10-Q 1 d753467d10q.htm 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2014

OR

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

Commission File Number 1-12317

NATIONAL OILWELL VARCO, INC.

(Exact name of registrant as specified in its charter)

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

7909 Parkwood Circle Drive

Houston, Texas

77036-6565

(Address of principal executive offices)

(713) 346-7500

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer |  | x |  | Accelerated filer |  | ¨
Non-accelerated filer |  | ¨ (Do not check if a smaller reporting company) |  | Smaller reporting company |  | ¨

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

As of July 31, 2014 the registrant had 430,238,649 shares of common stock, par value $.01 per share, outstanding.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

|  | June 30, 2014 |  |  | December 31, 2013 |
|  | (Unaudited) |  |  |  |
ASSETS |  |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 3,885 |  |  | $ | 3,436 |
Receivables, net |  |  | 4,427 |  |  |  | 4,896 |
Inventories, net |  |  | 5,198 |  |  |  | 5,603 |
Costs in excess of billings |  |  | 1,567 |  |  |  | 1,539 |
Deferred income taxes |  |  | 331 |  |  |  | 373 |
Prepaid and other current assets |  |  | 595 |  |  |  | 576 |
Total current assets |  |  | 16,003 |  |  |  | 16,423 |
Property, plant and equipment, net |  |  | 3,440 |  |  |  | 3,408 |
Deferred income taxes |  |  | 472 |  |  |  | 372 |
Goodwill |  |  | 8,640 |  |  |  | 9,049 |
Intangibles, net |  |  | 4,808 |  |  |  | 5,055 |
Investment in unconsolidated affiliates |  |  | 351 |  |  |  | 390 |
Other assets |  |  | 113 |  |  |  | 115 |
Total assets |  | $ | 33,827 |  |  | $ | 34,812 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |
Accounts payable |  | $ | 1,178 |  |  | $ | 1,275 |
Accrued liabilities |  |  | 2,857 |  |  |  | 2,763 |
Billings in excess of costs |  |  | 2,176 |  |  |  | 1,771 |
Current portion of long-term debt and short-term borrowings |  |  | — |  |  |  | 1 |
Accrued income taxes |  |  | 260 |  |  |  | 556 |
Deferred income taxes |  |  | 444 |  |  |  | 312 |
Total current liabilities |  |  | 6,915 |  |  |  | 6,678 |
Long-term debt |  |  | 3,148 |  |  |  | 3,149 |
Deferred income taxes |  |  | 2,002 |  |  |  | 2,292 |
Other liabilities |  |  | 344 |  |  |  | 363 |
Total liabilities |  |  | 12,409 |  |  |  | 12,482 |
Commitments and contingencies |  |  |  |  |  |  |  |
Stockholders’ equity: |  |  |  |  |  |  |  |
Common stock - par value $.01; 1 billion shares authorized; 429,458,195 and 428,433,703 shares issued and outstanding at June 30, 2014 and December 31, 2013 |  |  | 4 |  |  |  | 4 |
Additional paid-in capital |  |  | 8,999 |  |  |  | 8,907 |
Accumulated other comprehensive income (loss) |  |  | 48 |  |  |  | (4 | )
Retained earnings |  |  | 12,281 |  |  |  | 13,323 |
Total Company stockholders’ equity |  |  | 21,332 |  |  |  | 22,230 |
Noncontrolling interests |  |  | 86 |  |  |  | 100 |
Total stockholders’ equity |  |  | 21,418 |  |  |  | 22,330 |
Total liabilities and stockholders’ equity |  | $ | 33,827 |  |  | $ | 34,812 |

See notes to unaudited consolidated financial statements.

2

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(In millions, except per share data)

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Revenue |  | $ | 5,255 |  |  | $ | 4,680 |  |  | $ | 10,144 |  |  | $ | 9,056 |
Cost of revenue |  |  | 3,800 |  |  |  | 3,507 |  |  |  | 7,404 |  |  |  | 6,717 |
Gross profit |  |  | 1,455 |  |  |  | 1,173 |  |  |  | 2,740 |  |  |  | 2,339 |
Selling, general and administrative |  |  | 542 |  |  |  | 460 |  |  |  | 1,028 |  |  |  | 933 |
Operating profit |  |  | 913 |  |  |  | 713 |  |  |  | 1,712 |  |  |  | 1,406 |
Interest and financial costs |  |  | (27 | ) |  |  | (30 | ) |  |  | (53 | ) |  |  | (58 | )
Interest income |  |  | 5 |  |  |  | 3 |  |  |  | 9 |  |  |  | 6 |
Equity income in unconsolidated affiliates |  |  | 23 |  |  |  | 15 |  |  |  | 33 |  |  |  | 34 |
Other income (expense), net |  |  | (21 | ) |  |  | 11 |  |  |  | (21 | ) |  |  | (12 | )
Income from continuing operations before income taxes |  |  | 893 |  |  |  | 712 |  |  |  | 1,680 |  |  |  | 1,376 |
Provision for income taxes |  |  | 284 |  |  |  | 218 |  |  |  | 523 |  |  |  | 423 |
Income from continuing operations |  |  | 609 |  |  |  | 494 |  |  |  | 1,157 |  |  |  | 953 |
Income from discontinued operations |  |  | 11 |  |  |  | 37 |  |  |  | 52 |  |  |  | 78 |
Net income |  |  | 620 |  |  |  | 531 |  |  |  | 1,209 |  |  |  | 1,031 |
Net income (loss) attributable to noncontrolling interests |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | (2 | )
Net income attributable to Company |  | $ | 619 |  |  | $ | 531 |  |  | $ | 1,208 |  |  | $ | 1,033 |
Per share data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations |  | $ | 1.42 |  |  | $ | 1.16 |  |  | $ | 2.70 |  |  | $ | 2.24 |
Income from discontinued operations |  | $ | 0.03 |  |  | $ | 0.09 |  |  | $ | 0.12 |  |  | $ | 0.18 |
Net income attributable to Company |  | $ | 1.45 |  |  | $ | 1.25 |  |  | $ | 2.82 |  |  | $ | 2.42 |
Diluted: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations |  | $ | 1.42 |  |  | $ | 1.15 |  |  | $ | 2.69 |  |  | $ | 2.23 |
Income from discontinued operations |  | $ | 0.02 |  |  | $ | 0.09 |  |  | $ | 0.12 |  |  | $ | 0.18 |
Net income attributable to Company |  | $ | 1.44 |  |  | $ | 1.24 |  |  | $ | 2.81 |  |  | $ | 2.41 |
Cash dividends per share |  | $ | 0.46 |  |  | $ | 0.26 |  |  | $ | 0.72 |  |  | $ | 0.39 |
Weighted average shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 428 |  |  |  | 426 |  |  |  | 428 |  |  |  | 426 |
Diluted |  |  | 430 |  |  |  | 428 |  |  |  | 430 |  |  |  | 428 |

See notes to unaudited consolidated financial statements.

3

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(In millions)

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Net income |  | $ | 620 |  |  | $ | 531 |  |  | $ | 1,209 |  |  | $ | 1,031 |
Currency translation adjustments |  |  | 114 |  |  |  | (121 | ) |  |  | 63 |  |  |  | (238 | )
Changes in derivative financial instruments, net of tax |  |  | (25 | ) |  |  | (22 | ) |  |  | (11 | ) |  |  | (70 | )
Comprehensive income |  |  | 709 |  |  |  | 388 |  |  |  | 1,261 |  |  |  | 723 |
Comprehensive income (loss) attributable to noncontrolling interest |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | (2 | )
Comprehensive income attributable to Company |  | $ | 708 |  |  | $ | 388 |  |  | $ | 1,260 |  |  | $ | 725 |

See notes to unaudited consolidated financial statements.

4

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In millions)

|  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |
Cash flows from operating activities: |  |  |  |
Income from continuing operations |  |  | 1,157 |  |  | $ | 953 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 381 |  |  |  | 356 |
Deferred income taxes |  |  | (57 | ) |  |  | (116 | )
Equity income in unconsolidated affiliates |  |  | (33 | ) |  |  | (34 | )
Dividend from unconsolidated affiliate |  |  | 73 |  |  |  | 66 |
Other, net |  |  | 127 |  |  |  | 29 |
Change in operating assets and liabilities, net of acquisitions: |  |  |  |  |  |  |  |
Receivables |  |  | (123 | ) |  |  | (4 | )
Inventories |  |  | (516 | ) |  |  | (54 | )
Costs in excess of billings |  |  | (28 | ) |  |  | (222 | )
Prepaid and other current assets |  |  | (48 | ) |  |  | 32 |
Accounts payable |  |  | 101 |  |  |  | (47 | )
Billings in excess of costs |  |  | 405 |  |  |  | (30 | )
Income taxes payable |  |  | (295 | ) |  |  | (99 | )
Other assets/liabilities, net |  |  | 126 |  |  |  | (91 | )
Net cash provided by continuing operating activities |  |  | 1,270 |  |  |  | 739 |
Discontinued operations |  |  | 89 |  |  |  | 131 |
Net cash provided by operating activities |  |  | 1,359 |  |  |  | 870 |
Cash flows from investing activities: |  |  |  |  |  |  |  |
Purchases of property, plant and equipment |  |  | (300 | ) |  |  | (284 | )
Business acquisitions, net of cash acquired |  |  | (102 | ) |  |  | (2,390 | )
Cash distributed in spin-off |  |  | (253 | ) |  |  | — |
Other |  |  | 13 |  |  |  | 46 |
Net cash used in continuing investing activities |  |  | (642 | ) |  |  | (2,628 | )
Discontinued operations |  |  | (12 | ) |  |  | (36 | )
Net cash used in investing activities |  |  | (654 | ) |  |  | (2,664 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |
Borrowings against lines of credit and other debt |  |  | 151 |  |  |  | 1,556 |
Repayments on debt |  |  | (151 | ) |  |  | (586 | )
Cash dividends paid |  |  | (309 | ) |  |  | (167 | )
Proceeds from stock options exercised |  |  | 34 |  |  |  | 12 |
Other |  |  | 12 |  |  |  | 13 |
Net cash provided by (used in) continuing financing activities |  |  | (263 | ) |  |  | 828 |
Discontinued operations |  |  | — |  |  |  | — |
Net cash provided by (used in) financing activities |  |  | (263 | ) |  |  | 828 |
Effect of exchange rates on cash |  |  | 7 |  |  |  | (26 | )
Increase (decrease) in cash and cash equivalents |  |  | 449 |  |  |  | (992 | )
Cash and cash equivalents, beginning of period |  |  | 3,436 |  |  |  | 3,319 |
Cash and cash equivalents, end of period |  | $ | 3,885 |  |  | $ | 2,327 |
Supplemental disclosures of cash flow information: |  |  |  |  |  |  |  |
Cash payments during the period for: |  |  |  |  |  |  |  |
Interest |  | $ | 53 |  |  | $ | 57 |
Income taxes |  | $ | 886 |  |  | $ | 668 |

See notes to unaudited consolidated financial statements.

5

NATIONAL OILWELL VARCO, INC.

Notes to Consolidated Financial Statements (Unaudited)

1. | Basis of Presentation

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

The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (“NOV” or the “Company”) present information in accordance with GAAP in the United States for interim financial information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not include all information or footnotes required by GAAP in the United States for complete consolidated financial statements and should be read in conjunction with our 2013 Annual Report on Form 10-K.

In our opinion, the consolidated financial statements include all adjustments, which are of a normal recurring nature, unless otherwise disclosed, necessary for a fair presentation of the results for the interim periods. The results of operations for the three and six months ended June 30, 2014 are not necessarily indicative of the results to be expected for the full year.

On May 30, 2014, the Company completed the spin-off of its distribution business into an independent public company named NOW Inc. (“NOW”). As a result, the results of operations for our distribution business have been classified as discontinued operations for all periods presented. See Note 2 for additional information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

In conjunction with the spin-off of NOW Inc. the Company reviewed its reporting and management structure, and effective April 1, 2014, reorganized the Rig Technology, Petroleum Services & Supplies and remaining operations of Distribution & Transmission reporting segments into four new reporting segments. The new reporting segments are Rig Systems, Rig Aftermarket, Wellbore Technologies and Completion & Production Solutions.

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 8 for the fair value of long-term debt and Note 11 for the fair value of derivative financial instruments.

6

2. | Spin-off of Distribution Business

On May 30, 2014, the Company completed the previously announced spin-off (the “spin-off”) of its distribution business into an independent public company named NOW Inc., which trades on the New York Stock Exchange under the symbol “DNOW”. After the close of the New York Stock Exchange on May 30, 2014, the stockholders of record as of May 22, 2014 (the “Record Date”) received one share of NOW Inc. common stock for every four shares of NOV common stock held on the Record Date. No fractional shares of NOW Inc. common stock were distributed. Instead, the transfer agent aggregated any fractional shares into whole shares, sold those whole shares in the open market at prevailing rates and distributed the net cash proceeds, after deducting any taxes required to be withheld and any amount equal to all brokerage charges and commissions, pro rata to each holder who would otherwise have been entitled to receive fractional shares in the distribution.

In order to effect the spin-off and govern its relationship with NOW after the spin-off, the Company entered into a Separation and Distribution Agreement, a Tax Matters Agreement, an Employee Matters Agreement, a Transition Services Agreement, a Master Distributor Agreement, and a Master Services Agreement. The Separation and Distribution Agreement governs the terms of the separation of the distribution business from NOV’s other businesses. Generally, the Separation and Distribution Agreement includes agreements between NOW and NOV relating to the restructuring steps needed to be taken to complete the separation, including the assets, equity interests and rights to be transferred, liabilities to be assumed, contracts to be assigned and related matters. The Separation and Distribution Agreement also governs the treatment of aspects relating to indemnification, insurance, litigation responsibility, confidentiality, management, intellectual property (including trademarks) and cooperation.

The Tax Matters Agreement governs respective rights, responsibilities and obligations of NOV and NOW with respect to deficiencies and refunds, if any, of federal, state, local, and foreign taxes for periods before and after the distribution, as well as taxes attributable to the separation and distribution, and related matters such as the filing of tax returns and the conduct of IRS and other audits. In addition, the Tax Matters Agreement imposes certain restrictions on NOW and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the generally tax-free status of the separation and distribution.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees of NOV and NOW and generally allocates liabilities and responsibilities relating to employee compensation and benefit plans and programs. The Employee Matters Agreement provides for the treatment of outstanding NOV equity awards. The Employee Matters Agreement also sets forth the general principles relating to employee matters, including with respect to the assignment of employees and the transfer of employees from us to NOW, the assumption and retention of liabilities and related assets, expense reimbursements, workers’ compensation, leaves of absence, the provision of comparable benefits, employee service credits, the sharing of employee information and the duplication or acceleration of benefits.

The Transition Services Agreement sets forth the terms on which NOV will provide to NOW, and NOW will provide to NOV, on a temporary basis, certain services or functions that the companies historically have shared. Transition services may include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, legal support services, IT and network infrastructure systems and various other support and corporate services. The Transition Services Agreement provides for the provision of specified transition services generally for a period of up to 18 months.

The Master Distributor Agreement provides that NOW will act as a distributor of certain of NOV’s products. Under the Master Supply Agreement, NOW will supply products and provide solutions, including supply chain management solutions, to NOV.

7

The following table presents the carrying value of assets and liabilities of NOW, immediately preceding the spin-off, which are excluded from our consolidated balance sheet at June, 30, 2014 as a result of the spin-off on May 30, 2014 (in millions).

Current assets: |  |  |  |
Cash and cash equivalents |  | $ | 253 |
Receivables, net |  |  | 753 |
Inventories, net |  |  | 844 |
Deferred income taxes |  |  | 30 |
Prepaid and other current assets |  |  | 35 |
Total current assets of discontinued operations |  |  | 1,915 |
Property, plant and equipment, net |  |  | 115 |
Deferred income taxes |  |  | 15 |
Goodwill |  |  | 332 |
Intangibles, net |  |  | 67 |
Other assets |  |  | 2 |
Total assets of discontinued operations |  | $ | 2,446 |
Current liabilities: |  |  |  |
Accounts payable |  | $ | 384 |
Accrued liabilities |  |  | 90 |
Accrued income taxes |  |  | 5 |
Total current liabilities of discontinued operations |  |  | 479 |
Deferred income taxes |  |  | 17 |
Other liabilities |  |  | 9 |
Total liabilities of discontinued operations |  | $ | 505 |

Other items incurred as a result of the spin-off were $25 million and $34 million for the three and six months ended June 30, 2014 and are included in continuing operations. The following table presents selected financial information, as of May 30, 2014, regarding the results of operations of our distribution business, which is reported as discontinued operations (in millions):

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Revenue from discontinued operations |  | $ | 624 |  |  | $ | 1,070 |  |  | $ | 1,701 |  |  | $ | 2,142 |
Income from discontinued operations before income taxes |  |  | 21 |  |  |  | 58 |  |  |  | 83 |  |  |  | 118 |

Prior to the spin-off, sales to NOW were $91 million and $231 million for the three and six months ended June 30, 2014, respectively, and $116 million and $225 million for the three and six months ended June 30, 2013, respectively. Prior to the spin-off, purchases from NOW were $32 million and $82 million for the three and six months ended June 30, 2014, respectively and $32 million and $63 million for the three and six months ended June 30, 2013. Prior to May 30, 2014, the spin-off date, revenue and related cost of revenue were eliminated in consolidation between NOV and NOW. Beginning May 31, 2014, this revenue and cost of revenue represent third-party transactions with NOW.

8

3. | Inventories, net

Inventories consist of (in millions):

|  | June 30, 2014 |  |  | December 2013 |
Raw materials and supplies |  | $ | 1,267 |  |  | $ | 1,175 |
Work in process |  |  | 1,031 |  |  |  | 798 |
Finished goods and purchased products |  |  | 2,900 |  |  |  | 3,630 |
Total |  | $ | 5,198 |  |  | $ | 5,603 |

4. | Accrued Liabilities

Accrued liabilities consist of (in millions):

|  | June 30, 2014 |  |  | December 31, 2013 |
Customer prepayments and billings |  | $ | 808 |  |  | $ | 673 |
Accrued vendor costs |  |  | 538 |  |  |  | 531 |
Compensation |  |  | 419 |  |  |  | 516 |
Warranty |  |  | 267 |  |  |  | 228 |
Taxes (non-income) |  |  | 176 |  |  |  | 188 |
Insurance |  |  | 132 |  |  |  | 131 |
Accrued commissions |  |  | 96 |  |  |  | 97 |
Fair value of derivative financial instruments |  |  | 25 |  |  |  | 31 |
Interest |  |  | 11 |  |  |  | 11 |
Other |  |  | 385 |  |  |  | 357 |
Total |  | $ | 2,857 |  |  | $ | 2,763 |

Service and Product Warranties

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

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

Balance at December 31, 2013 |  | $ | 228 |
Net provisions for warranties issued during the year |  |  | 61 |
Amounts incurred |  |  | (26 | )
Currency translation adjustments and other |  |  | 4 |
Balance at June 30, 2014 |  | $ | 267 |

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5. | Costs and Estimated Earnings on Uncompleted Contracts

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

|  | June 30, 2014 |  |  | December 31, 2013 |
Costs incurred on uncompleted contracts |  | $ | 9,422 |  |  | $ | 7,608 |
Estimated earnings |  |  | 4,326 |  |  |  | 3,553 |
|  |  | 13,748 |  |  |  | 11,161 |
Less: Billings to date |  |  | 14,357 |  |  |  | 11,393 |
|  | $ | (609 | ) |  | $ | (232 | )
Costs and estimated earnings in excess of billings on uncompleted contracts |  | $ | 1,567 |  |  | $ | 1,539 |
Billings in excess of costs and estimated earnings on uncompleted contracts |  |  | (2,176 | ) |  |  | (1,771 | )
|  | $ | (609 | ) |  | $ | (232 | )

6. | Accumulated Other Comprehensive Income (Loss)

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

|  | Currency Translation Adjustments |  |  | Derivative Financial Instruments, Net of Tax |  |  | Defined Benefit Plans, Net of Tax |  |  | Total |
Balance at December 31, 2013 |  | $ | 17 |  |  | $ | 5 |  |  | $ | (26 | ) |  | $ | (4 | )
Accumulated other comprehensive income (loss) before reclassifications |  |  | 63 |  |  |  | 6 |  |  |  | — |  |  |  | 69 |
Amounts reclassified from accumulated other comprehensive income (loss) |  |  | — |  |  |  | (17 | ) |  |  | — |  |  |  | (17 | )
Balance at June 30, 2014 |  | $ | 80 |  |  | $ | (6 | ) |  | $ | (26 | ) |  | $ | 48 |

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

|  | Three Months Ended June 30, |
|  | 2014 |  |  | 2013 |
|  | Currency Translation Adjustments |  |  | Derivative Financial Instruments |  |  | Defined Benefit Plans |  |  | Total |  |  | Currency Translation Adjustments |  |  | Derivative Financial Instruments |  |  | Defined Benefit Plans |  |  | Total |
Revenue |  | $ | — |  |  | $ | (8 | ) |  | $ | — |  |  | $ | (17 | ) |  | $ | — |  |  | $ | (2 | ) |  | $ | — |  |  | $ | (2 | )
Cost of revenue |  |  | — |  |  |  | (4 | ) |  |  | — |  |  |  | (2 | ) |  |  | — |  |  |  | 4 |  |  |  | — |  |  |  | 4 |
Other income (expense), net |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (25 | ) |  |  | — |  |  |  | — |  |  |  | (25 | )
Tax effect |  |  | — |  |  |  | 2 |  |  |  | — |  |  |  | 4 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | $ | — |  |  | $ | (10 | ) |  | $ | — |  |  | $ | (15 | ) |  | $ | (25 | ) |  | $ | 2 |  |  | $ | — |  |  | $ | (23 | )

|  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |
|  | Currency Translation Adjustments |  |  | Derivative Financial Instruments |  |  | Defined Benefit Plans |  |  | Total |  |  | Currency Translation Adjustments |  |  | Derivative Financial Instruments |  |  | Defined Benefit Plans |  |  | Total |
Revenue |  | $ | — |  |  | $ | (21 | ) |  | $ | — |  |  | $ | (21 | ) |  | $ | — |  |  | $ | (4 | ) |  | $ | — |  |  | $ | (4 | )
Cost of revenue |  |  | — |  |  |  | (1 | ) |  |  | — |  |  |  | (1 | ) |  |  | — |  |  |  | 1 |  |  |  | — |  |  |  | 1 |
Other income (expense), net |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (25 | ) |  |  | — |  |  |  | — |  |  |  | (25 | )
Tax effect |  |  | — |  |  |  | 5 |  |  |  | — |  |  |  | 5 |  |  |  | — |  |  |  | 1 |  |  |  | — |  |  |  | 1 |
|  | $ | — |  |  | $ | (17 | ) |  | $ | — |  |  | $ | (17 | ) |  | $ | (25 | ) |  | $ | (2 | ) |  | $ | — |  |  | $ | (27 | )

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The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, currency translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in Other Comprehensive Income or Loss in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three and six months ended June 30, 2014, a majority of these local currencies strengthened against the U.S. dollar resulting in net Other Comprehensive Income of $114 million and $63 million, respectively, upon the translation from local currencies to the U.S. dollar. For the three and six months ended June 30, 2013, a majority of these local currencies weakened against the U.S. dollar resulting in net Other Comprehensive Loss of $96 million and $213 million, respectively, 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 or prior periods. The accumulated effect was Other Comprehensive Loss of $25 million (net of tax of $10 million) and $11 million (net of tax of $4 million) for the three and six months ended June 30, 2014, respectively. The accumulated effect was Other Comprehensive Loss of $22 million (net of tax of $8 million) and $70 million (net of tax of $27 million) for the three and six months ended June 30, 2013, respectively.

7. | Business Segments

Effective April 1, 2014, the Company’s operations were reorganized into four reportable segments: Rig Systems, Rig Aftermarket, Wellbore Technologies and Completion & Production Solutions. Within the four reporting segments, the Company has aggregated two business units under Rig Systems, one business unit under Rig Aftermarket, six business units under Wellbore Technologies and six business units under Completion & Production Solutions for a total of 15 business units. The Company has aggregated each of its business units in one of the four reporting segments based on the guidelines of ASC Topic 280, “Segment Reporting” (“ASC Topic 280”).

Rig Systems

The Company’s Rig Systems 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 rig process and functionality.

Equipment and technologies in Rig Systems 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 Rig Systems segment primarily supports land and offshore drillers. Demand for Rig Systems products primarily depends on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig construction and refurbishment.

Rig Aftermarket

The Company’s Rig Aftermarket segment provides comprehensive aftermarket products and services to support land rigs and offshore rigs, and drilling rig components manufactured by the Rig Systems segment.

The segment provides spare parts, repair, and rentals as well as technical support, field service and first well support, field engineering, and customer training through a network of aftermarket service and repair facilities strategically located in major areas of drilling operations.

The Rig Aftermarket segment primarily supports land and offshore drillers. Demand for Rig Aftermarket products and services primarily depends on overall levels of oilfield drilling activity, which drives demand for spare parts, service, and repair for Rig System’s large installed base of equipment; and secondarily on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig refurbishment and re-certification.

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, premium drill pipe, wired pipe, tubular inspection and coating services, instrumentation, downhole tools, and drill bits.

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The Wellbore Technologies segment focuses on oil and gas companies and supports drilling contractors, oilfield service companies, and oilfield rental companies. Demand for Wellbore Technologies products and services primarily 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 and pumps, blenders, sanders, hydration units, injection units, flowline, manifolds and wellheads; 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.

The Completion & Production Solutions segment primarily supports service companies and oil and gas companies. Demand for Completion & Production Solutions 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.

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

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  | $ | 2,372 |  |  | $ | 2,081 |  |  | $ | 4,628 |  |  | $ | 3,992 |
Rig Aftermarket |  |  | 785 |  |  |  | 670 |  |  |  | 1,535 |  |  |  | 1,221 |
Wellbore Technologies |  |  | 1,446 |  |  |  | 1,222 |  |  |  | 2,724 |  |  |  | 2,445 |
Completion & Production Solutions |  |  | 1,127 |  |  |  | 1,057 |  |  |  | 2,129 |  |  |  | 2,059 |
Eliminations |  |  | (475 | ) |  |  | (350 | ) |  |  | (872 | ) |  |  | (661 | )
Total Revenue |  | $ | 5,255 |  |  | $ | 4,680 |  |  | $ | 10,144 |  |  | $ | 9,056 |
Operating Profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  | $ | 501 |  |  | $ | 383 |  |  | $ | 952 |  |  | $ | 753 |
Rig Aftermarket |  |  | 217 |  |  |  | 189 |  |  |  | 408 |  |  |  | 331 |
Wellbore Technologies |  |  | 263 |  |  |  | 184 |  |  |  | 484 |  |  |  | 366 |
Completion & Production Solutions |  |  | 157 |  |  |  | 127 |  |  |  | 294 |  |  |  | 263 |
Unallocated expenses and eliminations |  |  | (225 | ) |  |  | (170 | ) |  |  | (426 | ) |  |  | (307 | )
Total Operating Profit |  | $ | 913 |  |  | $ | 713 |  |  | $ | 1,712 |  |  | $ | 1,406 |
Operating Profit %: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  |  | 21.1 | % |  |  | 18.4 | % |  |  | 20.6 | % |  |  | 18.9 | %
Rig Aftermarket |  |  | 27.6 | % |  |  | 28.2 | % |  |  | 26.6 | % |  |  | 27.1 | %
Wellbore Technologies |  |  | 18.2 | % |  |  | 15.1 | % |  |  | 17.8 | % |  |  | 15.0 | %
Completion & Production Solutions |  |  | 13.9 | % |  |  | 12.0 | % |  |  | 13.8 | % |  |  | 12.8 | %
Total Operating Profit % |  |  | 17.4 | % |  |  | 15.2 | % |  |  | 16.9 | % |  |  | 15.5 | %

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 four reporting segments that are eliminated in consolidation. Intercompany transactions within each reporting segment are eliminated within each reporting segment.

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

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Other items: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  | $ | — |  |  | $ | 10 |  |  | $ | — |  |  | $ | 12 |
Rig Aftermarket |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Wellbore Technologies |  |  | 6 |  |  |  | 11 |  |  |  | 9 |  |  |  | 37 |
Completion & Production Solutions |  |  | 1 |  |  |  | 36 |  |  |  | 7 |  |  |  | 72 |
Unallocated expenses and eliminations |  |  | 25 |  |  |  | — |  |  |  | 34 |  |  |  | — |
Total other items |  | $ | 32 |  |  | $ | 57 |  |  | $ | 50 |  |  | $ | 121 |

The Company had revenues of 8% of total revenue from one of its customers for each of the three and six months ended June 30, 2014, and 12% for each of the three and six months ended June 30, 2013. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.

8. | Debt

Debt consists of (in millions):

|  | June 30, |  |  | December 31, |
|  | 2014 |  |  | 2013 |
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015 |  | $ | 151 |  |  | $ | 151 |
Senior Notes, interest at 1.35% payable semiannually, principal due on December 1, 2017 |  |  | 500 |  |  |  | 500 |
Senior Notes, interest at 2.6% payable semiannually, principal due on December 1, 2022 |  |  | 1,396 |  |  |  | 1,396 |
Senior Notes, interest at 3.95% payable semiannually, principal due on December 1, 2042 |  |  | 1,096 |  |  |  | 1,096 |
Other |  |  | 5 |  |  |  | 7 |
Total debt |  |  | 3,148 |  |  |  | 3,150 |
Less current portion |  |  | — |  |  |  | 1 |
Long-term debt |  | $ | 3,148 |  |  | $ | 3,149 |

The Company has a $3.5 billion, five-year unsecured revolving credit facility which expires September 28, 2018. The Company also has a commercial paper program that is supported by its revolving credit facility. At June 30, 2014, the Company had no commercial paper borrowings and no borrowings against its revolving credit facility. Funds available under the Company’s revolving credit facility were $2,369 million due to $1,131 million in outstanding letters of credit issued under the facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% subject to a ratings-based grid, or the U.S. prime rate. The credit facility contains a financial covenant regarding maximum debt to capitalization and the Company was in compliance at June 30, 2014.

The Company also had $3,150 million of additional outstanding letters of credit at June 30, 2014, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds, advanced payment bonds and performance bonds.

The 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 June 30, 2014 and December 31, 2013, the fair value of the Company’s unsecured Senior Notes approximated $3,054 million and $2,896 million, respectively. At both June 30, 2014 and December 31, 2013, the carrying value of the Company’s unsecured Senior Notes approximated $3,143 million.

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9. | Tax

The effective tax rate for the three and six months ended June 30, 2014 was 31.8% and 31.1%, respectively, compared to 30.6% and 30.7% for the same periods in 2013. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the periods by the effect of lower tax rates on income earned in foreign jurisdictions, that is considered to be indefinitely reinvested, foreign exchange losses for tax reporting in Norway, and the deduction in the U.S. for manufacturing activities. The effective tax rate was negatively impacted by foreign dividends net of foreign tax credits.

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

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Federal income tax at U.S. federal statutory rate |  | $ | 312 |  |  | $ | 249 |  |  | $ | 588 |  |  | $ | 482 |
Foreign income tax rate differential |  |  | (51 | ) |  |  | (65 | ) |  |  | (98 | ) |  |  | (122 | )
State income tax, net of federal benefit |  |  | 9 |  |  |  | 4 |  |  |  | 15 |  |  |  | 12 |
Nondeductible expenses |  |  | 8 |  |  |  | 8 |  |  |  | 19 |  |  |  | 16 |
Tax benefit of manufacturing deduction |  |  | (10 | ) |  |  | (8 | ) |  |  | (17 | ) |  |  | (16 | )
Foreign dividends, net of foreign tax credits |  |  | 12 |  |  |  | 8 |  |  |  | 21 |  |  |  | 12 |
Tax impact of foreign exchange |  |  | 6 |  |  |  | 21 |  |  |  | (2 | ) |  |  | 39 |
Other |  |  | (2 | ) |  |  | 1 |  |  |  | (3 | ) |  |  | — |
Provision for income taxes |  | $ | 284 |  |  | $ | 218 |  |  | $ | 523 |  |  | $ | 423 |

The balance of unrecognized tax benefits at June 30, 2014 was $128 million, $55 million of which if ultimately realized, would be recorded as an income tax benefit. Included in the change in the balance of unrecognized tax benefits was an increase of $1 million associated with certain operating expenses that may not be deductible in foreign jurisdictions.

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

The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The Company has significant operations in the United States, Canada, the United Kingdom, the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdiction vary by legal entity, but are generally open in the U.S. for tax years after 2009 and outside the U.S. for tax years after 2005.

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

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10. | Stock-Based Compensation

The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights. The number of shares authorized under the Plan is 39.5 million. At June 30, 2014, 11,327,904 shares remain available for future grants under the Plan, all of which are available for grants of stock options, performance-based share awards, restricted stock awards, phantom shares, stock payments and stock appreciation rights.

On February 25, 2014, the Company granted 3,113,607 stock options with a fair value of $25.60 per share and an exercise price of $74.83 per share; 426,272 shares of restricted stock and restricted stock units with a fair value of $74.83 per share; and performance share awards to senior management employees with potential payouts varying from zero to 436,390 shares. The stock options vest over a three-year period from the grant date while the restricted stock and restricted stock units vest on the third 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 divided into two equal, independent parts that are subject to two separate performance metrics: 50% with a TSR (total shareholder return) goal (the “TSR Award”) and 50% with an internal ROC (return on capital) goal (the “ROC Award”).

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

On May 14, 2014, the Company granted 18,736 restricted stock awards with a fair value of $68.89 per share. The awards were granted to non-employee members of the board of directors and vest on the first anniversary of the grant date.

On June 2, 2014, as a result of the spin-off and pursuant to the terms of the Employee Matters Agreement and the Plan, outstanding NOV stock-based awards held by continuing NOV employees were adjusted to generally preserve the intrinsic value of the original award. Outstanding NOV stock-based awards held by employees of NOW were converted into similar NOW stock-based awards, each appropriately adjusted to generally preserve the intrinsic value of the original award. Adjustments to the awards did not have a material impact to compensation expense.

Total stock-based compensation for all stock-based compensation arrangements under the Plan was $27 million and $51 million for the three and six months ended June 30, 2014, respectively and $24 million and $39 million for the three and six months ended June 30, 2013, respectively. The total income tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation arrangements under the Plan was $9 million and $16 million for the three and six months ended June 30, 2014, respectively and $8 million and $12 million for the three and six months ended June 30, 2013, respectively.

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11. | Derivative Financial Instruments

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

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

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

At June 30, 2014, the Company has determined that the fair value of its derivative financial instruments representing assets of $49 million and liabilities of $38 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 June 30, 2014, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $11 million.

At June 30, 2014, the Company did not have any interest rate swaps and its financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

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

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

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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 |  | June 30, 2014 |  |  | December 31, 2013 |
Norwegian Krone |  | NOK | 11,836 |  |  | NOK | 10,503 |
Euro |  | € | 474 |  |  | € | 406 |
U.S. Dollar |  | $ | 305 |  |  | $ | 357 |
Danish Krone |  | DKK | 273 |  |  | DKK | 278 |
Mexican peso |  | MXN | 258 |  |  | MXN | — |
British Pound Sterling |  | £ | 43 |  |  | £ | 23 |
Singapore Dollar |  | SGD | 32 |  |  | SGD | 17 |
Canadian Dollar |  | CAD | 15 |  |  | CAD | 16 |

Non-designated Hedging Strategy

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

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

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

|  | Currency Denomination |
Foreign Currency |  | June 30, 2014 |  |  | December 31, 2013 |
Norwegian Krone |  | NOK | 2,857 |  |  | NOK | 3,257 |
Russian Ruble |  | RUB | 1,691 |  |  | RUB | 2,149 |
U.S. Dollar |  | $ | 913 |  |  | $ | 715 |
Euro |  | € | 426 |  |  | € | 310 |
Danish Krone |  | DKK | 290 |  |  | DKK | 177 |
Brazilian Real |  | BRL | 44 |  |  | BRL | — |
Singapore Dollar |  | SGD | 20 |  |  | SGD | 3 |
British Pound Sterling |  | £ | 18 |  |  | £ | 14 |
Swedish Krone |  | SEK | 9 |  |  | SEK | 4 |
Canadian Dollar |  | CAD | 3 |  |  | CAD | 3 |

17

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

NATIONAL OILWELL VARCO, INC.

Fair Values of Derivative Instruments

(In millions)

|  | Asset Derivatives |  |  | Liability Derivatives |
|  |  |  | Fair Value |  |  |  |  | Fair Value |
|  | Balance Sheet |  | June 30, |  |  | December 31, |  |  | Balance Sheet |  | June 30, |  |  | December 31, |
|  | Location |  | 2014 |  |  | 2013 |  |  | Location |  | 2014 |  |  | 2013 |
Derivatives designated as hedging instruments under ASC Topic 815 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign exchange contracts |  | Prepaid and other current assets |  | $ | 18 |  |  | $ | 35 |  |  | Accrued liabilities |  | $ | 13 |  |  | $ | 18 |
Foreign exchange contracts |  | Other Assets |  |  | 9 |  |  |  | 5 |  |  | Other Liabilities |  |  | 13 |  |  |  | 9 |
Total derivatives designated as hedging instruments under ASC Topic 815 |  |  |  | $ | 27 |  |  | $ | 40 |  |  |  |  | $ | 26 |  |  | $ | 27 |
Derivatives not designated as hedging instruments under ASC Topic 815 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign exchange contracts |  | Prepaid and other current assets |  | $ | 21 |  |  | $ | 19 |  |  | Accrued liabilities |  | $ | 12 |  |  | $ | 13 |
Foreign exchange contracts |  | Other Assets |  |  | 1 |  |  |  | — |  |  | Other Liabilities |  |  | — |  |  |  | — |
Total derivatives not designated as hedging instruments under ASC Topic 815 |  |  |  | $ | 22 |  |  | $ | 19 |  |  |  |  | $ | 12 |  |  | $ | 13 |
Total derivatives |  |  |  | $ | 49 |  |  | $ | 59 |  |  |  |  | $ | 38 |  |  | $ | 40 |

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 June 30, |  |  |  |  | Three Months Ended June 30, |  |  |  |  | Three Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  |  |  | 2014 |  |  | 2013 |  |  |  |  | 2014 |  |  | 2013 |
|  |  |  |  |  |  |  |  |  | Revenue |  |  | 21 |  |  |  | 4 |  |  |  |  |  |  |  |  |  |  |
Foreign exchange contracts |  |  | 13 |  |  |  | (95 | ) |  | Cost of revenue |  |  | 1 |  |  |  | (1 | ) |  | Other income (expense), net |  |  | 19 |  |  |  | 5 |
Total |  |  | 13 |  |  |  | (95 | ) |  |  |  |  | 22 |  |  |  | 3 |  |  |  |  |  | 19 |  |  |  | 5 |

(a) | The Company expects that $3 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 $1 million and nil related to the ineffective portion of the hedging relationships for the six months ended June 30, 2014 and 2013, respectively, and $19 million and $5 million related to the amount excluded from the assessment of the hedge effectiveness for the six months ended June 30, 2014 and 2013, respectively.

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12. | Net Income Attributable to Company Per Share

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

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Numerator: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations |  | $ | 608 |  |  | $ | 494 |  |  | $ | 1,156 |  |  | $ | 955 |
Income from discontinued operations |  | $ | 11 |  |  | $ | 37 |  |  | $ | 52 |  |  | $ | 78 |
Net income attributable to Company |  | $ | 619 |  |  | $ | 531 |  |  | $ | 1,208 |  |  | $ | 1,033 |
Denominator: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic—weighted average common shares outstanding |  |  | 428 |  |  |  | 426 |  |  |  | 428 |  |  |  | 426 |
Dilutive effect of employee stock options and other unvested stock awards |  |  | 2 |  |  |  | 2 |  |  |  | 2 |  |  |  | 2 |
Diluted outstanding shares |  |  | 430 |  |  |  | 428 |  |  |  | 430 |  |  |  | 428 |
Per share data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations |  | $ | 1.42 |  |  | $ | 1.16 |  |  | $ | 2.70 |  |  | $ | 2.24 |
Income from discontinued operations |  | $ | 0.03 |  |  | $ | 0.09 |  |  | $ | 0.12 |  |  | $ | 0.18 |
Net income attributable to Company |  | $ | 1.45 |  |  | $ | 1.25 |  |  | $ | 2.82 |  |  | $ | 2.42 |
Diluted: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income from continuing operations |  | $ | 1.42 |  |  | $ | 1.15 |  |  | $ | 2.69 |  |  | $ | 2.23 |
Income from discontinued operations |  | $ | 0.02 |  |  | $ | 0.09 |  |  | $ | 0.12 |  |  | $ | 0.18 |
Net income attributable to Company |  | $ | 1.44 |  |  | $ | 1.24 |  |  | $ | 2.81 |  |  | $ | 2.41 |
Cash dividends per share |  | $ | 0.46 |  |  | $ | 0.26 |  |  | $ | 0.72 |  |  | $ | 0.39 |

ASC Topic 260, “Earnings Per Share” (“ASC Topic 260”) requires companies with unvested participating securities to utilize a two-class method for the computation of Net income attributable to Company per share. The two-class method requires a portion of Net income attributable to Company to be allocated to participating securities, which are unvested awards of share-based payments with non-forfeitable rights to receive dividends or dividend equivalents, if declared. Net income attributable to Company allocated to these participating securities was immaterial for three and six months ended June 30, 2014 and therefore not excluded from Net income attributable to Company per share calculation.

In addition, the Company had stock options outstanding that were anti-dilutive totaling 9 million shares for each of the three and six months ended June 30, 2014, and 7 million shares for each of the three and six months ended June 30, 2013, respectively.

13. | Cash Dividends

On May 14, 2014, the Company’s Board of Directors approved a cash dividend of $0.46 per share. The cash dividend was paid on June 27, 2014, to each stockholder of record on June 13, 2014. Cash dividends aggregated $198 million and $309 million for the three and six months ended June 30, 2014, and $111 million and $167 million for the three and six months ended June 30, 2013, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.

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14. | Commitments and Contingencies

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

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

In addition, we are involved in various other claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. As of June 30, 2014, the Company recorded an immaterial amount for contingent liabilities representing all contingencies believed to be probable. The Company has also assessed the potential for additional losses above the amounts accrued as well as potential losses for matters that are not probable but are reasonably possible. The total potential loss on these matters cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for and except for the specific cases referred to above, will not materially affect our financial position, cash flow or results of operations. As it relates to the specific cases referred to above we currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position, cash flow or results of operations. These estimated liabilities are based on the Company’s assessment of the nature of these matters, their progress toward resolution, the advice of legal counsel and outside experts as well as management’s intention and experience.

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

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15. | Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update No. 2014-08 “Reporting Discontinued Operations and Disclosures of Disposals of Components of and Entity” (ASU No. 2014-08), which is an update for Accounting Standards Codification Topic No. 205 “Presentation of Financial Statements” and Topic No. 360 “Property, Plant and Equipment’. This update changes the requirements of reporting discontinued operations. Under the amended guidance, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update are effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Although early adoption is permitted, the Company did not elect to apply the guidance of ASU No. 2014-08 to the spin-off of NOW. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements. The Company is currently assessing the impact of ASU No. 2014-08 on its consolidated financial position and results of operations.

In May 2014, the FASB issued Accounting Standard Update No. 2014-09 “Revenue from Contracts with Customers” (ASU No. 2014-09), which supersedes the revenue recognition requirements in Accounting Standard Codification Topic No. 605 “Revenue Recognition” and most industry-specific guidance. This update requires that entities recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. ASU No. 2014-09 is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. The Company is currently assessing the impact of the adoption of ASU No. 2014-09 on its consolidated financial position and results of operations.

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

Introduction

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

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

Rig Systems

The Company’s Rig Systems 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 rig process and functionality.

Equipment and technologies in Rig Systems 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 Rig Systems segment primarily supports land and offshore drillers. Demand for Rig Systems products primarily depends on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig construction and refurbishment.

Rig Aftermarket

The Company’s Rig Aftermarket segment provides comprehensive aftermarket products and services to support land rigs and offshore rigs, and drilling rig components manufactured by the Rig Systems segment.

The segment provides spare parts, repair, and rentals as well as technical support, field service and first well support, field engineering, and customer training through a network of aftermarket service and repair facilities strategically located in major areas of drilling operations.

The Rig Aftermarket segment primarily supports land and offshore drillers. Demand for Rig Aftermarket products and services primarily depends on overall levels of oilfield drilling activity, which drives demand for spare parts, service, and repair for Rig System’s large installed base of equipment; and secondarily on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig refurbishment and re-certification.

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, premium drill pipe, wired pipe, tubular inspection and coating services, instrumentation, downhole tools, and drill bits.

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

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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 and pumps, blenders, sanders, hydration units, injection units, flowline, manifolds and wellheads; 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.

The Completion & Production Solutions segment primarily supports service companies and oil and gas companies. Demand for Completion & Production Solutions 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.

Discontinued Operations

On May 30, 2014, the Company completed the spin-off of its distribution business into an independent public company named NOW Inc. and the results of operations for the distribution business have been classified as discontinued operations for all periods presented. Unless indicated otherwise, the information in the Management’s Discussion and Analysis of Financial Condition and Results of Operations relates to our continuing operations.

Critical Accounting Policies and Estimates

In our annual report on Form 10-K for the year ended December 31, 2013, we identified our most critical accounting policies. In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are most critical in nature which are related to revenue recognition under long-term construction contracts; allowance for doubtful accounts; inventory reserves; impairment of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets; purchase price allocation of acquisitions; service and product warranties; and income taxes. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. The combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates and those differences may be material.

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EXECUTIVE SUMMARY

For its second quarter ended June 30, 2014, the Company generated $609 million in income from continuing operations, or $1.42 per fully diluted share, on $5.3 billion in revenue. Compared to the first quarter of 2014, revenue increased $366 million or 7% and income from continuing operations increased $61 million or 11%. Compared to the second quarter of 2013, revenue increased $575 million or 12%, and income from continuing operations increased $115 million or 23%.

The second quarter of 2014 included pre-tax other items of $32 million, the first quarter of 2014 included pre-tax other items of $18 million, and the second quarter of 2013 included pre-tax other items of $57 million. Excluding the other items from all periods, second quarter 2014 earnings from continuing operations were $1.47 per fully diluted share, compared to $1.29 per fully diluted share in the first quarter of 2014 and $1.24 per fully diluted share in the second quarter of 2013.

Pre-tax other items of $32 million, $18 million, $57 million for the second quarter of 2014, first quarter of 2014, and the second quarter of 2013, respectively, included costs related to acquisitions, such as transaction costs, the amortization of backlog and inventory that was stepped up to fair value during purchase accounting, the costs of the spin-off of the Company’s distribution business and certain legal costs.

Operating profit, excluding other items, was $945 million or 18.0% of sales in the second quarter of 2014, compared to $817 million or 16.7% of sales in the first quarter of 2014, and $770 million or 16.5% of sales in the second quarter of 2013.

Oil & Gas Equipment and Services Market

Worldwide, developed economies turned down in late 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks responded vigorously through 2009, but a credit-driven worldwide economic recession developed nonetheless. Developed economies struggled to recover throughout 2010 and 2011, facing additional economic weakness related to potential sovereign debt defaults in Europe. As a result, commodity prices, including oil and gas prices, have been volatile. During the first quarter of 2009, oil prices averaged $43 per barrel, but slowly recovered into the $100 per barrel range by mid-2011 where they held relatively steady since (although the fourth quarter of 2012 dipped to average $88 per barrel). As a result of relatively high and stable oil prices, oil-drilling activity over the past two years has increased. In the third quarter of 2009, North American gas prices declined to average $3.17 per mmbtu. Gas prices recovered modestly, trading up above $5 six months later, but then slowly settled into the $3 to $4 per mmbtu through 2011 before turning down sharply in early 2012 to the $2 range. However, the average quarterly price per mmbtu climbed steadily since the second quarter of 2012 to an average of $4.61 per mmbtu in the second quarter of 2014 significantly up from a full year 2013 average of $3.72 per mmbtu. Recent price upticks seem to be a product of relatively colder weather; and, as a result, the supply of natural gas stockpiles diminishing.

The count of rigs actively drilling in the U.S. as measured by Baker Hughes, Inc. (a good measure of the level of oilfield activity and spending) decreased to a low of 876 in June, 2009 as many oil and gas operators, reliant on external financing to fund their drilling programs, significantly curtailed their drilling activity. As commodity prices improved, the U.S. rig count increased steadily to 2,026 by late 2011, but began to decline to average 1,852 rigs during the second quarter of 2014. Recently low gas prices have caused operators to trim drilling, driving the average U.S. gas rig count down 64% from the fourth quarter of 2011, to an average of 318 in the second quarter of 2014. However, with high oil prices, many have redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. For the second quarter of 2014, oil-directed drilling rose to 83% of the total domestic drilling effort, and remains at its highest levels in the U.S. since the early 1980’s.

Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings; but, the international rig count exhibited modest declines nonetheless, falling from its 1,108 in September 2008 to 947 in August 2009. Since that decline, international drilling activity has increased and averaged 1,348 rigs in the second quarter of 2014.

During 2009 the Company saw its Wellbore Technologies and Completion & Production Solutions margins affected most acutely by a drilling downturn, through both volume and price declines. Resumption of drilling activity since enabled both of these segments to gain volume, stabilize and lift pricing, and improve margins over 2009 results. The Company’s Rig Systems segment was less impacted by the 2009 downturn owing to its high level of contracted backlog, which it executed well. It posted higher revenues and operating profits in 2009 than 2008 as a result. The segment’s revenues decreased in 2010 as its backlog declined, remained relatively flat in 2011, and rose 24% year-over-year in 2012 as orders for new offshore rigs increased.

The economic decline beginning in late 2008 followed an extended period of high drilling activity which fueled strong demand for oilfield services between 2003 and 2008. Incremental drilling activity through the upswing shifted toward harsh environments, employing increasingly sophisticated technology to find and produce reserves. Higher utilization of drilling rigs tested the capability

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of the world’s fleet of rigs, much of which is old and of limited capability. Technology has advanced significantly since most of the existing rig fleet was built. The industry invested little during the late 1980’s and 1990’s on new drilling equipment, but drilling technology progressed steadily nonetheless, as the Company and its competitors continued to invest in new and better ways of drilling. As a consequence, the safety, reliability, and efficiency of new, modern rigs surpass the performance of most of the older rigs at work today. Drilling rigs are now being pushed to drill deeper wells, more complex wells, highly deviated wells and horizontal wells, tasks which require larger rigs with more capabilities. The drilling process effectively consumes the mechanical components of a rig, which wear out and need periodic repair or replacement. This process was accelerated by very high rig utilization and wellbore complexity. Drilling consumes rigs; more complex and challenging drilling consumes rigs faster.

The industry responded by launching many new rig construction projects since 2005, to: 1.) retool the existing fleet of jackup rigs, 2.) replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and 3.) build out additional deepwater floating drilling rigs, including semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet.

As a result of the credit crisis and slowing drilling activity in 2009, orders in the Rig Systems segment declined below amounts flowing out of backlog as revenue, causing the segment’s backlog to decline to $4.4 billion by the end of 2010. Since 2010 lows, the backlog increased steadily as drillers ordered more than the Company shipped out of backlog, and the segment finished the second quarter of 2014 at a record $15.4 billion. Of this backlog, 93% of the total is for equipment destined for offshore operations, with 7% destined for land. Equipment destined for international markets totaled 94% of the backlog as of the end of the second quarter of 2014.

Manufacturing lead time for orders in the Completion & Production Solutions segment’s backlog is considerably shorter than that of the orders in Rig System’s backlog. This segment’s backlog has increased since 2009 as levels of drilling activity worldwide moved higher. Backlog in this segment was $2.1B at the end of the second quarter of 2014. Of the $2.1B, 66% of the total is for equipment destined for offshore operations, with 34% destined for land. Equipment destined for international markets totaled 83%.

Segment Performance

The Rig Systems segment generated $2.4 billion in revenues and $501 million in operating profit or 21.1% of sales in the second quarter of 2014. Compared to the prior quarter, revenues increased $116 million, and operating profit increased $50 million, representing 43% incremental operating leverage. Compared to the second quarter of 2013, segment revenues grew $291 million or 14%, and operating profit increased $118 million, representing 31% incremental leverage. The segments margins have moved down steadily since mid-2010 due to an adverse mix shift in the segment, the addition of lower-margin acquisitions, and incremental expenses to support several strategic growth initiatives. The mix shift arises from offshore projects contracted at high prices in 2007 and 2008, which were subsequently manufactured in low cost environments in 2009 and 2010, resulting in high margins for the group which peaked in the third quarter of 2010. As these projects have been completed and replaced with lower priced projects, margins have gradually declined. Margins have also been negatively impacted by the compression of delivery schedules from our shipyard customers, which have challenged the limits of our supply chain and increased our overall project costs. Second quarter 2014 revenue out of backlog for the Rig Systems segment increased 6% in comparison to the first quarter of 2014 and 14% year-over-year. Orders for seven deepwater floating rig equipment packages, and one drilling equipment package for a jackup rig, contributed to total order additions to the segment’s backlog of $2.3 billion during the second quarter of 2014. Offshore rig newbuild projects, floaters and jackups, accounted for approximately $1.4 billion, or 27%, of the Company’s consolidated second quarter revenues, all within the Rig Systems segment.

The Rig Aftermarket segment generated $785 million in revenues and $217 million in operating profit or 27.6% of sales in the second quarter of 2014. Compared to the prior quarter, revenues increased $35 million, and operating profit increased $26 million, representing 74% incremental operating leverage. Compared to the second quarter of 2013, segment revenues grew $115 million or 17%, and operating profit increased $28 million, representing 24% incremental leverage. Year-over-year revenue and operating profit growth is mainly attributable to increased demand for spare parts, repairs and services along with continued investments in capacity expansions.

The Wellbore Technologies segment generated $1.4 billion in revenue and $263 million in operating profit, or 18.2% of sales, for the second quarter of 2014. Compared to the prior quarter, revenue increased $168 million or 13%, and operating profit increased $42 million, representing 25% incremental operating leverage. Revenues were up sequentially as a reduction in active rigs drilling in Canada was offset by a strengthening U.S. market. Compared to the second quarter of 2013, revenues increased $224 million, and operating profit increased $79 million, representing 35% incremental leverage. Both revenues and operating profit were positively influenced by a higher average rig count year-over-year and the fact that our customers have worked through the excess inventory they carried into early 2013.

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The Completion & Production Solutions segment generated $1.1 billion in revenue and $157 million in operating profit or 13.9% of sales during the second quarter of 2014. Revenue increased $125 million or 12% from the first quarter of 2014, and operating profit increased $20 million, representing 16% incremental leverage. The revenue increase was due to higher shipments of subsea flexible pipe and well stimulation equipment. Compared to the second quarter of 2013, revenues increased $70 million, and operating profit increased $30 million. Year-over-year the segment experienced similar results as contributions from acquisitions and higher sales of offshore production equipment were offset by decreased demand for land related pressure pumping equipment and coiled tubing units. Operating leverage was negatively impacted by a higher mix of subsea and floating production businesses.

Outlook

Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher drilling activity in North America and slowly improving international drilling activity. Since that time, order levels for new deepwater drilling rigs, as well as new jackup drilling rigs, have rebounded; but, softening day rates for deepwater drilling rigs could result in a near-term reduction in new orders for deepwater drilling rigs. Some of this expected reduction could be offset by increasing demand for new land drilling rigs and equipment packages, primarily in the North American, Latin American and Middle East markets. And, as the fleet of offshore and land drilling rigs worldwide continues to grow, we are confident that our Aftermarket business will continue to support our growing installed base of equipment with spare parts, service and repair. Strict regulatory drilling requirements worldwide will keep demand for the segment’s offerings at high levels.

Our outlook for the Company’s Wellbore Technologies segment and Completion & Production Solutions segment remains closely tied to the rig count, particularly in North America. Average U.S. rig count during the second quarter of 2014 saw modest gains of 4% and 5% compared to the first quarter of 2014 and second quarter of 2013, respectively. The second quarter of 2014 saw average Canadian rig count decreased 62% sequentially and increased 30% year-over-year. As a result, revenues for both segments improved sequentially in Canada. Domestic land drilling and well service firms are increasing activity, which is leading to increased demand for drilling and stimulation equipment to develop unconventional shales. Activity generally seems to be continuing to increase in most markets outside North America as well.

Subsequent to the second quarter of 2014, both the United States and the European Union announced economic sanctions against Russia affecting its energy, defense and banking industries. The Company had sales of approximately $60 million and $100 million for the three and six months ended June 30, 2014 to customers in Russia. Some or all such sales may be restricted in the future by these sanctions. The Company’s net investment in Russia was approximately $140 million at June 30, 2014. The severity of delayed or lost future revenue, and any possible impairment of our net investment, will depend on the duration of the sanctions and other government actions.

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

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Operating Environment Overview

The Company’s results are dependent on, among other things, the level of worldwide oil and gas drilling, well remediation activity, the prices of crude oil and natural gas, capital spending by other oilfield service companies and drilling contractors, and worldwide oil and gas inventory levels. Key industry indicators for the second quarter of 2014 and 2013, and the first quarter of 2014 include the following

|  | 2Q14* |  |  | 2Q13* |  |  | 1Q14* |  |  | % 2Q14 2Q13 |  |  | % 2Q14 1Q14 |
Active Drilling Rigs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | 1,852 |  |  |  | 1,761 |  |  |  | 1,781 |  |  |  | 5.2 | % |  |  | 4.0 | %
Canada |  |  | 202 |  |  |  | 155 |  |  |  | 526 |  |  |  | 30.3 | % |  |  | (61.6 | %)
International |  |  | 1,348 |  |  |  | 1,305 |  |  |  | 1,337 |  |  |  | 3.3 | % |  |  | 0.8 | %
Worldwide |  |  | 3,402 |  |  |  | 3,221 |  |  |  | 3,644 |  |  |  | 5.6 | % |  |  | (6.6 | %)
West Texas Intermediate Crude Prices (per barrel) |  | $ | 103.35 |  |  | $ | 94.10 |  |  | $ | 98.75 |  |  |  | 9.8 | % |  |  | 4.7 | %
Natural Gas Prices ($/mmbtu) |  | $ | 4.61 |  |  | $ | 4.01 |  |  | $ | 5.18 |  |  |  | 15.0 | % |  |  | (11.0 | %)

* | Averages for the quarters indicated. See sources below.

The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended June 30, 2014, on a quarterly basis:

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

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The worldwide quarterly average rig count decreased 6.6% (from 3,644 to 3,402) and the U.S. increased 4.0% (from 1,781 to 1,852), in the second quarter of 2014 compared to the first quarter of 2014. The average per barrel price of West Texas Intermediate Crude increased 4.7% (from $98.75 per barrel to $103.35 per barrel) and natural gas prices decreased 11.0% (from $5.18 per mmbtu to $4.61 per mmbtu) in the second quarter of 2014 compared to the first quarter of 2014.

U.S. rig activity at July 25, 2014 was 1,883 rigs increased two percent compared to the second quarter average of 1,852 rigs. The price for West Texas Intermediate Crude was at $102.09 per barrel at July 25, 2014, decreasing one percent from the second quarter average. The price for natural gas was at $3.78 per mmbtu at July 25, 2014, decreasing 18 percent from the second quarter average.

Results of Operations

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

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |
Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  | $ | 2,372 |  |  | $ | 2,081 |  |  | $ | 4,628 |  |  | $ | 3,992 |
Rig Aftermarket |  |  | 785 |  |  |  | 670 |  |  |  | 1,535 |  |  |  | 1,221 |
Wellbore Technologies |  |  | 1,446 |  |  |  | 1,222 |  |  |  | 2,724 |  |  |  | 2,445 |
Completion & Production Solutions |  |  | 1,127 |  |  |  | 1,057 |  |  |  | 2,129 |  |  |  | 2,059 |
Eliminations |  |  | (475 | ) |  |  | (350 | ) |  |  | (872 | ) |  |  | (661 | )
Total Revenue |  | $ | 5,255 |  |  | $ | 4,680 |  |  | $ | 10,144 |  |  | $ | 9,056 |
Operating Profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  | $ | 501 |  |  | $ | 383 |  |  | $ | 952 |  |  | $ | 753 |
Rig Aftermarket |  |  | 217 |  |  |  | 189 |  |  |  | 408 |  |  |  | 331 |
Wellbore Technologies |  |  | 263 |  |  |  | 184 |  |  |  | 484 |  |  |  | 366 |
Completion & Production Solutions |  |  | 157 |  |  |  | 127 |  |  |  | 294 |  |  |  | 263 |
Unallocated expenses and eliminations |  |  | (225 | ) |  |  | (170 | ) |  |  | (426 | ) |  |  | (307 | )
Total Operating Profit |  | $ | 913 |  |  | $ | 713 |  |  | $ | 1,712 |  |  | $ | 1,406 |
Operating Profit %: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  |  | 21.1 | % |  |  | 18.4 | % |  |  | 20.6 | % |  |  | 18.9 | %
Rig Aftermarket |  |  | 27.6 | % |  |  | 28.2 | % |  |  | 26.6 | % |  |  | 27.1 | %
Wellbore Technologies |  |  | 18.2 | % |  |  | 15.1 | % |  |  | 17.8 | % |  |  | 15.0 | %
Completion & Production Solutions |  |  | 13.9 | % |  |  | 12.0 | % |  |  | 13.8 | % |  |  | 12.8 | %
Total Operating Profit % |  |  | 17.4 | % |  |  | 15.2 | % |  |  | 16.9 | % |  |  | 15.5 | %

Rig Systems

Three and Six months ended June 30, 2014 and 2013. Revenue from Rig Systems was $2,372 million for the three months ended June 30, 2014, compared to $2,081 million for the three months ended June 30, 2013, an increase of $291 million (14.0%). For the six months ended June 30, 2014, revenue from Rig Systems was $4,628 million compared to $3,992 million for the six months ending June 30, 2013, an increase of $636 million (15.9%). Increased demand for land rigs in the U.S., Latin America and the Middle East resulted in higher revenues for Rig Systems in the first half of 2014. In addition, increased capacity enabled Rig Systems to generate revenue out of backlog of $2,075 million and $4,039 million for the three and six months ended June 30, 2014, respectively, compared to revenue out of backlog of $1,819 million and $3,485 million for the three and six months ended June 30, 2013, respectively.

Operating profit from Rig Systems was $501 million for the three months ended June 30, 2014 compared to $383 million for the three months ended June 30, 2013, an increase of $118 million (30.8%) from the same period in 2013. Operating profit percentage increased to 21.1% for the three months ended June 30, 2014, from 18.4% in the three months ended June 30, 2013. For the six months ended June 30, 2014, operating profit from Rig Systems was $952 million compared to $753 million for the six months ending June 30, 2013, an increase of $199 million (26.4%). Operating profit percentage increased to 20.6% for the six months ended June 30, 2014, from 18.9% in the six months ended June 30, 2013.

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The Rig Systems 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 $15.4 billion at June 30, 2014, an increase of $2.5 billion (19.7%) from backlog of $12.9 billion at June 30, 2013. At June 30, 2014, approximately 93% of the capital equipment backlog was for offshore products and 7% was for land. In addition, at June 30, 2014, approximately 94% of the capital equipment backlog was for international markets and 6% was for domestic markets.

Rig Aftermarket

Three and Six months ended June 30, 2014 and 2013. Revenue from Rig Aftermarket was $785 million for the three months ended June 30, 2014, compared to $670 million for the three months ended June 30, 2014, an increase of $115 million (17.2%). For the six months ended June 30, 2014, revenue from Rig Aftermarket was $1,535 million compared to $1,221 million for the six months ending June 30, 2013, an increase of $314 million (25.7%). Deep water offshore drilling worldwide and an increased demand for land drilling equipment in North America are the primary driving forces for the increase in revenue.

Operating profit from Rig Aftermarket was $217 million for the three months ended June 30, 2014 compared to $189 million for the three months ended June 30, 2013, an increase of $28 million (14.8%). For the six months ended June 30, 2014, operating profit from Rig Aftermarket was $408 million compared to $331 million for the six months ending June 30, 2013, an increase of $77 million (23.3%). Operating profit percentage decreased in the six months ended June 30, 2014 to 26.6%, from 27.1% in the six months ended June 30, 2013. Operating profit percentage decreased slightly due to reserves taken on slow moving inventory and several expansion initiatives worldwide.

Wellbore Technologies

Three and Six months ended June 30, 2014 and 2013. Revenue from Wellbore Technologies was $1,446 million for the three months ended June 30, 2014 compared to $1,222 million for the three months ended June 30, 2013, an increase of $224 million (18.3%). For the six months ended June 30, 2014, revenue from Wellbore Technologies was $2,724 million compared to $2,445 million for the six months ending June 30, 2013, an increase of $279 million (11.4%). This increase is primarily due to a strengthening in the U.S. market coupled with the fact that customers have worked through excess inventory that they carried into 2013.

Operating profit from Wellbore Technologies was $263 million for the three months ended June 30, 2014 compared to $184 million for the three months ended June 30, 2013, an increase of $79 million (42.9%). For the six months ended June 30, 2014, operating profit from Wellbore Technologies was $484 million compared to $366 million for the six months ending June 30, 2013, an increase of $118 million (32.2%). Operating profit percentage increased to 17.8% in the six months ended June 30, 2014, up from 15.0% in the six months ended June 30, 2013. This increase is primarily due to higher volumes and lower integration costs.

Completion & Production Solutions

Three and Six months ended June 30, 2014 and 2013. Revenue from Completion & Production Solutions was $1,127 million for three months ended June 30, 2014, compared to $1,057 for the three months ended June 30, 2013, and increase of $70 million (6.6%). For the six months ended June 30, 2014, revenue from Completion & Production Solutions was $2,129 million compared to $2,059 million for the six months ending June 30, 2013, an increase of $70 million (3.4%). The increase in revenue was primarily driven by increased demand for floating production as well as subsea products offset by a decline in stimulation equipment.

Operating profit from Completion & Production Solutions was $157 million for the three months ended June 30, 2014 compared to $127 million for the three months ended June 30, 2013, an increase of $30 million. For the six months ended June 30, 2014, operating profit from Completion & Production Solutions was $294 million compared to $263 million for the six months ending June 30, 2013, an increase of $31 million (11.8%). Operating profit percentage increased to 13.8% in the six months ended June 30, 2014, from 12.8% in the six months ended June 30, 2013. This increase was primarily related to lower integration costs during 2014 compared to 2013 offset by a decrease in operating profit percentage due to product mix with increased revenues from floating production and subsea products.

The Completion & Production 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 components or a signed contract related to a construction project. The capital equipment backlog was $2.1 billion at June 30, 2014, an increase of $0.6 billion (40.0%) from backlog of $1.5 billion at June 30, 2013. At June 30, 2014, approximately 66% of the capital equipment backlog was for offshore products and 34% was for land.

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Eliminations

Eliminations were $475 million and $872 million for the three and six months ended June 30, 2014, respectively. This increase is primarily due to higher 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 four 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 $21 million for each of the three and six months ended June 30, 2014 compared to income of $11 million and expenses of $12 million for the three and six months ended June 30, 2013. The increase in expense is primarily due to increased banking fees as well as lower foreign exchange losses. The three and six months ended June 30, 2013 included gains on the sale of certain assets an event that did not repeat in 2014.

Provision for income taxes

The effective tax rate for the three and six months ended June 30, 2014 was 31.8% and 31.1%, compared to 30.6% and 30.7% for the same period in 2013. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the periods by the effect of lower tax rates on income earned in foreign jurisdictions, that is considered to be indefinitely reinvested, foreign exchange losses for tax reporting in Norway, and the deduction in the U.S. for manufacturing activities. The effective tax rate was negatively impacted by foreign dividends net of foreign tax credits.

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Non-GAAP Financial Measures and Reconciliations

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

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

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

|  | Three Months Ended |  |  | Six Months Ended June 30, |
|  | June 30, |  |  | March 31, 2014 |  |
|  | 2014 |  |  | 2013 |  |  |  | 2014 |  |  | 2013 |
Reconciliation of operating profit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
GAAP operating profit |  | $ | 913 |  |  | $ | 713 |  |  | $ | 799 |  |  | $ | 1,712 |  |  | $ | 1,406 |
Other items (1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Rig Systems |  |  | — |  |  |  | 10 |  |  |  | — |  |  |  | — |  |  |  | 12 |
Rig Aftermarket |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Wellbore Technologies |  |  | 6 |  |  |  | 11 |  |  |  | 6 |  |  |  | 9 |  |  |  | 37 |
Completion & Production Solutions |  |  | 1 |  |  |  | 36 |  |  |  | 3 |  |  |  | 7 |  |  |  | 72 |
Eliminations |  |  | 25 |  |  |  | — |  |  |  | 9 |  |  |  | 34 |  |  |  | — |
Operating profit excluding other items |  | $ | 945 |  |  | $ | 770 |  |  | $ | 817 |  |  | $ | 1,762 |  |  | $ | 1,527 |
|  | Three Months Ended |  |  | Six Months Ended June 30, |
|  | June 30, |  |  | March 31, 2014 |  |
|  | 2014 |  |  | 2013 |  |  |  | 2014 |  |  | 2013 |
Reconciliation of operating profit %: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
GAAP operating profit % |  |  | 17.4 | % |  |  | 15.2 | % |  |  | 16.3 | % |  |  | 16.9 | % |  |  | 15.5 | %
other items % |  |  | 0.6 | % |  |  | 1.3 | % |  |  | 0.4 | % |  |  | 0.5 | % |  |  | 1.4 | %
Operating profit % excluding other items |  |  | 18.0 | % |  |  | 16.5 | % |  |  | 16.7 | % |  |  | 17.4 | % |  |  | 16.9 | %
|  | Three Months Ended |  |  | Six Months Ended June 30, |
|  | June 30, |  |  | March 31, 2014 |  |
|  | 2014 |  |  | 2013 |  |  |  | 2014 |  |  | 2013 |
Reconciliation of diluted earnings per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
GAAP earnings per share (continuing operations) |  | $ | 1.42 |  |  | $ | 1.15 |  |  | $ | 1.28 |  |  | $ | 2.69 |  |  | $ | 2.23 |
Other items (1) |  |  | 0.05 |  |  |  | 0.09 |  |  |  | 0.01 |  |  |  | 0.07 |  |  |  | 0.21 |
Earnings per share excluding other items |  |  | 1.47 |  |  |  | 1.24 |  |  |  | 1.29 |  |  |  | 2.76 |  |  |  | 2.44 |
Amortization of intangible assets |  |  | 0.14 |  |  |  | 0.15 |  |  |  | 0.14 |  |  |  | 0.29 |  |  |  | 0.27 |
Operating (non-GAAP) earnings |  | $ | 1.61 |  |  | $ | 1.39 |  |  | $ | 1.43 |  |  | $ | 3.05 |  |  | $ | 2.71 |

(1) | Other items primarily related to acquisitions, such as transaction costs, the amortization of backlog and inventory that was stepped up to fair value during purchase accounting, the costs of the proposed spin-off of the Company’s distribution business and certain legal costs, items which are included in operating profit. For the three and six months ended June 30, 2014, other items included in operating profit were $32 million and $50 million, respectively. For the three and six months ended June 30, 2013, other items included in operating profit were $57 million and $121 million, respectively. Certain other items are included in other income (expense), net were nil and $8 million for the three and six months ended June 30, 2013, respectively. Other items for the three months ended March 31, 2014 totaled $18 million.

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Liquidity and Capital Resources

Overview

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

At June 30, 2014, the Company had cash and cash equivalents of $3,885 million, and total debt of $3,148 million. At December 31, 2013, cash and cash equivalents were $3,436 million and total debt was $3,150 million. A significant portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. Of the $3,885 million of cash and cash equivalents at June 30, 2014, approximately $3,628 million is held outside the U.S. If opportunities to invest in the U.S. are greater than available cash balances, rather than repatriating this cash, the Company may choose to borrow against its revolving credit facility or its commercial paper program.

The Company’s outstanding debt at June 30, 2014 was $3,148 million and consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,396 million in 2.60% Senior Notes, $1,096 million in 3.95% Senior Notes, and other debt of $5 million.

At June 30, 2014, the Company had no commercial paper borrowings and no borrowings against its $3.5 billion revolving credit facility. Funds available under the Company’s revolving credit facility were $2,369 million due to $1,131 million in outstanding letters of credit issued under the facility.

The Company also had $3,150 million of additional outstanding letters of credit at June 30, 2014, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds, advanced payment bonds and performance bonds.

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

|  | Six Months Ended June 30, |
|  | 2014 |  |  | 2013 |
Net cash provided by continuing operating activities |  | $ | 1,270 |  |  | $ | 739 |
Net cash used in continuing investing activities |  |  | (642 | ) |  |  | (2,628 | )
Net cash provided by (used in) continuing financing |  |  | (263 | ) |  |  | 828 |

Operating Activities

For the first six months of 2014, cash provided by continuing operating activities was $1,270 million compared to $739 million in the same period of 2013. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by continuing operations primarily through net income from continuing operation of $1,157 million plus non-cash charges of $324 million, plus $73 million in a dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $33 million in equity income.

Net changes in operating assets and liabilities, net of acquisitions, used $378 million for the first six months of 2014 compared to $515 million used in the same period in 2013. This decrease in the first six months of 2014 compared to the same period in 2013 was primarily the result of prepayments and milestone invoicing on major projects outpaced costs incurred offset by higher accounts receivable and inventory.

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Investing Activities

For the first six months of 2014, net cash used in continuing investing activities was $642 million compared to $2,628 million for the same period of 2013. Net cash used in continuing investing activities continued to be the result of acquisition activity as well as capital expenditures. The Company used approximately $102 million for acquisitions in the first six months of 2014, a significant decrease compared to approximately $2.4 billion for the purpose of acquiring Robbins & Myers during the first six months of 2013. Capital expenditures however increased to $300 million during the first six months of 2013 compared to $284 million during the first six months of 2013. In addition, the Company’s cash and cash equivalents decreased $253 million during the first six months of 2014 as a result of the spin-off of its distribution business.

Financing Activities

For the first six months of 2014, net cash used in continuing financing activities was $263 million compared to net cash provided by continuing financing activities of $828 million for the same period of 2013. The change was primarily due to decreased borrowing from $1,556 million during the first half of 2013 to $151 million during the same time period this year. In addition, dividends payments increased to $309 million during the first six months of 2014 from $167 million during the first six months of 2013. The change was partially offset by decreased repayment of debt of $151 million during the first half of 2014, from $586 million during the same time period of 2013.

Other

The effect of the change in exchange rates on cash flows was a positive $7 million and negative $26 million for the first six months of 2014 and 2013, respectively.

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

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

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board issued Accounting Standard Update No. 2014-08 “Reporting Discontinued Operations and Disclosures of Disposals of Components of and Entity” (ASU No. 2014-08), which is an update for Accounting Standards Codification Topic No. 205 “Presentation of Financial Statements” and Topic No. 360 “Property, Plant and Equipment’. This update changes the requirements of reporting discontinued operations. Under the amended guidance, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update are effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Although early adoption is permitted, the Company did not elect to apply the guidance of ASU No. 2014-08 to the spin-off of NOW. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements. The Company is currently assessing the impact of ASU No. 2014-08 on its consolidated financial position and results of operations.

In May 2014, the FASB issued Accounting Standard Update No. 2014-09 “Revenue from Contracts with Customers” (ASU No. 2014-09), which supersedes the revenue recognition requirements in Accounting Standard Codification Topic No. 605 “Revenue Recognition” and most industry-specific guidance. This update requires that entities recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. ASU No. 2014-09 is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. The Company is currently assessing the impact of the adoption of ASU No. 2014-09 on its consolidated financial position and results of operations.

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Forward-Looking Statements

Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward-looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products, difficulties encountered in integrating mergers and acquisitions, and worldwide economic activity. You should also consider carefully the statements under “Risk Factors,” as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

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Item 3. | Quantitative and Qualitative Disclosures About Market Risk

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

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. We recorded a foreign exchange gain in our income statement of approximately $1 million in the first six months of 2014, compared to a $19 million foreign exchange loss in the same period of the prior year. The gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

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

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods at June 30, 2014 (in millions, except contract rates):

|  |  |  | As of June 30, 2014 |  |  | December 31, 2013 |
Functional Currency |  | 2014 |  |  | 2015 |  |  | 2016 |  |  | Total |  |
CAD |  | Buy USD/Sell CAD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in Canadian dollars) |  |  | 156 |  |  |  | — |  |  |  | — |  |  |  | 156 |  |  |  | 229 |
|  | Average USD to CAD contract rate |  |  | 1.0909 |  |  |  | — |  |  |  | — |  |  |  | 1.0909 |  |  |  | 1.0669 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | (3 | ) |  |  | — |  |  |  | — |  |  |  | (3 | ) |  |  | 1 |
|  | Sell USD/Buy CAD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to sell (in Canadian dollars) |  |  | 163 |  |  |  | 76 |  |  |  | — |  |  |  | 239 |  |  |  | 51 |
|  | Average USD to CAD contract rate |  |  | 1.1064 |  |  |  | 1.1180 |  |  |  | — |  |  |  | 1.1101 |  |  |  | 1.0230 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 5 |  |  |  | 3 |  |  |  | — |  |  |  | 8 |  |  |  | (1 | )
EUR |  | Buy USD/Sell EUR: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in euros) |  |  | 5 |  |  |  | — |  |  |  | — |  |  |  | 5 |  |  |  | 9 |
|  | Average USD to EUR contract rate |  |  | 0.7333 |  |  |  | 0.7405 |  |  |  | — |  |  |  | 0.7338 |  |  |  | 7.5900 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1 |
|  | Sell USD/Buy EUR: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in euros) |  |  | 322 |  |  |  | 47 |  |  |  | — |  |  |  | 369 |  |  |  | 344 |
|  | Average USD to EUR contract rate |  |  | 0.7393 |  |  |  | 0.7328 |  |  |  | — |  |  |  | 0.7385 |  |  |  | 0.7401 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 4 |  |  |  | — |  |  |  | — |  |  |  | 4 |  |  |  | 9 |
KRW |  | Sell USD/Buy KRW: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in South Korean won) |  |  | 130,842 |  |  |  | — |  |  |  | — |  |  |  | 130,842 |  |  |  | 195,020 |
|  | Average USD to KRW contract rate |  |  | 1,022 |  |  |  | — |  |  |  | — |  |  |  | 1,022 |  |  |  | 1,114 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | 10 |

35

|  |  |  | As of June 30, 2014 |  |  | December 31, |
Functional Currency |  | 2014 |  |  | 2015 |  |  | 2016 |  |  | Total |  |  | 2013 |
GBP |  | Buy USD/Sell GBP: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in British Pounds Sterling) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 11 |
|  | Average USD to GBP contract rate |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.6142 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Sell USD/Buy GBP: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in British Pounds Sterling) |  |  | 96 |  |  |  | 17 |  |  |  | — |  |  |  | 113 |  |  |  | 73 |
|  | Average USD to GBP contract rate |  |  | 0.6031 |  |  |  | 0.6050 |  |  |  | — |  |  |  | 0.6034 |  |  |  | 0.6201 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 4 |  |  |  | 1 |  |  |  | — |  |  |  | 5 |  |  |  | 2 |
USD |  | Buy CAD/Sell USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 7 |  |  |  | 9 |  |  |  | — |  |  |  | 16 |  |  |  | 15 |
|  | Average CAD to USD contract rate |  |  | 0.9355 |  |  |  | 0.9399 |  |  |  | — |  |  |  | 0.9381 |  |  |  | 0.9431 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | (1 | ) |  |  | — |  |  |  | (1 | ) |  |  | — |
|  | Buy DKK/Sell USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 38 |  |  |  | 40 |  |  |  | 2 |  |  |  | 80 |  |  |  | 71 |
|  | Average DKK to USD contract rate |  |  | 0.1830 |  |  |  | 0.1842 |  |  |  | 0.1841 |  |  |  | 0.1836 |  |  |  | 0.1813 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1 |
|  | Buy EUR/Sell USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 437 |  |  |  | 427 |  |  |  | 51 |  |  |  | 915 |  |  |  | 773 |
|  | Average EUR to USD contract rate |  |  | 1.3511 |  |  |  | 1.3659 |  |  |  | 1.3825 |  |  |  | 1.3597 |  |  |  | 1.3411 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 5 |  |  |  | 1 |  |  |  | — |  |  |  | 6 |  |  |  | 21 |
|  | Buy GBP/Sell USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 64 |  |  |  | 21 |  |  |  | — |  |  |  | 85 |  |  |  | 42 |
|  | Average GBP to USD contract rate |  |  | 1.6436 |  |  |  | 1.6264 |  |  |  | — |  |  |  | 1.6392 |  |  |  | 1.5779 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 2 |  |  |  | 1 |  |  |  | — |  |  |  | 3 |  |  |  | 1 |
|  | Buy NOK/Sell USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 724 |  |  |  | 936 |  |  |  | 316 |  |  |  | 1,976 |  |  |  | 1,877 |
|  | Average NOK to USD contract rate |  |  | 0.1653 |  |  |  | 0.1628 |  |  |  | 0.1612 |  |  |  | 0.1634 |  |  |  | 0.1642 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | (11 | ) |  |  | (7 | ) |  |  | (1 | ) |  |  | (19 | ) |  |  | (28 | )
|  | Buy MXN/Sell USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 19 |  |  |  | — |  |  |  | — |  |  |  | 19 |  |  |  | — |
|  | Average MXN to USD contract rate |  |  | 0.0752 |  |  |  | — |  |  |  | — |  |  |  | 0.0752 |  |  |  | — |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Buy SGD/Sell USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 30 |  |  |  | 7 |  |  |  | 3 |  |  |  | 40 |  |  |  | 15 |
|  | Average SGD to USD contract rate |  |  | 0.7959 |  |  |  | 0.7966 |  |  |  | 0.7954 |  |  |  | 0.7960 |  |  |  | 0.7966 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Sell BRL/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 19 |  |  |  | — |  |  |  | — |  |  |  | 19 |  |  |  | — |
|  | Average BRL to USD contract rate |  |  | 0.4294 |  |  |  | — |  |  |  | — |  |  |  | 0.4294 |  |  |  | — |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | (1 | ) |  |  | — |
|  | Sell CAD/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | 2 |
|  | Average CAD to USD contract rate |  |  | 0.9508 |  |  |  | — |  |  |  | — |  |  |  | 0.9058 |  |  |  | 1.3625 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Sell DKK/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 23 |  |  |  | — |  |  |  | — |  |  |  | 23 |  |  |  | 11 |
|  | Average DKK to USD contract rate |  |  | 0.1851 |  |  |  | — |  |  |  | — |  |  |  | 0.1851 |  |  |  | 1.3625 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Sell EUR/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to sell (in U.S. dollars) |  |  | 291 |  |  |  | 11 |  |  |  | 6 |  |  |  | 308 |  |  |  | 190 |
|  | Average EUR to USD contract rate |  |  | 1.3602 |  |  |  | 1.3734 |  |  |  | 1.3772 |  |  |  | 1.3610 |  |  |  | 1.3109 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | (1 | ) |  |  | (2 | )
|  | Sell GBP/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to sell (in U.S. dollars) |  |  | 15 |  |  |  | — |  |  |  | — |  |  |  | 15 |  |  |  | — |
|  | Average GBP to USD contract rate |  |  | 1.6462 |  |  |  | — |  |  |  | — |  |  |  | 1.6462 |  |  |  | — |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | (1 | ) |  |  | — |

36

|  |  |  | As of June 30, 2014 |  |  | December 31, |
Functional Currency |  | 2014 |  |  | 2015 |  |  | 2016 |  |  | Total |  |  | 2013 |
|  | Sell NOK/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to sell (in U.S. dollars) |  |  | 274 |  |  |  | 127 |  |  |  | 29 |  |  |  | 430 |  |  |  | 385 |
|  | Average NOK to USD contract rate |  |  | 0.1669 |  |  |  | 0.1626 |  |  |  | 0.1644 |  |  |  | 0.1654 |  |  |  | 0.1634 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 6 |  |  |  | 1 |  |  |  | 1 |  |  |  | 8 |  |  |  | 6 |
|  | Sell SGD/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | 1 |
|  | Average SGD to USD contract rate |  |  | 0.7986 |  |  |  | — |  |  |  | — |  |  |  | 0.7986 |  |  |  | 0.8000 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Sell RUB/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 49 |  |  |  | — |  |  |  | — |  |  |  | 49 |  |  |  | 64 |
|  | Average RUB to USD contract rate |  |  | 0.0290 |  |  |  | — |  |  |  | — |  |  |  | 0.0290 |  |  |  | 0.0298 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1 | )
|  | Sell SEK/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 1 |  |  |  | — |  |  |  | — |  |  |  | 1 |  |  |  | 1 |
|  | Average SEK to USD contract rate |  |  | 0.1524 |  |  |  | — |  |  |  | — |  |  |  | 0.1524 |  |  |  | 0.1529 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
DKK |  | Sell DKK/Buy USD: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Notional amount to buy (in U.S. dollars) |  |  | 55 |  |  |  | — |  |  |  | — |  |  |  | 55 |  |  |  | 111 |
|  | Average DKK to USD contract rate |  |  | 5.4762 |  |  |  | — |  |  |  | — |  |  |  | 5.4762 |  |  |  | 5.6126 |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Other Currencies |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Fair Value at June 30, 2014 in U.S. dollars |  |  | 3 |  |  |  | — |  |  |  | (1 | ) |  |  | 2 |  |  |  | (1 | )
Total Fair Value at June 30, 2014 in U.S. dollars |  |  | 13 |  |  |  | (1 | ) |  |  | (1 | ) |  |  | 11 |  |  |  | 19 |

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $812 million and translation exposures totaling $446 million as of June 30, 2014 excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on the transactional exposures financial market risk sensitive instruments could affect net income by $53 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $45 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 June 30, 2014, long term borrowings consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,400 million in 2.60% Senior Notes and $1,100 million in 3.95% Senior Notes, no commercial paper borrowings and no borrowings against our revolving 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 EURIBOR, 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 EURIBOR for 30 days to six months. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.

37

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.

38

PART II - OTHER INFORMATION

Item 4. | Mine Safety Disclosures

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

Item 6. | Exhibits

Reference is hereby made to the Exhibit Index commencing on page 41.

39

SIGNATURE

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

Date: August 4, 2014 |  | By: |  | /s/ Jeremy D. Thigpen
|  | Jeremy D. Thigpen
|  | Senior Vice President and Chief Financial Officer
|  | (Duly Authorized Officer, Principal Financial and Accounting Officer)

40

INDEX TO EXHIBITS

| (a) | Exhibits

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

41

10.20 |  | Second Amendment to Employment Agreement dated as of December 31, 2009 between Jeremy Thigpen and National Oilwell Varco. (Exhibit 10.3) (13)
10.21 |  | Form of Performance Award Agreement (Exhibit 10.1) (14)
31.1 |  | Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
31.2 |  | Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
32.1 |  | Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 |  | Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95 |  | Mine Safety Information persuant to section 1503 of the Dodd-Frank Act.
101 |  | The following materials from our Quarterly Report on Form 10-Q for the period ended June 30, 2014 formatted in eXtensible Business Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (15)

* | Compensatory plan or arrangement for management or others.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

42