%		2.2	%
Total operating profit (loss) %		(0.1	%)		(5.6	%)

Wellbore Technologies

Three months ended March 31, 2018 and 2017. Revenue from Wellbore Technologies was $711 million for the three months ended March 31, 2018, compared to $555 million for the three months ended March 31, 2017, an increase of $156 million or 28%. This increase was due to the strong U.S. recovery.

Operating profit (loss) from Wellbore Technologies was $12 million for the three months ended March 31, 2018 compared to $(57) million for the three months ended March 31, 2017, an increase of $69 million. Operating profit (loss) percentage increased to 1.7% for the three months ended March 31, 2018, from (10.3)% in the three months ended March 31, 2017. This increase was primarily due to the strong U.S. recovery.

Completion & Production Solutions

Three months ended March 31, 2018 and 2017. Revenue from Completion & Production Solutions was $670 million for the three months ended March 31, 2018, compared to $648 million for the three months ended March 31, 2017, an increase of $22 million or 3%. This increase was due to the overall increase in demand for capital equipment used in completion and production related activities.

Operating profit from Completion & Production Solutions was $16 million for the three months ended March 31, 2018 compared to $8 million for the three months ended March 31, 2017, an increase of $8 million or 100%. Operating profit percentage increased to 2.4% for the three months ended March 31, 2018, from 1.2% in the three months ended March 31, 2017. This increase was due to an overall increase in market activity.

The Completion & Productions Solutions 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 completion and production components or a signed contract related to a construction project. The capital equipment backlog was $1,010 million at March 31, 2018, an increase of $259 million, or 34% from backlog of $751 million at March 31, 2017. Numerous factors may affect the timing of revenue out of backlog. Considering these factors, the Company reasonably expects approximately $880 million of revenue out of backlog for the remainder of 2018 and approximately $130 million of revenue out of backlog in 2019 and thereafter. At March 31, 2018, approximately 54% of the capital equipment backlog was for offshore products and approximately 72% of the capital equipment backlog was destined for international markets.

Rig Technologies

Three months ended March 31, 2018 and 2017. Revenue from Rig Technologies was $483 million for the three months ended March 31, 2018, compared to $582 million for the three months ended March 31, 2017, a decrease of $99 million or 17%. This decrease was due to a declining backlog and challenging market conditions for the Company’s offshore contract drilling customer base.

Operating profit from Rig Technologies was $18 million for the three months ended March 31, 2018 compared to $13 million for the three months ended March 31, 2017, an increase of $5 million or 38%. Operating profit percentage increased to 3.7% for the three months ended March 31, 2018, from 2.2% in the three months ended March 31, 2017. Operating profit percentage increased due to product mix.

The Rig Technologies 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 $2.05 billion at March 31, 2018, a decrease of $275 million, or 12%, from backlog of $2.32 billion at March 31, 2017. Numerous factors may affect the timing of revenue out of backlog. Considering these factors, the Company reasonably expects approximately $750 million of revenue out of backlog for the remainder of 2018 and approximately $1.30 billion of revenue out of backlog in 2019 and thereafter. At March 31, 2018, approximately 77% of the capital equipment backlog was for offshore products and approximately 80% of the capital equipment backlog was destined for international markets.

Eliminations and corporate costs

Eliminations and corporate costs were $47 million and $61 million for the three months ended March 31, 2018 and 2017, respectively. This change is primarily due to the change in intersegment eliminations. Sales from one segment to another generally are priced at estimated equivalent commercial selling prices; however, segments originating an external sale are credited with the full profit to the company. Eliminations include intercompany transactions conducted between the three reporting segments that are eliminated in consolidation. Intercompany transactions within each reporting segment are eliminated within each reporting segment.

Other income (expense), net

Other income (expense), net were expenses of $(47) million and $(15) million for the three months ended March 31, 2018 and 2017, respectively. The change in expense was primarily due to the fluctuations in foreign currencies.

Provision for income taxes

Non-GAAP Financial Measures and Reconciliations

The Company discloses Adjusted EBITDA (defined as Operating Profit excluding Depreciation, Amortization and Other Items) in its periodic earnings press releases and other public disclosures to provide investors additional information about the results of ongoing operations. The Company uses Adjusted EBITDA internally to evaluate and manage the business. Adjusted EBITDA is not intended to replace GAAP financial measures, such as Net Income. Other items in 2018 consisted primarily of the reversal of certain accruals, partially offset by restructure charges and severance payments. Other items in 2017 consisted primarily of restructure charges for inventory write-downs, facility closures and severance payments.

The following tables set forth the reconciliation of Adjusted EBITDA to its most comparable GAAP financial measure (in millions):


	Three Months Ended
	March 31,						December 31,
	2018			2017			2017
Operating profit (loss):
Wellbore Technologies	$	12		$	(57	)	$	(21	)
Completion & Production Solutions		16			8			19
Rig Technologies		18			13			(51	)
Eliminations and corporate costs		(47	)		(61	)		(58	)

Total operating profit (loss)	$	(1	)	$	(97	)	$	(111	)

Other items:
Wellbore Technologies	$	(3	)	$	—		$	32
Completion & Production Solutions		3			15			1
Rig Technologies		6			12			100
Eliminations and corporate costs		(18	)		—			—

Total other items	$	(12	)	$	27		$	133

Depreciation & amortization:
Wellbore Technologies	$	94		$	95		$	96
Completion & Production Solutions		54			54			54
Rig Technologies		21			22			21
Eliminations and corporate costs		4			4			4

Total depreciation & amortization	$	173		$	175		$	175

Adjusted EBITDA:
Wellbore Technologies	$	103		$	38		$	107
Completion & Production Solutions		73			77			74
Rig Technologies		45			47			70
Eliminations and corporate costs		(61	)		(57	)		(54	)

Total Adjusted EBITDA	$	160		$	105		$	197

Reconciliation of Adjusted EBITDA:
GAAP net loss attributable to Company	$	(68	)	$	(122	)	$	(14	)
Net income (loss) attributable to noncontrolling interest		2			2			(1	)
Provision for income taxes		3			(13	)		(123	)
Interest expense		24			25			25
Interest income		(7	)		(4	)		(6	)
Equity (income) loss in unconsolidated affiliates		(2	)		—			1
Other (income) expense, net		47			15			7
Depreciation & amortization		173			175			175
Other items in operating profit		(12	)		27			133

Total Adjusted EBITDA:	$	160		$	105		$	197

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 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, 2018, the Company had cash and cash equivalents of $1,236 million and total debt of $2,713 million. At December 31, 2017, cash and cash equivalents were $1,437 million and total debt was $2,712 million. As of March 31, 2018, approximately $971 million of the $1,236 million of cash and cash equivalents was held by our foreign subsidiaries and the earnings associated with this cash were subject to U.S. taxation under the Act defined in Note 8 to the Consolidated Financial Statements. If opportunities to invest in the U.S. are greater than available cash balances that are not subject to income tax, rather than repatriating cash, the Company may choose to borrow against its revolving credit facility or utilize its commercial paper program.

The Company’s outstanding debt at March 31, 2018 was $2,713 million and consisted of $1,393 million in 2.60% Senior Notes, $1,088 million in 3.95% Senior Notes, and other debt of $232 million. The Company was in compliance with all covenants at March 31, 2018.

At March 31, 2018, there were no commercial paper borrowings supported by the $3.0 billion credit facility and no outstanding letters of credit issued under the credit facility, resulting in $3.0 billion of funds available under this credit facility.

The Company had $567 million of outstanding letters of credit at March 31, 2018 that are under various bilateral letter of credit facilities. Letters of credit are issued as bid bonds, advanced payment bonds and performance bonds.

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


	Three Months Ended March 31,
	2018			2017
Net cash provided (used) by operating activities	$	(129	)	$	111
Net cash used in investing activities		(61	)		(42	)
Net cash used in financing activities		(18	)		(13	)

Operating Activities

For the first three months of 2018, cash provided (used) by operating activities was $(129) million compared to $111 million in the same period of 2017. Before changes in operating assets and liabilities, net of acquisitions, cash was used by operations primarily through a $66 million loss from operations plus non-cash charges of $195 million.

The change in cash used in the first three months of 2018 compared to the same period in 2017 was primarily due to increases in accounts receivable and inventory and a decrease in accrued liabilities, partially offset by increases in accounts payable and contract liabilities. Net changes in operating assets and liabilities, net of acquisitions, used $258 million of cash for the first three months of 2018 compared to cash used of $3 million in the same period in 2017.

Investing Activities

For the first three months of 2018, net cash used in investing activities was $61 million compared to $42 million for the same period of 2017. Net cash used in investing activities was primarily the result of capital expenditures and acquisition activity. The Company used $36 million during the first three months of 2018 for acquisitions compared to $6 million for the same period of 2017 and $39 million for capital expenditures in the first three months of 2018 compared to $42 million for the same period of 2017.

Financing Activities

For the first three months of 2018, net cash used in financing activities was $18 million compared to $13 million for the same period of 2017. This decrease was primarily the result of activity under stock incentive plans providing $3 million of cash in 2018 compared to $9 million in 2017. Dividends paid were $19 million for each of the first three months of 2018 and 2017, respectively.

Other

The effect of the change in exchange rates on cash flows was an increase of $7 million and $15 million for the first three months of 2018 and 2017, respectively.

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

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

New Accounting Pronouncements

Recently Adopted Accounting Standards

Recently Issued Accounting Standards

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, 2017, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. We recorded a foreign exchange loss in our income statement of approximately $22 million in the first three months of 2018, compared to approximately $1 million in foreign exchange gain 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. Currency exchange rate fluctuations may create losses in future periods to the extent we maintain net monetary 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 forward contracts grouped by functional currency and their expected maturity periods (in millions, except contract rates):


	As of March 31, 2018											December 31, 2017
Functional Currency	2018			2019			2020		Total			December 31, 2017
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		40			35			—		75			75
Average USD to CAD contract rate		1.3286			1.3242			—		1.3265			1.3265
Fair Value at March 31, 2018 in U.S. dollars		(1	)		(1	)		—		(2	)		(3	)
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		19			24			141		184			216
Average USD to CAD contract rate		1.2865			1.3167			1.3147		1.3119			1.3075
Fair Value at March 31, 2018 in U.S. dollars		—			1			3		4			7
EUR Buy GBP/Sell EUR:
Notional amount to buy (in Euros)		—			—			—		—			—
Average GBP to EUR contract rate		—			1.1273			—		—			1.1459
Fair Value at March 31, 2018 in U.S. dollars		—			—			—		—			—
Buy USD/Sell EUR:
Notional amount to buy (in Euros)		3			—			—		3			10
Average USD to EUR contract rate		0.7983			—			—		0.7983			0.8565
Fair Value at March 31, 2018 in U.S. dollars		—			—			—		—			—
Buy ZAR/Sell EUR:
Notional amount to buy (in Euros)		2			—			—		2			10
Average ZAR to EUR contract rate		0.0619			—			—		0.0619			0.8565
Fair Value at March 31, 2018 in U.S. dollars		—			—			—		—			—
Sell USD/Buy EUR:
Notional amount to sell (in Euros)		93			—			—		93			105
Average USD to EUR contract rate		0.8062			—			—		0.8062			0.8429
Fair Value at March 31, 2018 in U.S. dollars		—			—			—		—			2
Sell ZAR/Buy EUR:
Notional amount to sell (in Euros)		9			—			—		9			9
Average ZAR to EUR contract rate		0.0619			—			—		0.0619			0.0619
Fair Value at March 31, 2018 in U.S. dollars		(1	)		—			—		(1	)		—


	As of March 31, 2018										December 31, 2017
Functional Currency	2018			2019		2020		Total			December 31, 2017
AUD Buy USD/Sell AUD:
Notional amount to buy (in Australian dollars)		1			—		—		1			2
Average USD to AUD contract rate		1.2906			—		—		1.2906			1.3152
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell USD/Buy AUD:
Notional amount to sell (in Australian dollars)		3			—		—		3			5
Average USD to AUD contract rate		1.2790			—		—		1.2790			1.3324
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		—			—		—		—			—
Average USD to GBP contract rate		—			—		—		—			0.7855
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell USD/Buy GBP:
Notional amount to sell (in British Pounds Sterling)		141			—		—		141			156
Average USD to GBP contract rate		0.7041			—		—		0.7041			0.7438
Fair Value at March 31, 2018 in U.S. dollars		(2	)		—		—		(2	)		1
USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		5			—		—		5			5
Average DKK to USD contract rate		0.1605			—		—		0.1605			0.1483
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		61			2		—		63			58
Average EUR to USD contract rate		1.2217			1.2740		—		1.2231			1.1604
Fair Value at March 31, 2018 in U.S. dollars		1			—		—		1			2
Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		4			—		—		4			4
Average GBP to USD contract rate		1.3130			1.4430		—		1.3195			1.2934
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		331			199		1		531			615
Average NOK to USD contract rate		0.1211			0.1218		0.1317		0.1214			0.1207
Fair Value at March 31, 2018 in U.S. dollars		20			13		—		33			11
Sell DKK/Buy USD:
Notional amount to sell (in U.S. dollars)		3			—		—		3			2
Average DKK to USD contract rate		0.1622			—		—		0.1622			0.1606
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		77			—		—		77			86
Average EUR to USD contract rate		1.2272			—		—		1.2272			1.1755
Fair Value at March 31, 2018 in U.S. dollars		(1	)		—		—		(1	)		(2	)
Sell GBP/Buy USD:
Notional amount to sell (in U.S. dollars)		2			—		—		2			1
Average GBP to USD contract rate		1.3707			—		—		1.3707			1.3340
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		67			5		3		75			81
Average NOK to USD contract rate		0.1285			0.1305		0.1313		0.1288			0.1260
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			2
Sell RUB/Buy USD:
Notional amount to sell (in U.S. dollars)		50			—		—		50			45
Average RUB to USD contract rate		0.0172			—		—		0.0172			0.0167
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			(1	)


	As of March 31, 2018										December 31,
Functional Currency	2018			2019		2020		Total			2017
BRL Buy EUR/Sell BRL:
Notional amount to buy (in Brazilian reals)		80			—		—		80			138
Average EUR to BRL contract rate		4.0075			—		—		4.0075			3.8793
Fair Value at March 31, 2018 in U.S. dollars		1			—		—		1			2
Buy GBP/Sell BRL:
Notional amount to buy (in Brazilian reals)		27			—		—		27			38
Average GBP to BRL contract rate		4.4026			—		—		4.4026			4.3752
Fair Value at March 31, 2018 in U.S. dollars		1			—		—		1			1
Buy USD/Sell BRL:
Notional amount to buy (in Brazilian reals)		36			—		—		36			43
Average USD to BRL contract rate		3.2902			—		—		3.2902			3.2805
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell EUR/Buy BRL:
Notional amount to sell (in Brazilian reals)		143			—		—		143			125
Average EUR to BRL contract rate		4.0345			—		—		4.0345			3.9985
Fair Value at March 31, 2018 in U.S. dollars		(1	)		—		—		(1	)		(1	)
Sell USD/Buy BRL:
Notional amount to sell (in Brazilian reals)		102			—		—		102			—
Average USD to BRL contract rate		3.3170			—		—		3.3170			—
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
DKK Buy USD/Sell DKK:
Notional amount to buy (in Danish Krone)		17			—		—		17			—
Average USD to DKK contract rate		5.9953			—		—		6			—
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell USD/Buy DKK:
Notional amount to sell (in Danish Krone)		8			—		—		8			219
Average USD to DKK contract rate		5.9952			—		—		5.9952			6.3500
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			1
NOK Buy EUR/Sell NOK:
Notional amount to buy (in Norwegian Kroner)		69			13		—		82			114
Average EUR to NOK contract rate		9.6416			9.8534		—		9.6740			9.8269
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Buy GBP/Sell NOK:
Notional amount to buy (in Norwegian Kroner)		9			8		—		17			18
Average GBP to NOK contract rate		11.0306			11.0470		—		11.0386			11.0468
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Buy USD/Sell NOK:
Notional amount to buy (in Norwegian Kroner)		6			5		—		11			8
Average USD to NOK contract rate		7.8498			8		—		7.8239			8.3188
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Buy JPY/Sell NOK:
Notional amount to buy (in Norwegian Kroner)		38			—		—		38			40
Average JPY to NOK contract rate		0.0727			—		—		0.0727			0.0740
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell EUR/Buy NOK:
Notional amount to sell (in Norwegian Kroner)		103			12		—		115			152
Average EUR to NOK contract rate		9.6569			9.8952		—		9.6815			9.7832
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell USD/Buy NOK:
Notional amount to sell (in Norwegian Kroner)		27			—		—		27			44
Average USD to NOK contract rate		7.7263			—		—		7.7263			8.3339
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—
Sell JPY/Buy NOK:
Notional amount to sell (in Norwegian Kroner)		32			—		—		32			33
Average JPY to NOK contract rate		0.0727			—		—		0.0727			0.0743
Fair Value at March 31, 2018 in U.S. dollars		—			—		—		—			—

Other Currencies
Fair Value at March 31, 2018 in U.S. dollars		—			—				—			—

Total Fair Value at March 31, 2018 in U.S. dollars		17			13		3		33			22

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $73 million and translation exposures totaling $173 million as of March 31, 2018 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 $5 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $17 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, 2018, long term borrowings consisted $1,393 million in 2.60% Senior Notes and $1,088 million in 3.95% Senior Notes. At March 31, 2018, there were no commercial paper borrowings and no outstanding letters of credit issued under the credit facility, resulting in $3.0 billion of funds available under this credit facility. 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 CDOR, or at the U.S. prime 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 CDOR 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.

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.

PART II—OTHER INFORMATION

Item 1A. Risk

Factors

As of the date of this filing, the Company and its operations continue to be subject to the risk factors previously disclosed in Part I, Item 1A “Risk Factors” in our 2017 Annual Report on Form 10-K.

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 42.

INDEX TO EXHIBITS

(a)

Exhibits



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) (2)

10.1		Credit Agreement, dated as of June 27, 2017, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in its capacity, among others, as Administrative Agent, Co-Lead Arranger and Joint Book Runner. (Exhibit 10.1) (3)

10.2		National Oilwell Varco Long-Term Incentive Plan, as amended and restated. (4)*

10.3		Form of Employee Stock Option Agreement. (Exhibit 10.1) (5)

10.4		Form of Non-Employee Director Stock Option Agreement. (Exhibit 10.2) (5)

10.5		Form of Performance-Based Restricted Stock. (18 Month) Agreement (Exhibit 10.1) (6)

10.6		Form of Performance-Based Restricted Stock. (36 Month) Agreement (Exhibit 10.2) (6)

10.7		Form of Performance Award Agreement (Exhibit 10.1) (7)

10.8		Form of Executive Employment Agreement. (Exhibit 10.1) (8)

10.9		Form of Executive Severance Agreement. (Exhibit 10.2) (8)

10.10		Form of Employee Nonqualified Stock Option Grant Agreement (9)

10.11		Form of Restricted Stock Agreement (9)

10.12		Form of Performance Award Agreement (9)

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, 2018 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. (10)
* 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 Current Report on Form 8-K filed on August 17, 2011.
(3)		Filed as an Exhibit to our Current Report on Form 8-K filed on June 28, 2017
(4)		Filed as Appendix I to our Proxy Statement filed on April 11, 2016.
(5)		Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006.



(6)		Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007.
(7)		Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2013.
(8)		Filed as an Exhibit to our Current Report on Form 8-K filed on November 24, 2014.
(9)		Filed as an Exhibit to our Current Report on Form 8-K filed on February 26, 2016.
(10)		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.

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.