NATIONAL OILWELL VARCO INC
10-Qs and 10-Ks
PROXIES
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
| þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011
OR
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 1-12317
NATIONAL OILWELL VARCO, INC.
(Exact name of registrant as specified in its charter)
| Delaware | 76-0475815 | |
|
(State or other jurisdiction
of incorporation or organization) |
(I.R.S. Employer
Identification No.) |
7909 Parkwood Circle Drive
Houston, Texas
77036-6565
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
þ
No
o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
þ
No
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
| (Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes
o
No
þ
As of May 2, 2011 the registrant had
423,077,225 shares of common stock, par value $.01 per share,
outstanding.
TABLE OF CONTENTS
Table of Contents
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
| March 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
| (Unaudited) | ||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 3,060 | $ | 3,333 | ||||
|
Receivables, net
|
2,757 | 2,425 | ||||||
|
Inventories, net
|
3,570 | 3,388 | ||||||
|
Costs in excess of billings
|
744 | 815 | ||||||
|
Deferred income taxes
|
297 | 316 | ||||||
|
Prepaid and other current assets
|
311 | 258 | ||||||
|
|
||||||||
|
Total current assets
|
10,739 | 10,535 | ||||||
|
|
||||||||
|
Property, plant and equipment, net
|
1,861 | 1,840 | ||||||
|
Deferred income taxes
|
158 | 341 | ||||||
|
Goodwill
|
5,908 | 5,790 | ||||||
|
Intangibles, net
|
4,026 | 4,103 | ||||||
|
Investment in unconsolidated affiliate
|
402 | 386 | ||||||
|
Other assets
|
62 | 55 | ||||||
|
|
||||||||
|
Total assets
|
$ | 23,156 | $ | 23,050 | ||||
|
|
||||||||
|
|
||||||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable
|
$ | 656 | $ | 628 | ||||
|
Accrued liabilities
|
1,989 | 2,105 | ||||||
|
Billings in excess of costs
|
571 | 511 | ||||||
|
Current portion of long-term debt and short-term borrowings
|
203 | 373 | ||||||
|
Accrued income taxes
|
284 | 468 | ||||||
|
Deferred income taxes
|
429 | 451 | ||||||
|
|
||||||||
|
Total current liabilities
|
4,132 | 4,536 | ||||||
|
|
||||||||
|
Long-term debt
|
512 | 514 | ||||||
|
Deferred income taxes
|
1,832 | 1,885 | ||||||
|
Other liabilities
|
279 | 253 | ||||||
|
|
||||||||
|
Total liabilities
|
6,755 | 7,188 | ||||||
|
|
||||||||
|
|
||||||||
|
Commitments and contingencies
|
||||||||
|
|
||||||||
|
Stockholders’ equity:
|
||||||||
|
Common stock — par value $.01; 422,957,697 and 421,141,751 shares issued
and outstanding at March 31, 2011 and December 31, 2010
|
4 | 4 | ||||||
|
Additional paid-in capital
|
8,432 | 8,353 | ||||||
|
Accumulated other comprehensive income
|
192 | 91 | ||||||
|
Retained earnings
|
7,661 | 7,300 | ||||||
|
|
||||||||
|
Total Company stockholders’ equity
|
16,289 | 15,748 | ||||||
|
Noncontrolling interests
|
112 | 114 | ||||||
|
|
||||||||
|
Total stockholders’ equity
|
16,401 | 15,862 | ||||||
|
|
||||||||
|
Total liabilities and stockholders’ equity
|
$ | 23,156 | $ | 23,050 | ||||
|
|
||||||||
See notes to unaudited consolidated financial statements.
2
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(In millions, except per share data)
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(In millions, except per share data)
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Revenue
|
$ | 3,146 | $ | 3,032 | ||||
|
Cost of revenue
|
2,171 | 2,070 | ||||||
|
|
||||||||
|
Gross profit
|
975 | 962 | ||||||
|
Selling, general and administrative
|
366 | 325 | ||||||
|
|
||||||||
|
Operating profit
|
609 | 637 | ||||||
|
Interest and financial costs
|
(14 | ) | (13 | ) | ||||
|
Interest income
|
4 | 2 | ||||||
|
Equity income in unconsolidated affiliate
|
13 | 6 | ||||||
|
Other income (expense), net
|
(19 | ) | (16 | ) | ||||
|
|
||||||||
|
Income before income taxes
|
593 | 616 | ||||||
|
Provision for income taxes
|
189 | 197 | ||||||
|
|
||||||||
|
Net income
|
404 | 419 | ||||||
|
Net loss attributable to noncontrolling interests
|
(3 | ) | (3 | ) | ||||
|
|
||||||||
|
Net income attributable to Company
|
$ | 407 | $ | 422 | ||||
|
|
||||||||
|
|
||||||||
|
Net income attributable to Company per share:
|
||||||||
|
Basic
|
$ | 0.97 | $ | 1.01 | ||||
|
|
||||||||
|
Diluted
|
$ | 0.96 | $ | 1.01 | ||||
|
|
||||||||
|
|
||||||||
|
Cash dividends per share
|
$ | 0.11 | $ | 0.10 | ||||
|
|
||||||||
|
|
||||||||
|
Weighted average shares outstanding:
|
||||||||
|
Basic
|
420 | 417 | ||||||
|
|
||||||||
|
Diluted
|
423 | 419 | ||||||
|
|
||||||||
See notes to unaudited consolidated financial statements.
3
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Cash flows from operating activities:
|
||||||||
|
Net income
|
$ | 404 | $ | 419 | ||||
|
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
|
||||||||
|
Depreciation and amortization
|
135 | 127 | ||||||
|
Deferred income taxes
|
95 | 85 | ||||||
|
Equity income in unconsolidated affiliate
|
(13 | ) | (6 | ) | ||||
|
Other, net
|
12 | 53 | ||||||
|
Change in operating assets and liabilities, net of acquisitions:
|
||||||||
|
Receivables
|
(321 | ) | 74 | |||||
|
Inventories
|
(200 | ) | 67 | |||||
|
Costs in excess of billings
|
70 | (178 | ) | |||||
|
Prepaid and other current assets
|
(51 | ) | 13 | |||||
|
Accounts payable
|
15 | (46 | ) | |||||
|
Billings in excess of costs
|
60 | (409 | ) | |||||
|
Other assets/liabilities, net
|
(231 | ) | (104 | ) | ||||
|
|
||||||||
|
Net cash (used in) provided by operating activities
|
(25 | ) | 95 | |||||
|
|
||||||||
|
|
||||||||
|
Cash flows from investing activities:
|
||||||||
|
Purchases of property, plant and equipment
|
(79 | ) | (31 | ) | ||||
|
Business acquisitions, net of cash acquired
|
(51 | ) | (46 | ) | ||||
|
Other
|
7 | 12 | ||||||
|
|
||||||||
|
Net cash used in investing activities
|
(123 | ) | (65 | ) | ||||
|
|
||||||||
|
|
||||||||
|
Cash flows from financing activities:
|
||||||||
|
Repayments on debt
|
(170 | ) | (2 | ) | ||||
|
Cash dividends paid
|
(46 | ) | (42 | ) | ||||
|
Proceeds from stock options exercised
|
58 | 5 | ||||||
|
Other, net
|
14 | 3 | ||||||
|
|
||||||||
|
Net cash used in financing activities
|
(144 | ) | (36 | ) | ||||
|
Effect of exchange rates on cash
|
19 | (8 | ) | |||||
|
|
||||||||
|
Decrease in cash and cash equivalents
|
(273 | ) | (14 | ) | ||||
|
Cash and cash equivalents, beginning of period
|
3,333 | 2,622 | ||||||
|
|
||||||||
|
Cash and cash equivalents, end of period
|
$ | 3,060 | $ | 2,608 | ||||
|
|
||||||||
|
|
||||||||
|
Supplemental disclosures of cash flow information:
|
||||||||
|
Cash payments during the period for:
|
||||||||
|
Interest
|
$ | 12 | $ | 11 | ||||
|
Income taxes
|
$ | 266 | $ | 101 | ||||
See notes to unaudited consolidated financial statements.
4
Table of Contents
NATIONAL OILWELL VARCO, INC.
Notes to Consolidated Financial Statements (Unaudited)
Notes to Consolidated Financial Statements (Unaudited)
1. Basis of Presentation
The preparation of financial statements in conformity with generally accepted accounting principles
(“GAAP”) in the United States requires management to make estimates and assumptions that affect
reported and contingent amounts of assets and liabilities as of the date of the financial
statements and reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (the
“Company”) present information in accordance with GAAP in the United States for interim financial
information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not
include all information or footnotes required by GAAP in the United States for complete
consolidated financial statements and should be read in conjunction with our 2010 Annual Report on
Form 10-K.
In our opinion, the consolidated financial statements include all adjustments, all of which are of
a normal recurring nature, necessary for a fair presentation of the results for the interim
periods. The results of operations for the three months ended March 31, 2011 are not necessarily
indicative of the results to be expected for the full year.
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, receivables, and
payables approximated fair value because of the relatively short maturity of these instruments.
Cash equivalents include only those investments having a maturity date of three months or less at
the time of purchase. The carrying values of other financial instruments approximate their
respective fair values.
2. Inventories, net
Inventories consist of (in millions):
| March 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
|
Raw materials and supplies
|
$ | 721 | $ | 661 | ||||
|
Work in process
|
1,092 | 953 | ||||||
|
Finished goods and purchased products
|
1,757 | 1,774 | ||||||
|
|
||||||||
|
Total
|
$ | 3,570 | $ | 3,388 | ||||
|
|
||||||||
5
Table of Contents
3. Accrued Liabilities
Accrued liabilities consist of (in millions):
| March 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
|
Accrued purchase orders
|
$ | 601 | $ | 597 | ||||
|
Customer prepayments and billings
|
491 | 387 | ||||||
|
Compensation
|
263 | 403 | ||||||
|
Warranty
|
213 | 215 | ||||||
|
Taxes (non income)
|
68 | 93 | ||||||
|
Insurance
|
50 | 49 | ||||||
|
Fair value of derivatives
|
22 | 22 | ||||||
|
Interest
|
14 | 11 | ||||||
|
Other
|
267 | 328 | ||||||
|
|
||||||||
|
Total
|
$ | 1,989 | $ | 2,105 | ||||
|
|
||||||||
Service and Product Warranties
The Company provides service and warranty policies on certain of its products. The Company accrues
liabilities under service and warranty policies based upon specific claims and a review of
historical warranty and service claim experience in accordance with Accounting Standards
Codification (“ASC”) Topic 450 “Contingencies” (“ASC Topic 450”). Adjustments are made to accruals
as claim data and historical experience change. In addition, the Company incurs discretionary costs
to service its products in connection with product performance issues and accrues for them when
they are encountered.
The changes in the carrying amount of service and product warranties are as follows (in millions):
|
Balance at December 31, 2010
|
$ | 215 | ||
|
|
||||
|
Net provisions for warranties issued during the year
|
6 | |||
|
Amounts incurred
|
(9 | ) | ||
|
Foreign currency translation and other
|
1 | |||
|
|
||||
|
Balance at March 31, 2011
|
$ | 213 | ||
|
|
||||
4. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
| March 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
|
Costs incurred on uncompleted contracts
|
$ | 6,408 | $ | 6,676 | ||||
|
Estimated earnings
|
4,633 | 4,665 | ||||||
|
|
||||||||
|
|
11,041 | 11,341 | ||||||
|
Less: Billings to date
|
10,868 | 11,037 | ||||||
|
|
||||||||
|
|
$ | 173 | $ | 304 | ||||
|
|
||||||||
|
|
||||||||
|
Costs and estimated earnings in excess of billings on uncompleted contracts
|
$ | 744 | $ | 815 | ||||
|
Billings in excess of costs and estimated earnings on uncompleted contracts
|
(571 | ) | (511 | ) | ||||
|
|
||||||||
|
|
$ | 173 | $ | 304 | ||||
|
|
||||||||
6
Table of Contents
5. Comprehensive Income
The components of comprehensive income are as follows (in millions):
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Net income
|
$ | 404 | $ | 419 | ||||
|
Currency translation adjustments
|
64 | (14 | ) | |||||
|
Changes in derivative financial instruments, net of tax
|
37 | (26 | ) | |||||
|
|
||||||||
|
Comprehensive income
|
505 | 379 | ||||||
|
Comprehensive loss attributable to noncontrolling interest
|
(3 | ) | (3 | ) | ||||
|
|
||||||||
|
Comprehensive income attributable to Company
|
$ | 508 | $ | 382 | ||||
|
|
||||||||
The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international
entities in which there is a substantial investment have the local currency as their functional
currency. As a result, translation adjustments resulting from the process of translating the
entities’ financial statements into the reporting currency are reported in Other Comprehensive
Income in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the three
months ended March 31, 2011, a majority of these local currencies strengthened against the U.S.
dollar resulting in a net increase to Other Comprehensive Income of $64 million upon the
translation of their financial statements from their local currency to the U.S. dollar.
The effect of changes in the fair values of derivatives designated as cash flow hedges are
accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which
they are designed to hedge are realized. The movement in Other Comprehensive Income from period to
period will be the result of the combination of changes in fair value for open derivatives and the
outflow of accumulated Other Comprehensive Income related to the fair value of derivatives that
have settled in the current or prior periods. The accumulated effect is an increase in Other
Comprehensive Income of $37 million (net of tax of $14 million) for the three months ended March
31, 2011.
7
Table of Contents
6. Business Segments
Operating results by segment are as follows (in millions):
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Revenue:
|
||||||||
|
Rig Technology
|
$ | 1,608 | $ | 1,886 | ||||
|
Petroleum Services & Supplies
|
1,265 | 923 | ||||||
|
Distribution Services
|
410 | 334 | ||||||
|
Elimination
|
(137 | ) | (111 | ) | ||||
|
|
||||||||
|
Total Revenue
|
$ | 3,146 | $ | 3,032 | ||||
|
|
||||||||
|
|
||||||||
|
Operating Profit:
|
||||||||
|
Rig Technology
|
$ | 419 | $ | 581 | ||||
|
Petroleum Services & Supplies
|
231 | 113 | ||||||
|
Distribution Services
|
27 | 11 | ||||||
|
Unallocated expenses and eliminations
|
(68 | ) | (68 | ) | ||||
|
|
||||||||
|
Total Operating Profit
|
$ | 609 | $ | 637 | ||||
|
|
||||||||
|
|
||||||||
|
Operating Profit %:
|
||||||||
|
Rig Technology
|
26.1 | % | 30.8 | % | ||||
|
Petroleum Services & Supplies
|
18.3 | % | 12.2 | % | ||||
|
Distribution Services
|
6.6 | % | 3.3 | % | ||||
|
Total Operating Profit %
|
19.4 | % | 21.0 | % | ||||
The Company had revenues of 12% and 21% of total revenue from one of its customers for the three
months ended March 31, 2011 and 2010, respectively. This customer, Samsung Heavy Industries, is a
shipyard acting as a general contractor for its customers, who are drillship owners and drilling
contractors. This shipyard’s customers have specified that the Company’s drilling equipment be
installed on their drillships and have required the shipyard to issue contracts to the Company.
8
Table of Contents
7. Debt
Debt consists of (in millions):
| March 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
|
Senior Notes, interest at 6.5% payable semiannually,
principal due on March 15, 2011
|
$ | — | $ | 150 | ||||
|
Senior Notes, interest at 7.25% payable semiannually,
principal due on May 1, 2011
|
200 | 201 | ||||||
|
Senior Notes, interest at 5.65% payable semiannually,
principal due on November 15, 2012
|
200 | 200 | ||||||
|
Senior Notes, interest at 5.5% payable semiannually,
principal due on November 19, 2012
|
150 | 151 | ||||||
|
Senior Notes, interest at 6.125% payable semiannually,
principal due on August 15, 2015
|
151 | 151 | ||||||
|
Other
|
14 | 34 | ||||||
|
|
||||||||
|
Total debt
|
715 | 887 | ||||||
|
Less current portion
|
203 | 373 | ||||||
|
|
||||||||
|
Long-term debt
|
$ | 512 | $ | 514 | ||||
|
|
||||||||
Senior Notes
On March 15, 2011, the Company repaid $150 million of its 6.5% unsecured Senior Notes using
available cash balances. The remaining Senior Notes contain reporting covenants, and the Company was in
compliance at March 31, 2011.
Revolving Credit Facilities
On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit
facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to
finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2
billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility
which was terminated early in February 2009. At March 31, 2011 there were no borrowings against the
remaining credit facility, and there were $429 million in outstanding letters of credit issued
under this facility, resulting in $1,571 million of funds available under this revolving credit
facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus
0.26% subject to a ratings-based grid, or the prime rate.
The Company also had $1,479 million of additional outstanding letters of credit at March 31, 2011,
primarily in Norway, that are essentially under various bilateral committed letter of credit
facilities. Other letters of credit are issued as bid bonds and performance bonds. The credit
facility contains a financial covenant regarding maximum debt to capitalization. The Company was
in compliance with all covenants regarding its credit facility at March 31, 2011.
9
Table of Contents
8. Tax
The effective tax rate for the three months ended March 31, 2011 was 31.9% compared to 32.0% for
the same period in 2010. The effective tax rate was positively impacted in the period by the
effect of tax rate reductions on timing differences in foreign jurisdictions and an increase in the
benefit of the manufacturing deduction as a result of increasing income in the U.S. This was
offset by a reduction in the benefit of lower foreign tax rates as a result of decreasing income in
foreign jurisdictions.
The difference between the effective tax rate reflected in the provision for income taxes and the
U.S. federal statutory rate of 35% was as follows (in millions):
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Federal income tax at U.S. federal statutory rate
|
$ | 208 | $ | 216 | ||||
|
Foreign income tax rate differential
|
(24 | ) | (40 | ) | ||||
|
State income tax, net of federal benefit
|
6 | 2 | ||||||
|
Nondeductible expenses
|
10 | 19 | ||||||
|
Tax benefit of manufacturing deduction
|
(6 | ) | (3 | ) | ||||
|
Foreign dividends, net of foreign tax credits
|
5 | 1 | ||||||
|
Tax rate change on temporary differences
|
(13 | ) | — | |||||
|
Change in contingency reserve and other
|
3 | 2 | ||||||
|
|
||||||||
|
Provision for income taxes
|
$ | 189 | $ | 197 | ||||
|
|
||||||||
The balance of unrecognized tax benefits at March 31, 2011 was $117 million. The Company recognized
no material changes in the balance of unrecognized tax benefits for the three month period ended
March 31, 2011.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in
millions):
|
Balance at December 31, 2010
|
$ | 118 | ||
|
|
||||
|
Settlements
|
(1 | ) | ||
|
|
||||
|
Balance at March 31, 2011
|
$ | 117 | ||
|
|
||||
The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The
Company has significant operations in the U.S., Canada, the U.K., the Netherlands and Norway. Tax
years that remain subject to examination by major tax jurisdiction vary by legal entity, but are
generally open in the U.S. for the tax years after 2006 and outside the U.S. for tax years ending
after 2004.
The Company does not anticipate that its total unrecognized tax benefits will significantly change
due to the settlement of audits or the expiration of statutes of limitation within 12 months of
this reporting date.
To the extent penalties and interest would be assessed on any underpayment of income tax, such
accrued amounts have been classified as a component of income tax expense in the financial
statements.
10
Table of Contents
9. Stock-Based Compensation
The Company has a stock-based compensation plan known as the National Oilwell Varco, Inc. Long-Term
Incentive Plan (the “Plan”). The Plan provides for the granting of stock options,
performance-based share awards, restricted stock, phantom shares, stock payments and stock
appreciation rights. The number of shares authorized under the Plan is 25.5 million. As of March
31, 2011, 5,594,202 shares remain available for future grants under the Plan, all of which are
available for grants of stock options, performance-based share awards, restricted stock awards,
phantom shares, stock payments and stock appreciation rights. Total stock-based compensation for
all stock-based compensation arrangements under the Plan was
$17 million for each of the three months
ended March 31, 2011 and 2010. The total income tax benefit recognized in the Consolidated
Statements of Income for all stock-based compensation arrangements under the Plan was $5 million
for each of the three months ended March 31, 2011 and 2010.
During the three months ended March 31, 2011, the Company granted 2,255,322 stock options and
365,920 shares of restricted stock and restricted stock units, which includes 131,300 performance-based restricted stock
awards. The stock options were granted February 22, 2011 with an exercise price of $79.80. These
options generally vest over a three-year period from the grant date. The restricted stock
and restricted stock unit awards
were granted February 22, 2011 and vest on the third anniversary of the date of grant. The
performance-based restricted stock awards were granted February 22, 2011. The performance-based
restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to
the performance condition of the Company’s operating income growth, measured on a
percentage basis, from January 1, 2011 through December 31, 2013 exceeding the median operating
income level growth of a designated peer group over the same period.
10. Derivative Financial Instruments
ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires companies to recognize all of
its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at
fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative
instrument depends on whether it has been designated and qualifies as part of a hedging
relationship and further, on the type of hedging relationship. For those derivative instruments
that are designated and qualify as hedging instruments, a company must designate the hedging
instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a
hedge of a net investment in a foreign operation.
The Company is exposed to certain risks relating to its ongoing business operations. The primary
risks managed by using derivative instruments are foreign currency exchange rate risk and interest
rate risk. Forward contracts against various foreign currencies are entered into to manage the
foreign currency exchange rate risk on forecasted revenue and expenses denominated in currencies
other than the functional currency of the operating unit (cash flow hedge). Other forward exchange
contracts against various foreign currencies are entered into to manage the foreign currency
exchange rate risk associated with certain firm commitments denominated in currencies other than
the functional currency of the operating unit (fair value hedge). In addition, the Company will
enter into non-designated forward contracts against various foreign currencies to manage the
foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts
(non-designated hedge). Interest rate swaps are entered into to manage interest rate risk
associated with the Company’s fixed and floating-rate borrowings.
The Company records all derivative financial instruments at their fair value in its Consolidated
Balance Sheet. Except for certain non-designated hedges discussed below, all derivative financial
instruments that the Company holds are designated as either cash flow or fair value hedges and are
highly effective in offsetting movements in the underlying risks. Such arrangements typically have
terms between two and 24 months, but may have longer terms depending on the underlying cash flows
being hedged, typically related to the projects in our backlog. The Company may also use interest
rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt
issuances.
At March 31, 2011, the Company has determined that its financial assets of $90 million and
liabilities of $23 million (primarily currency related derivatives) are level 2 in the fair value
hierarchy. At March 31, 2011, the net fair value of the Company’s foreign currency forward
contracts totaled an asset of $67 million.
As of March 31, 2011, the Company did not have any interest rate swaps and its financial
instruments do not contain any credit-risk-related or other contingent features that could cause
accelerated payments when the Company’s financial instruments are in net liability positions. We do
not use derivative financial instruments for trading or speculative purposes.
11
Table of Contents
Cash Flow Hedging Strategy
For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the
exposure to variability in expected future cash flows that is subject to a particular currency
risk), the effective portion of the gain or loss on the derivative instrument is reported as a
component of Other Comprehensive Income and reclassified into earnings in the same line item
associated with the forecasted transaction and in the same period or periods during which the
hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are cash
flows associated with forecasted revenues). The remaining gain or loss on the derivative
instrument in excess of the cumulative change in the present value of future cash flows of the
hedged item, if any (i.e. the ineffective portion), or hedge components excluded from the
assessment of effectiveness, are recognized in the Consolidated Statements of Income during the
current period.
To protect against the volatility of forecasted foreign currency cash flows resulting from
forecasted sales and expenses, the Company has instituted a cash flow hedging program. The Company
hedges portions of its forecasted revenues and expenses denominated in nonfunctional currencies
with forward contracts. When the U.S. dollar strengthens against the foreign currencies, the
decrease in present value of future foreign currency revenue and costs is offset by gains in the
fair value of the forward contracts designated as hedges. Conversely, when the U.S. dollar
weakens, the increase in the present value of future foreign currency cash flows is offset by
losses in the fair value of the forward contracts.
As of March 31, 2011, the Company had the following outstanding foreign currency forward contracts
that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and
costs (in millions):
| Currency Denomination | ||||||||||||
| March 31, | ||||||||||||
| Foreign Currency | 2011 | 2010 | ||||||||||
|
British Pound Sterling
|
£ | 20 | £ | 30 | ||||||||
|
Danish Krone
|
DKK | 21 | DKK | 106 | ||||||||
|
Euro
|
€ | 165 | € | 143 | ||||||||
|
Norwegian Krone
|
NOK | 5,062 | NOK | 6,307 | ||||||||
|
U.S. Dollar
|
$ | 334 | $ | 264 | ||||||||
|
Japanese Yen
|
¥ | 122 | ¥ | — | ||||||||
|
Singapore Dollar
|
SGD | 7 | SGD | — | ||||||||
|
Swedish Krone
|
SEK | 55 | SEK | — | ||||||||
|
Canadian Dollar
|
CAD | 1 | CAD | — | ||||||||
Fair Value Hedging Strategy
For derivative instruments that are designated and qualify as a fair value hedge (i.e., hedging the
exposure to changes in the fair value of an asset or a liability or an identified portion thereof
that is subject to a particular risk), the gain or loss on the derivative instrument as well as the
offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the
same line item associated with the hedged item in current earnings (e.g., in “revenue” when the
hedged item is a contracted sale).
The Company enters into forward exchange contracts to hedge certain firm commitments of revenue and
costs that are denominated in currencies other than the functional currency of the operating unit.
The purpose of the Company’s foreign currency hedging activities is to protect the Company from
risk that the eventual U.S. dollar-equivalent cash flows from the sale of products to customers
will be adversely affected by changes in the exchange rates.
As of March 31, 2011, the Company had the following outstanding foreign currency forward contracts
that were entered into to hedge nonfunctional currency fair values of firm commitments of revenues
and costs (in millions):
| Currency Denomination | ||||||||
| March 31, | ||||||||
| Foreign Currency | 2011 | 2010 | ||||||
|
U.S. Dollar
|
$ | 1 | $ | 20 | ||||
12
Table of Contents
Non-designated Hedging Strategy
For derivative instruments that are non-designated, the gain or loss on the derivative instrument
subject to the hedged risk (i.e. nonfunctional currency monetary accounts) are recognized in other
income (expense), net in current earnings.
The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary
accounts. The purpose of the Company’s foreign currency hedging activities is to protect the
Company from risk that the eventual U.S. dollar-equivalent cash flows from the nonfunctional
currency monetary accounts will be adversely affected by changes in the exchange rates.
As of March 31, 2011, the Company had the following outstanding foreign currency forward contracts
that hedge the fair value of nonfunctional currency monetary accounts (in millions):
| Currency Denomination | ||||||||||||
| March 31, | ||||||||||||
| Foreign Currency | 2011 | 2010 | ||||||||||
|
British Pound Sterling
|
£ | 20 | £ | 24 | ||||||||
|
Danish Krone
|
DKK | 146 | DKK | 174 | ||||||||
|
Euro
|
€ | 78 | € | 64 | ||||||||
|
Norwegian Krone
|
NOK | 2,043 | NOK | 3,777 | ||||||||
|
Swedish Krone
|
SEK | — | SEK | 5 | ||||||||
|
U.S. Dollar
|
$ | 430 | $ | 491 | ||||||||
|
Russian Ruble
|
RUB | 438 | RUB | 2,812 | ||||||||
|
Korean Won
|
KRW | — | KRW | 4,348 | ||||||||
|
Brazilian Real
|
BRL | 22 | BRL | — | ||||||||
|
Japanese Yen
|
¥ | 244 | ¥ | — | ||||||||
|
Singapore Dollar
|
SGD | 24 | SGD | — | ||||||||
As of March 31, 2011, the Company has the following fair values of its derivative instruments and
their balance sheet classifications (in millions):
| Asset Derivatives | Liability Derivatives | |||||||||||||||||||
| Fair Value | Fair Value | |||||||||||||||||||
| Balance Sheet | March 31, | December 31, | Balance Sheet | March 31, | December 31, | |||||||||||||||
| Location | 2011 | 2010 | Location | 2011 | 2010 | |||||||||||||||
|
Derivatives designated as hedging
instruments under ASC Topic 815
|
||||||||||||||||||||
|
Foreign exchange contracts
|
Prepaid and other | |||||||||||||||||||
|
|
current assets | $ | 56 | $ | 28 | Accrued liabilities | $ | 10 | $ | 12 | ||||||||||
|
Foreign exchange contracts
|
Other Assets | 23 | 12 | Other Liabilities | 1 | 1 | ||||||||||||||
|
|
||||||||||||||||||||
|
Total derivatives designated as
hedging
instruments under ASC Topic 815
|
$ | 79 | $ | 40 | $ | 11 | $ | 13 | ||||||||||||
|
|
||||||||||||||||||||
|
Derivatives not designated as hedging
instruments under ASC Topic 815
|
||||||||||||||||||||
|
Foreign exchange contracts
|
Prepaid and other | |||||||||||||||||||
|
|
current assets | $ | 11 | $ | 7 | Accrued liabilities | $ | 12 | $ | 10 | ||||||||||
|
|
||||||||||||||||||||
|
Total derivatives not designated as
hedging
instruments under ASC Topic 815
|
$ | 11 | $ | 7 | $ | 12 | $ | 10 | ||||||||||||
|
|
||||||||||||||||||||
|
Total derivatives
|
$ | 90 | $ | 47 | $ | 23 | $ | 23 | ||||||||||||
|
|
||||||||||||||||||||
13
Table of Contents
The
Effect of Derivative Instruments on the Consolidated Statement of
Income
($ in millions)
($ in millions)
| Location of Gain (Loss) | ||||||||||||||||||||||||||||||||
| Recognized in Income on | Amount of Gain (Loss) | |||||||||||||||||||||||||||||||
| Location of Gain (Loss) | Derivative (Ineffective | Recognized in Income on | ||||||||||||||||||||||||||||||
| Reclassified from | Amount of Gain (Loss) | Portion and Amount | Derivative (Ineffective | |||||||||||||||||||||||||||||
| Derivatives in ASC Topic 815 | Amount of Gain (Loss) | Accumulated OCI into | Reclassified from | Excluded from | Portion and Amount | |||||||||||||||||||||||||||
| Cash Flow Hedging | Recognized in OCI on | Income | Accumulated OCI into | Effectiveness | Excluded from | |||||||||||||||||||||||||||
| Relationships | Derivative (Effective Portion) (a) | (Effective Portion) | Income (Effective Portion) | Testing) | Effectiveness Testing) (b) | |||||||||||||||||||||||||||
| Three Months Ended | Three Months Ended | Three Months Ended | ||||||||||||||||||||||||||||||
| March 31, | March 31, | March 31, | ||||||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||
|
|
Revenue | 1 | 7 | |||||||||||||||||||||||||||||
|
Foreign exchange contracts
|
55 | (34 | ) | Cost of revenue | 4 | (6 | ) | Other income (expense), net | (3 | ) | 5 | |||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Total
|
55 | (34 | ) | 5 | 1 | (3 | ) | 5 | ||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Derivatives in ASC Topic 815 | Location of Gain (Loss) | Amount of Gain (Loss) | ASC Topic 815 | Location of Gain (Loss) | Recognized in Income on | |||||||||||||||||||||||||||
| Fair Value | Recognized in Income | Recognized in Income on | Fair Value Hedge | Recognized in Income on | Related Hedged | |||||||||||||||||||||||||||
| Hedging Relationships | on Derivative | Derivative | Relationships | Related Hedged Item | Items | |||||||||||||||||||||||||||
| Three Months Ended | Three Months Ended | |||||||||||||||||||||||||||||||
| March 31, | March 31, | |||||||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||||
|
Foreign exchange contracts
|
Revenue | — | (1 | ) | Firm commitments | Revenue | — | 1 | ||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Total
|
— | (1 | ) | — | 1 | |||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| Derivatives Not Designated as | Location of Gain (Loss) | Amount of Gain (Loss) | ||||||||
| Hedging Instruments under | Recognized in Income | Recognized in Income on | ||||||||
| ASC Topic 815 | on Derivative | Derivative | ||||||||
| Three Months Ended | ||||||||||
| March 31, | ||||||||||
| 2011 | 2010 | |||||||||
|
Foreign exchange contracts
|
Other income (expense), net | (11 | ) | (1 | ) | |||||
|
|
||||||||||
|
Total
|
(11 | ) | (1 | ) | ||||||
|
|
||||||||||
| (a) | The Company expects that $(34) 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 $(3) million and $5 million related to the ineffective portion of the hedging relationships for the three months ended March 31, 2011 and 2010, respectively, and $(4) million and $4 million related to the amount excluded from the assessment of the hedge effectiveness for the three months ended March 31, 2011 and 2010, respectively. |
14
Table of Contents
11. Net Income Attributable to Company Per Share
The following table sets forth the computation of weighted average basic and diluted shares
outstanding (in millions, except per share data):
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Numerator:
|
||||||||
|
Net income attributable to Company
|
$ | 407 | $ | 422 | ||||
|
|
||||||||
|
Denominator:
|
||||||||
|
Basic—weighted average common shares outstanding
|
420 | 417 | ||||||
|
Dilutive effect of employee stock options and
other unvested stock awards
|
3 | 2 | ||||||
|
|
||||||||
|
Diluted outstanding shares
|
423 | 419 | ||||||
|
|
||||||||
|
|
||||||||
|
Net income attributable to Company per share:
|
||||||||
|
Basic
|
$ | 0.97 | $ | 1.01 | ||||
|
|
||||||||
|
Diluted
|
$ | 0.96 | $ | 1.01 | ||||
|
|
||||||||
|
Cash dividends per share
|
$ | 0.11 | $ | 0.10 | ||||
|
|
||||||||
In addition, the Company had stock options outstanding that were anti-dilutive totaling 3 million
and 6 million shares for the three months ended March 31, 2011 and 2010, respectively.
12. Cash Dividends
On February 23, 2011 the Company’s Board of Directors approved a cash dividend of $0.11 per share.
The cash dividend was paid on March 25, 2011 to each stockholder of record on March 11, 2011. Cash
dividends aggregated $46 million and $42 million for the three months ended March 31, 2011 and
2010, respectively. The declaration and payment of future dividends is at the discretion of the
Company’s Board of Directors and will be dependent upon the Company’s results of operations,
financial condition, capital requirements and other factors deemed relevant by the Company’s Board
of Directors.
15
Table of Contents
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 are presented in accordance with accounting
principles generally accepted in the United States (“GAAP”). In an effort to provide investors with
additional information regarding our results of operations, certain non-GAAP financial measures,
including operating profit excluding other costs, operating profit percentage excluding other costs
and diluted earnings per share excluding other costs, are provided. See Non-GAAP Financial Measures
and Reconciliations in Results of Operations for an explanation of our use of non-GAAP financial
measures and reconciliations to their corresponding measures calculated in accordance with GAAP.
Rig Technology
Our Rig Technology segment designs, manufactures, sells and services complete systems for the
drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line
of highly-engineered equipment that automates complex well construction and management operations,
such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly
systems; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well
workover rigs; wireline winches; wireline trucks; cranes; and turret mooring systems and other
products for Floating Production, Storage and Offloading vessels (“FPSOs”) and other offshore
vessels and terminals. Demand for Rig Technology products is primarily dependent on capital
spending plans by drilling contractors, oilfield service companies, and oil and gas companies; and
secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts
for the segment’s large installed base of equipment. We have made strategic acquisitions and other
investments during the past several years in an effort to expand our product offering and our
global manufacturing capabilities, including adding additional operations in the United States,
Canada, Norway, the United Kingdom, Brazil, China, Belarus, India, Turkey, the Netherlands,
Singapore, and South Korea.
Petroleum Services & Supplies
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used
to drill, complete, remediate and workover oil and gas wells and service flowlines and
other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and
equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer
pumps, solids control systems, drilling motors, drilling fluids, drill bits, reamers and other
downhole tools, and mud pump consumables. Demand for these services and supplies is determined
principally by the level of oilfield drilling and workover activity by drilling contractors, major
and independent oil and gas companies, and national oil companies. Oilfield tubular services
include the provision of inspection and internal coating services and equipment for drill pipe,
line pipe, tubing, and casing; and the design, manufacture and sale of coiled tubing pipe
and advanced composite pipe for application in highly corrosive environments. The segment sells its
tubular goods and services to oil and gas companies; drilling contractors; pipe distributors,
processors and manufacturers; and pipeline operators. This segment has benefited from several
strategic acquisitions and other investments completed during the past few years, including
additional operations in the United States, Canada, the United Kingdom, Brazil, China, Kazakhstan,
Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, and the
United Arab Emirates.
Distribution Services
Our Distribution Services segment provides maintenance, repair and operating supplies (“MRO”) and
spare parts to drill site and production locations worldwide. In addition to its comprehensive
network of field locations supporting land drilling operations throughout North America, the
segment supports major offshore drilling contractors through locations in Mexico, the Middle East,
Europe, Southeast Asia and South America. Distribution Services employs advanced information
technologies to provide complete procurement, inventory management and logistics services to its
customers around the globe. Demand for the segment’s services is determined primarily by the level
of drilling, servicing, and oil and gas production activities.
Critical Accounting Estimates
In our annual report on Form 10-K for the year ended December 31, 2010, we identified our most
critical accounting policies. In preparing the financial statements, we make assumptions, estimates
and judgments that affect the amounts reported. We periodically evaluate our estimates and
judgments that are most critical in nature which are related to revenue recognition under long-term
construction contracts; allowance for doubtful accounts; inventory reserves; impairments of
long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and
other indefinite-lived intangible assets; service and product warranties and income taxes. Our
estimates are based on historical experience and on our future expectations that we believe are
reasonable. The combination of these factors forms the basis for making judgments about the
carrying values of
assets and liabilities that are not readily apparent from other sources. Actual results are likely
to differ from our current estimates and those differences may be material.
16
Table of Contents
EXECUTIVE SUMMARY
National Oilwell Varco generated $407 million in net income attributable to the Company, or $0.96
per fully diluted share, on $3.1 billion in revenue in its first quarter ended March 31, 2011.
Compared to the fourth quarter of 2010, revenue declined one percent and net income attributable to
the Company declined eight percent. Compared to the first quarter of 2010 revenue increased four
percent and net income attributable to the Company decreased four percent.
The first quarter of 2011 included pre-tax transaction charges and the write-down of Libyan assets
of $19 million, consisting mostly of the write-down of inventory, fixed assets and accounts
receivable rendered uncollectable due to sanctions against Libya. The fourth quarter of 2010
included pre-tax transaction charges of $1 million and the first quarter of 2010 included pre-tax
devaluation charges of $38 million. Excluding transaction and devaluation charges along with the
write-down of Libyan assets from all periods, first quarter 2011 earnings were $1.00 per fully
diluted share, compared to $1.10 per fully diluted share a year ago and $1.05 per fully diluted
share last quarter.
Operating profit excluding transaction and devaluation charges was $628 million or 20.0 percent of
sales in the first quarter of 2011, compared to $625 million or 19.7 percent of sales in the fourth
quarter of 2010 excluding transaction charges. Operating profit excluding transaction and
devaluation charges was $648 million or 21.4 percent of sales for the first quarter of 2010.
Revenues, operating profit and operating margins increased both sequentially and year-over-year for
the Company’s Petroleum Services & Supplies segment. The Company’s Distribution Services segment
generated 23 percent higher sales compared to the first quarter of 2010, but saw sales decline
three percent from the fourth quarter of 2010. Both Distribution Services and Petroleum Services &
Supplies generally benefitted from high rig counts and oilfield activity. The Company’s Rig
Technology segment posted eight percent lower revenues sequentially and 15 percent lower revenues
compared to the prior year first quarter, due primarily to lower revenues from the segment’s
backlog of capital equipment orders.
Oil & Gas Equipment and Services Market
Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset
write-downs at major financial institutions paralyzed credit markets and sparked a serious global
banking crisis. Major central banks responded vigorously through 2009, but a credit-driven
worldwide economic recession continues to dampen economic growth in many developed economies. As a
result asset and commodity prices, including oil and gas prices, declined. After rising steadily
for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to
average $43 per barrel (West Texas Intermediate Crude Prices) during the first quarter of 2009, but
recovered to $76 per barrel range by the end of 2009 and increased to $85 per barrel by the end of
2010. Unrest in the Middle East led to a larger risk premium in oil and prices in excess of $100
per barrel through the first few months of 2011. North American gas prices declined to $3.17 per
mmbtu in the third quarter of 2009 but recovered to average $4.18 per mmbtu in the first quarter of
2011. The steadily rising oil and gas prices seen between 2003 and 2008 led to high levels of
exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed
sharply in 2009 with lower oil and gas prices and tightening credit availability.
The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the
level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a
low of 876 in June 2009. U.S. rig count has since increased to 1,818 in late April 2011, and
averaged 1,717 rigs during the first quarter of 2011. Many oil and gas operators reliant on
external financing to fund their drilling programs significantly curtailed their drilling activity
in 2009, but drilling recovered across North America as gas prices firmed above $4 per mmbtu and,
more recently, as operators began to drill unconventional shale plays targeting oil, rather than
gas. Oil drilling has risen to over 50 percent of the total domestic drilling effort.
Most international activity is driven by oil exploration and production by national oil companies,
which has historically been less susceptible to short-term commodity price swings, but the
international rig count has exhibited modest declines nonetheless, falling from its September 2008
peak of 1,108 to 947 in August 2009, but recently climbing back to 1,147 in March 2011.
During 2009 the Company saw its Petroleum Services & Supplies and its Distribution Services margins
affected most acutely by a drilling downturn, through both volume and price declines; nevertheless,
both of these segments saw pricing stabilize and revenues recover since third quarter 2009 lows.
The Company’s Rig Technology segment increased revenues and margins through 2009 owing to its high
level of contracted backlog which it executed on very well since the economic downturn. As its
backlog declined through 2010 its margins and revenues generally began to move down as well.
The recent economic decline beginning in late 2008 followed an extended period of high drilling
activity which fueled strong demand for oilfield services between 2003 and 2008. Incremental
drilling activity through the upswing shifted toward harsh environments, employing increasingly
sophisticated technology to find and produce reserves. Higher utilization of drilling rigs tested
the capability of the world’s fleet of rigs, much of which is old and of limited capability.
Technology has advanced significantly since most of the existing rig fleet was built. The industry
invested little during the late 1980’s and 1990’s on new drilling equipment, but drilling
technology progressed steadily nonetheless, as the Company and its competitors continued to invest
in new and better ways of drilling. As a consequence, the safety, reliability, and efficiency of
new, modern rigs surpass the performance of most of the older rigs at work today. Drilling rigs
are now being pushed to drill deeper wells, more complex wells, highly deviated wells and
horizontal wells, tasks which require larger rigs with more capabilities. The drilling process
effectively consumes the mechanical components of a rig, which wear out and need periodic repair or
replacement. This process was accelerated by very high rig utilization and wellbore complexity.
Drilling consumes rigs; more complex and challenging drilling consumes rigs faster.
The industry responded by launching many new rig construction projects since 2005, to: 1) retool
the existing fleet of jackup rigs (according to Offshore Data Services, 70 percent of the existing
476 jackup rigs are more than 25 years old); 2) replace older mechanical and DC electric land rigs
with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown
technology; and 3) to build out additional deepwater floating drilling rigs, including
semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit
unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency,
safety, and capability, and that many will effectively replace a portion of the existing fleet, and
that declining dayrates may accelerate the retirement of older rigs.
As a result of these trends the Company’s Rig Technology segment grew its backlog of capital
equipment orders from $0.9 billion at March 31, 2005, to $11.8 billion at September 30, 2008.
However, as a result of the credit crisis and slowing drilling activity, orders declined below
amounts flowing out of backlog as revenue, causing the backlog to decline to $4.9 billion by June
30, 2010. The decline has reversed since, and the backlog stood at $6.2 billion as of March 31,
2011, partly due to very strong orders during the first quarter of 2011. Orders totaled $2.3
billion, the second highest level of orders taken during a quarter during the history of the
Company. Approximately $3.7 billion of these orders are scheduled to flow out as revenue during
the remaining three quarters of 2011; $2.0 billion in 2012, and the balance thereafter. The land
rig backlog comprised 17 percent and equipment destined for offshore operations comprised 83
percent of the total backlog as of March 31, 2011. Equipment destined for international markets
totaled 87 percent of the backlog.
Segment Performance
The Rig Technology segment revenues of $1,608 million in the first quarter of 2011 declined eight
percent sequentially and declined 15 percent compared to the first quarter of 2010. Segment
operating profit was $419 million and operating margins were 26.1 percent during the first quarter.
Compared to the first quarter of 2010 decremental operating leverage or flow-through (the decrease
in operating profit divided by the decrease in revenue) was 58 percent, and compared to the fourth
quarter of 2010 decremental operating leverage was 53 percent, both greater than expected operating leverage of 30 to 35 percent. The
reason for the higher decremental leverage was a mix shift away from higher margin offshore
projects won a few years ago, toward lower-priced offshore work, and more land business, which
typically carries lower margins. Many offshore projects were contracted at high prices in 2007 and
2008 and subsequently manufactured in much lower cost environments in 2009 and 2010. Sequentially
operating margin declined 240 basis points due to mix and slightly lower volumes, and further
margin declines are expected through the next few quarters. Non-backlog revenue was roughly flat
sequentially, as lower sales of small capital goods which do not flow through the segment’s backlog
were offset by higher aftermarket spares and services revenues. Compared to the first quarter of
2010 aftermarket spares and services revenues improved 17 percent. Revenue out of backlog declined
12 percent sequentially. Demand for stimulation equipment, complete land rig packages for
international markets, several jackup rigs and six drillship packages contributed to the strong
order level during the first quarter. Large shale play fracture stimulation jobs in North America
are consuming equipment at a more rapid pace owing to the upturn in oilfield activity and higher
equipment intensity in these types of jobs. Additionally, demand is shifting to larger diameter
coiled tubing strings to stimulate wells and drill out plugs, which led to demand for the Company’s
well-intervention equipment in the quarter. In Brazil the Company submitted tenders for deepwater
drillships for Petrobras to shipyards and drilling contractors, which are to be built in Brazil,
and expects a decision on these soon. Customer inquiries for pressure control equipment are also
trending higher, and orders for pressure control components, spares, repair and services rose
during the first quarter, in response to the Macondo blowout.
The Petroleum Services & Supplies segment generated total sales of $1,265 million in the first
quarter of 2011, up 11 percent from the fourth quarter of 2010 and up 37 percent from the first
quarter of 2010. Operating profit was $231 million or 18.3 percent of sales for the first
quarter, compared to 15.0 percent in the fourth quarter of 2010 and 12.2 percent in the first
quarter of 2010. Operating leverage or flow-through was 48 percent from the fourth quarter of
2010, and 35 percent from the first quarter of 2010 to the first quarter of 2011. First quarter
performance benefitted from high and rising levels of rig activity across North America (up 10
percent sequentially), and a rising shift in drilling toward horizontal wells within the shale
plays, which lifted demand for drilling motors, downhole tools, and 4 inch XT drill pipe which led
to an exceptionally strong quarter for drill pipe sales). Additionally, drilling in North America
shifted toward oil over gas, which prompted demand for fiberglass tubing and line pipe which is
used in oil wells to avoid corrosion from associated produced water. Other consumables such as
valves, seats, shale shaker screens, etc. improved sequentially on high drilling activity as well.
Consolidated segment sales into the U.S. grew 18 percent, Canada improved 23 percent, and
international revenues declined three percent sequentially, leading to an overall mix of 60 percent
North America and 40 percent international for the first quarter of 2011.
The Distribution Services segment generated $410 million in revenue during the first quarter of
2011, down three percent from the fourth quarter of 2010 and increasing 23 percent from the first
quarter of 2010. Operating profit was $27 million, and operating margin was 6.6 percent of sales,
down slightly from the fourth quarter of 2010 but doubled year-ago levels. Decremental operating
leverage or flow-through was 23 percent sequentially, and incremental operating leverage was 21
percent year-over-year for the first quarter. The segment posted strong margin gains in Canada on
small revenue improvements, owing to cost reductions there in earlier periods and strong market
conditions in the first quarter. International sales were down sequentially due to large capital
spares sales overseas in the fourth quarter which did not repeat. Domestic sales were relatively
flat sequentially, at slightly lower margins, due to mix.
Outlook
Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw
signs of stabilization and recovery in many of our markets in 2010, and recovery has continued
through the first quarter of 2011, led by higher drilling activity in North America, and slowly
improving international drilling activity. Order levels for new drilling rigs declined
significantly in 2009 as compared to 2008 due to credit market conditions and softer rig activity,
but we see clear improvement now due to dayrate stabilization for certain classes of newer
technology rigs, lower rig construction costs, and improving availability of financing, including
easier payment terms from shipyards. We expect modest declines in Rig
Technology revenues and margins over the next few quarters before new offshore rig construction
projects can translate into higher revenues.
Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution Services
segment remains closely tied to the rig count, particularly in North America. If the rig count
continues to increase we expect these segments to benefit from higher demand for the services,
consumables and capital items they supply. Many products are beginning to see higher steel, alloy,
resin and fiberglass costs impact their business, and are attempting to raise process to offset
rising costs. Continuing tight iron ore supplies to the steel mills could adversely affect margins
as the year unfolds.
The Company believes it is well positioned to continue to manage through this recession, and should
benefit from its strong balance sheet and capitalization, access to credit, and a high level of
contracted orders which are expected to continue to generate earnings during the remainder of year.
The Company has a long history of cost-control and downsizing in response to depressed market
conditions, and of executing strategic acquisitions during difficult periods. Such a period may
present opportunities to the Company to effect new organic growth and acquisition initiatives, and
we remain hopeful that a downturn will generate new opportunities.
17
Table of Contents
Operating Environment Overview
The Company’s results are dependent on, among other things, the level of worldwide oil and gas
drilling, well remediation activity, the prices of crude oil and natural gas, capital spending by
other oilfield service companies and drilling contractors, and worldwide oil and gas inventory
levels. Key industry indicators for the first quarter of 2011 and 2010, and the fourth quarter of
2010 include the following:
| % | % | |||||||||||||||||||
| 1Q11 v | 1Q11 v | |||||||||||||||||||
| 1Q11* | 4Q10* | 1Q10* | 4Q10 | 1Q10 | ||||||||||||||||
|
Active Drilling Rigs:
|
||||||||||||||||||||
|
U.S.
|
1,717 | 1,687 | 1,345 | 1.8 | % | 27.7 | % | |||||||||||||
|
Canada
|
587 | 405 | 470 | 44.9 | % | 24.9 | % | |||||||||||||
|
International
|
1,166 | 1,115 | 1,063 | 4.6 | % | 9.7 | % | |||||||||||||
|
|
||||||||||||||||||||
|
Worldwide
|
3,470 | 3,207 | 2,878 | 8.2 | % | 20.6 | % | |||||||||||||
|
|
||||||||||||||||||||
|
West Texas Intermediate
Crude Prices (per barrel)
|
$ | 93.54 | $ | 85.10 | $ | 78.64 | 9.9 | % | 18.9 | % | ||||||||||
|
|
||||||||||||||||||||
|
Natural Gas Prices ($/mmbtu)
|
$ | 4.18 | $ | 3.80 | $ | 5.15 | 10.0 | % | (18.8 | %) | ||||||||||
| * | Averages for the quarters indicated. See sources below. |
The following table details the U.S., Canadian, and international rig activity and West Texas
Intermediate Oil prices for the past nine quarters ended March 31, 2011 on a quarterly basis:
| Source: | Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude and Natural Gas Prices: Department of Energy, Energy Information Administration ( www.eia.doe.gov ). |
18
Table of Contents
The worldwide and U.S. quarterly average rig count increased 8% (from 3,207 to 3,470) and 2%
(from 1,687 to 1,717), respectively, in the first quarter of 2011 compared to the fourth quarter of
2010. The average per barrel price of West Texas Intermediate Crude increased 10% (from $85.10 per
barrel to $93.54 per barrel) and natural gas prices increased 10% (from $3.80 per mmbtu to $4.18
per mmbtu) in the first quarter of 2011 compared to the fourth quarter of 2010.
U.S. rig activity at April 21, 2011 was 1,800 rigs compared to the first quarter average of 1,717
rigs, increasing 5%. The price for West Texas Intermediate Crude was at $112.29 per barrel as of
April 21, 2011, increasing 20% from the first quarter average. The price for natural gas was at
$4.41 per mmbtu as of April 21, 2011, increasing 6% from the first quarter average.
Results of Operations
Operating results by segment are as follows (in millions):
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Revenue:
|
||||||||
|
Rig Technology
|
$ | 1,608 | $ | 1,886 | ||||
|
Petroleum Services & Supplies
|
1,265 | 923 | ||||||
|
Distribution Services
|
410 | 334 | ||||||
|
Elimination
|
(137 | ) | (111 | ) | ||||
|
|
||||||||
|
Total Revenue
|
$ | 3,146 | $ | 3,032 | ||||
|
|
||||||||
|
|
||||||||
|
Operating Profit:
|
||||||||
|
Rig Technology
|
$ | 419 | $ | 581 | ||||
|
Petroleum Services & Supplies
|
231 | 113 | ||||||
|
Distribution Services
|
27 | 11 | ||||||
|
Unallocated expenses and eliminations
|
(68 | ) | (68 | ) | ||||
|
|
||||||||
|
Total Operating Profit
|
$ | 609 | $ | 637 | ||||
|
|
||||||||
|
|
||||||||
|
Operating Profit %:
|
||||||||
|
Rig Technology
|
26.1 | % | 30.8 | % | ||||
|
Petroleum Services & Supplies
|
18.3 | % | 12.2 | % | ||||
|
Distribution Services
|
6.6 | % | 3.3 | % | ||||
|
Total Operating Profit %
|
19.4 | % | 21.0 | % | ||||
Rig Technology
Three Months Ended March 31, 2011 and 2010.
Rig Technology revenue in the first quarter of 2011 was
$1,608 million, a decrease of $278 million (14.7%) compared to the same period in 2010. This
decrease is primarily due to the decrease of revenue out of backlog of $382 million partially
offset by the increase in non backlog revenue of $104 million.
Backlog was $6.2 billion at March 31, 2011, a 13% increase from March
31, 2010.
Operating profit from Rig Technology was $419 million for the first quarter ended March 31, 2011, a
decrease of $162 million (27.9%) over the same period of 2010. Operating profit percentage
decreased to 26.1%, from 30.8% for the same prior year period primarily due to a
decrease in revenue out of backlog related to offshore projects.
Petroleum Services & Supplies
Three Months Ended March 31, 2011 and 2010.
Revenue from Petroleum Services & Supplies was $1,265
million for the first quarter of 2011 compared to $923 million for the first quarter of 2010, an
increase of $342 million (37.1%). The increase was primarily attributable to shale plays leading to
a strong U.S. market with a 28% increase in U.S. rig activity compared to the first quarter of
2010.
19
Table of Contents
Operating profit from Petroleum Services & Supplies was $231 million for the first quarter ended
March 31, 2011, an increase of $118 million (104.4%) over the same period of 2010. Operating profit
percentage increased to 18.3%, up from 12.2% for the same prior year period primarily due to
increased volume with a strong domestic demand fueled by an increase
in rig count. The increase was offset by the write-down of Libyan assets of $15 million, mostly related to
accounts receivable affected by sanctions enacted during the quarter along with the write off of
certain inventory and fixed assets in the country. The Company’s Rig Technology and Distribution
Services segments incurred $2 million of such asset write-downs for a total of $17 million in
Libyan asset write-downs incurred by the Company for the first quarter ended March 31, 2011.
Distribution Services
Three Months Ended March 31, 2011 and 2010.
Revenue from Distribution Services was $410 million for
the first quarter of 2011 compared to $334 million for the first quarter of 2010, an increase of
$76 million (22.8%). This increase was primarily attributable to increased U.S. rig count activity
as well as a later than usual Canadian breakup.
Operating profit from Distribution Services was $27 million for the first quarter ended March 31,
2011, an increase of $16 million (145.5%) over the same period of 2010. Operating profit percentage
increased to 6.6%, up from 3.3% for the same prior year period primarily due to increased volume
along with greater cost efficiencies in the quarter.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were
$68 million for each of the three months ended
March 31, 2011 and 2010.
Interest and financial costs
Interest and financial costs were
$14 million for the three months ended
March 31, 2011 compared to $13 million for the same period in 2010.
Other income (expense), net
Other income (expense), net were expenses, net of $19 million and $16 million for the three months
ended March 31, 2011 and 2010, respectively. The increase for the three months ended March 31,
2011, was mainly due to higher foreign exchange losses during the first quarter of 2011 as a result
of exchange rate movements, primarily related to the weakening of the U.S. dollar.
Provision for income taxes
The effective tax rate for the three months ended March 31, 2011 was 31.9% compared to 32.0% for
the same period in 2010. The effective tax rate was positively impacted in the period by the effect
of tax rate reductions on timing differences in foreign jurisdictions and an increase in the
benefit of the manufacturing deduction as a result of increasing income in the U.S. This was offset
by a reduction in the benefit of lower foreign tax rates as a result of decreasing income in
foreign jurisdictions.
Non-GAAP Financial Measures and Reconciliations
In an effort to provide investors with additional information regarding our results as determined
by GAAP, we disclose various non-GAAP financial measures in our quarterly earnings press releases
and other public disclosures. The primary non-GAAP financial measures we focus on are: (i)
operating profit excluding other costs, (ii) operating profit percentage excluding other costs, and
(iii) diluted earnings per share excluding other costs. Each of these financial measures excludes
the impact of certain other costs and therefore has not been calculated in accordance with GAAP. A
reconciliation of each of these non-GAAP financial measures to its most comparable GAAP financial
measure is included below.
We use these non-GAAP financial measures because we believe it provides useful supplemental
information regarding the Company’s on-going economic performance and, therefore, use these
non-GAAP financial measures internally to evaluate and manage the Company’s operations. We have
chosen to provide this information to investors to enable them to perform more meaningful
comparisons of operating results and as a means to emphasize the results of on-going operations.
The following tables set forth the reconciliations of these non-GAAP financial measures to their
most comparable GAAP financial measures (in millions, except per share data):
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Reconciliation of operating profit:
|
||||||||
|
GAAP operating profit
|
$ | 609 | $ | 637 | ||||
|
Other costs:
|
||||||||
|
Libya asset write-down
|
17 | — | ||||||
|
Transaction costs
|
2 | — | ||||||
|
Devaluation costs
|
— | 11 | ||||||
|
|
||||||||
|
Operating profit excluding other costs
|
$ | 628 | $ | 648 | ||||
|
|
||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Reconciliation of operating profit %:
|
||||||||
|
GAAP operating profit %
|
19.4 | % | 21.0 | % | ||||
|
Other costs %
|
0.6 | % | 0.4 | % | ||||
|
|
||||||||
|
Operating profit % excluding other costs
|
20.0 | % | 21.4 | % | ||||
|
|
||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Reconciliation of diluted earnings per share:
|
||||||||
|
GAAP earnings per share
|
$ | 0.96 | $ | 1.01 | ||||
|
Other costs
|
0.04 | 0.09 | ||||||
|
|
||||||||
|
Earnings per share excluding other costs
|
$ | 1.00 | $ | 1.10 | ||||
|
|
||||||||
20
Table of Contents
Liquidity and Capital Resources
Overview
At March 31, 2011, the Company had cash and cash equivalents of $3,060 million, and total debt of
$715 million. At December 31, 2010, cash and cash equivalents were $3,333 million and total debt
was $887 million. A significant portion of the consolidated cash balances are maintained in
accounts in various foreign subsidiaries and, if such amounts were transferred among countries or
repatriated to the U.S., such amounts may be subject to additional tax obligations. Rather than
repatriating this cash, the Company may choose to borrow against its credit facility. The Company’s
outstanding debt at March 31, 2011 consisted of $200 million of 7.25% Senior Notes due 2011, $200
million of 5.65% Senior Notes due 2012, $150 million of 5.5% Senior Notes due 2012, $151 million of
6.125% Senior Notes due 2015, and other debt of $14 million.
There were no borrowings against the Company’s unsecured revolving credit facility, and there were
$429 million in outstanding letters of credit issued under the facility, resulting in $1,571
million of funds available under the Company’s unsecured revolving credit facility at March 31,
2011.
The Company had $1,479 million of additional outstanding letters of credit at March 31, 2011,
primarily in Norway, that are essentially under various bilateral committed letter of credit
facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes
contain reporting covenants and the credit facility contains a financial covenant regarding maximum
debt to capitalization. The Company was in compliance with all covenants at March 31, 2011.
The following table summarizes our net
cash used in provided by operating activities, net cash used in
investing activities and net cash used in financing activities for the periods presented (in
millions):
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2011 | 2010 | |||||||
|
Net cash (used in) provided by
operating activities
|
$ | (25 | ) | $ | 95 | |||
|
Net cash used in investing activities
|
(123 | ) | (65 | ) | ||||
|
Net cash used in financing activities
|
(144 | ) | (36 | ) | ||||
Operating Activities
For the
first three months of 2011, cash used in operating activities was $25 million, a change of
$120 million compared to cash provided by operating activities of $95 million in the same period of
2010. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by
operations primarily through net income of $404 million plus non-cash charges of $230 million less
$13 million in equity income from the Company’s unconsolidated affiliate.
Net changes in operating assets and liabilities, net of acquisitions, used $658 million for the
first three months of 2011, a $75 million increase from the same period in 2010. Due to an increase
in market activity during the first three months of 2011 compared to the same period in 2010,
revenue and backlog (milestone invoicing) increased which is reflected in increased accounts receivable coupled with a
buildup in inventory. Incentive compensation and tax payments contributed to the reduction in other
assets/liabilities, net for the first three months of 2011 compared to the same period in 2010.
Investing Activities
For the first three months of 2011, cash used in investing activities was $123 million compared to
cash used in investing of $65 million for the same period of 2010. The primary reason for the
increase related to the increase in capital expenditures to
approximately $79 million as capital was spent on several
international expansion projects during the first
three months of 2011 compared to $31 million used in the same period of 2010. In addition, business
acquisitions increased slightly to approximately $51 million compared to $46 million used in the
same period of 2010.
21
Table of Contents
Financing Activities
For the first three months of 2011, cash used in financing activities was $144 million compared to
cash used in financing activities of $36 million for the same period of 2010. The $108 million
increase in cash used in financing activities for the first three months of 2011 primarily related
to the repayment of $150 million in Senior Notes that were due late in the quarter as well as $20
million in other current borrowings. The Company increased its dividend slightly to $46 million for
the first three months of 2011 compared to $42 million for the same period of 2010. The increase in
cash used was offset by $58 million in proceeds from stock options exercised during the first three
months of 2011 compared to $5 million in proceeds from stock options exercised during the same
period in 2010. For the first three months of 2011, the Company used its cash on hand to fund its
acquisitions.
The effect of the change in exchange rates on cash flows was a positive $19 million and a negative
$8 million for the three months ended March 31, 2011 and 2010, respectively.
We believe that cash on hand, cash generated from operations and amounts available under the credit
facilities and from other sources of debt will be sufficient to fund operations, working capital
needs, capital expenditure requirements, dividends and financing obligations.
We intend to pursue additional acquisition candidates, but the timing, size or success of any
acquisition effort and the related potential capital commitments cannot be predicted. We expect to
fund future cash acquisitions primarily with cash flow from operations and borrowings, including
the unborrowed portion of the credit facility or new debt issuances, but may also issue additional
equity either directly or in connection with acquisitions. There can be no assurance that
additional financing for acquisitions will be available at terms acceptable to us.
Forward-Looking Statements
Some of the information in this document contains, or has incorporated by reference,
forward-looking statements. Statements that are not historical facts, including statements about
our beliefs and expectations, are forward-looking statements. Forward-looking statements typically
are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and
similar words, although some forward-looking statements are expressed differently. All statements
herein regarding expected merger synergies are forward-looking statements. You should be aware that
our actual results could differ materially from results anticipated in the forward-looking
statements due to a number of factors, including but not limited to changes in oil and gas prices,
customer demand for our products, difficulties encountered in integrating mergers and acquisitions,
and worldwide economic activity. You should also consider carefully the statements under “Risk
Factors,” as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010,
which address additional factors that could cause our actual results to differ from those set forth
in the forward-looking statements. Given these uncertainties, current or prospective investors are
cautioned not to place undue reliance on any such forward-looking statements. We undertake no
obligation to update any such factors or forward-looking statements to reflect future events or
developments.
22
Table of Contents
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to changes in foreign currency exchange rates and interest rates. Additional
information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these
operations are exposed to changes in foreign currency exchange rates, although such fluctuations
generally do not affect income since their functional currency is typically the local currency.
These operations also have net assets and liabilities not denominated in the functional currency,
which exposes us to changes in foreign currency exchange rates that impact income. We recorded a
foreign exchange loss in our income statement of approximately $14 million in the first three
months of 2011, compared to an $11 million foreign exchange loss in the same period of the prior
year. The gains and losses are primarily due to exchange rate fluctuations related to monetary
asset balances denominated in currencies other than the functional currency and adjustments to our
hedged positions as a result of changes in foreign currency exchange rates. Strengthening of
currencies against the U.S. dollar may create losses in future periods to the extent we maintain
net assets and liabilities not denominated in the functional currency of the countries using the
local currency as their functional currency.
Some of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes
in foreign currency exchange rates impact our earnings to the extent that costs associated with
those U.S. dollar revenues are denominated in the local currency. Similarly some of our revenues
are denominated in foreign currencies, but have associated U.S. dollar costs, which also give rise
to foreign currency exchange rate exposure. In order to mitigate that risk, we may utilize foreign
currency forward contracts to better match the currency of our revenues and associated costs. We do
not use foreign currency forward contracts for trading or speculative purposes.
The following table details the Company’s foreign currency exchange risk grouped by functional
currency and their expected maturity periods as of March 31, 2011 (in millions, except contract
rates):
| As of March 31, 2011 | December 31, | |||||||||||||||||||
| Functional Currency | 2011 | 2012 | 2013 | Total | 2010 | |||||||||||||||
|
CAD Buy USD/Sell CAD:
|
||||||||||||||||||||
|
Notional amount to buy (in Canadian dollars)
|
311 | — | — | 311 | 267 | |||||||||||||||
|
Average CAD to USD contract rate
|
0.9886 | — | — | 0.9886 | 1.0072 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
(5 | ) | — | — | (5 | ) | (1 | ) | ||||||||||||
|
Sell USD/Buy CAD:
|
||||||||||||||||||||
|
Notional amount to sell (in Canadian dollars)
|
107 | 18 | — | 125 | 55 | |||||||||||||||
|
Average CAD to USD contract rate
|
0.9929 | 0.9825 | — | 0.9915 | 1.0237 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
2 | — | — | 2 | 1 | |||||||||||||||
|
EUR Buy USD/Sell EUR:
|
||||||||||||||||||||
|
Notional amount to buy (in euros)
|
5 | — | — | 5 | 1 | |||||||||||||||
|
Average USD to EUR contract rate
|
1.3845 | 1.4126 | — | 1.3845 | 1.3884 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
— | — | — | — | — | |||||||||||||||
|
Sell USD/Buy EUR:
|
||||||||||||||||||||
|
Notional amount to buy (in euros)
|
95 | 16 | — | 111 | 74 | |||||||||||||||
|
Average USD to EUR contract rate
|
1.3379 | 1.3331 | — | 1.3372 | 1.3172 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
6 | 1 | — | 7 | 1 | |||||||||||||||
|
KRW Sell EUR/Buy KRW:
|
||||||||||||||||||||
|
Notional amount to buy (in South Korean won)
|
291 | 123 | 261 | 675 | 273 | |||||||||||||||
|
Average KRW to EUR contract rate
|
931.39 | 923.70 | 918.82 | 925.09 | 1,742.53 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
— | — | — | — | — | |||||||||||||||
|
Sell USD/Buy KRW:
|
||||||||||||||||||||
|
Notional amount to buy (in South Korean won)
|
45,336 | 3,416 | 639 | 49,391 | 67,657 | |||||||||||||||
|
Average KRW to USD contract rate
|
1,096.99 | 1,118.68 | 1,020.25 | 1,097.25 | 1,085.68 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
(1 | ) | — | — | (1 | ) | (3 | ) | ||||||||||||
23
Table of Contents
| As of March 31, 2011 | December 31, | |||||||||||||||||||
| Functional Currency | 2011 | 2012 | 2013 | Total | 2010 | |||||||||||||||
|
GBP Buy USD/Sell GBP:
|
||||||||||||||||||||
|
Notional amount to buy (in British Pounds
Sterling)
|
2 | — | — | 2 | — | |||||||||||||||
|
Average USD to GBP contract rate
|
1.6225 | — | — | 1.6225 | — | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
— | — | — | — | — | |||||||||||||||
|
Sell USD/Buy GBP:
|
||||||||||||||||||||
|
Notional amount to buy (in British Pounds
Sterling)
|
55 | 10 | — | 65 | 49 | |||||||||||||||
|
Average USD to GBP contract rate
|
1.5471 | 1.5937 | — | 1.5544 | 1.4952 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
3 | — | — | 3 | 2 | |||||||||||||||
|
USD Buy DKK/Sell USD:
|
||||||||||||||||||||
|
Notional amount to buy (in U.S. dollars)
|
19 | — | — | 19 | 19 | |||||||||||||||
|
Average DKK to USD contract rate
|
5.4881 | — | — | 5.4881 | 5.5064 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
1 | — | — | 1 | — | |||||||||||||||
|
Buy EUR/Sell USD:
|
||||||||||||||||||||
|
Notional amount to buy (in U.S. dollars)
|
204 | 52 | — | 256 | 224 | |||||||||||||||
|
Average USD to EUR contract rate
|
1.3565 | 1.3345 | — | 1.3520 | 1.3243 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
7 | 2 | — | 9 | — | |||||||||||||||
|
Buy GBP/Sell USD:
|
||||||||||||||||||||
|
Notional amount to buy (in U.S. dollars)
|
51 | — | — | 51 | 18 | |||||||||||||||
|
Average USD to GBP contract rate
|
0.6283 | — | — | 0.6283 | 1.5724 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
— | — | — | — | — | |||||||||||||||
|
Buy NOK/Sell USD:
|
||||||||||||||||||||
|
Notional amount to buy (in U.S. dollars)
|
515 | 339 | 39 | 893 | 810 | |||||||||||||||
|
Average NOK to USD contract rate
|
6.0026 | 6.2007 | 6.0278 | 6.0789 | 6.2022 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
35 | 26 | 1 | 62 | 32 | |||||||||||||||
|
Buy SEK/Sell USD:
|
||||||||||||||||||||
|
Notional amount to sell (in U.S. dollars)
|
8 | — | — | 8 | — | |||||||||||||||
|
Average SEK to USD contract rate
|
7.0171 | — | — | 7.0171 | — | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
1 | — | — | 1 | — | |||||||||||||||
|
Sell DKK/Buy USD:
|
||||||||||||||||||||
|
Notional amount to buy (in U.S. dollars)
|
11 | — | — | 11 | 8 | |||||||||||||||
|
Average DKK to USD contract rate
|
5.5521 | — | — | 5.5521 | 5.5998 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
(1 | ) | — | — | (1 | ) | — | |||||||||||||
|
Sell EUR/Buy USD:
|
||||||||||||||||||||
|
Notional amount to sell (in U.S. dollars)
|
121 | 9 | — | 130 | 66 | |||||||||||||||
|
Average USD to EUR contract rate
|
1.3941 | 1.3575 | — | 1.3914 | 1.3423 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
(1 | ) | — | — | (1 | ) | 1 | |||||||||||||
|
Sell NOK/Buy USD:
|
||||||||||||||||||||
|
Notional amount to sell (in U.S. dollars)
|
257 | 29 | 1 | 287 | 229 | |||||||||||||||
|
Average NOK to USD contract rate
|
5.8414 | 6.0006 | 5.9030 | 5.8575 | 6.1282 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
(11 | ) | (1 | ) | — | (12 | ) | (7 | ) | |||||||||||
|
Sell RUB/Buy USD:
|
||||||||||||||||||||
|
Notional amount to sell (in U.S. dollars)
|
15 | — | — | 15 | 25 | |||||||||||||||
|
Average RUB to USD contract rate
|
28.6100 | — | — | 28.6100 | 31.2030 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
— | — | — | — | (1 | ) | ||||||||||||||
|
DKK Sell DKK/Buy USD:
|
||||||||||||||||||||
|
Notional amount to buy (in U.S. dollars)
|
103 | — | — | 103 | 113 | |||||||||||||||
|
Average DKK to USD contract rate
|
5.2687 | — | — | 5.2687 | 5.6618 | |||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
— | — | — | — | — | |||||||||||||||
|
Other Currencies
|
||||||||||||||||||||
|
Fair Value at March 31, 2011 in U.S. dollars
|
2 | — | — | 2 | (1 | ) | ||||||||||||||
|
|
||||||||||||||||||||
|
Total Fair Value at March 31, 2011 in U.S. dollars
|
38 | 28 | 1 | 67 | 24 | |||||||||||||||
|
|
||||||||||||||||||||
24
Table of Contents
The Company had other financial market risk sensitive instruments denominated in foreign currencies
for transactional exposures totaling $237 million and translation exposures totaling $574 million
as of March 31, 2011 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 $15
million and the transactional exposures financial market risk sensitive instruments could affect
the future fair value by $57 million.
The counterparties to forward contracts are major financial institutions. The credit ratings and
concentration of risk of these financial institutions are monitored on a continuing basis. In the
event that the counterparties fail to meet the terms of a foreign currency contract, our exposure
is limited to the foreign currency rate differential.
Interest Rate Risk
At March 31, 2011 our long term borrowings consisted of $200 million in 7.25% Senior Notes, $200
million in 5.65% Senior Notes, $150 million in 5.5% Senior Notes and $151 million in 6.125% Senior
Notes. We occasionally have borrowings under our credit facility, and a portion of these borrowings
could be denominated in multiple currencies which could expose us to market risk with exchange rate
movements. These instruments carry interest at a pre-agreed upon percentage point spread from
either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may,
at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or
EURIBOR for 30 days to six months. Our objective is to maintain a portion of our debt in variable
rate borrowings for the flexibility obtained regarding early repayment without penalties and lower
overall cost as compared with fixed-rate borrowings.
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.
25
Table of Contents
PART II — OTHER INFORMATION
Item 6. Exhibits
Reference
is hereby made to the Exhibit Index commencing on page 27.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
Date: May 6, 2011
|
By: /s/ Clay C. Williams
|
|||
|
|
Executive Vice President and Chief Financial Officer | |||
|
|
(Duly Authorized Officer, Principal Financial and Accounting Officer) |
26
Table of Contents
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
|
Amended and Restated Certificate of Incorporation of National-Oilwell, 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, with similar agreement with Mark A. Reese. (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. (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
|
Five-Year Credit Agreement, dated as of April 21, 2008, 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, DnB Nor Bank ASA, as Co-Lead Arranger and Joint Book Runner, and Fortis Capital Corp., The Bank of Nova Scotia and The Bank of Tokyo — Mitsubishi UFJ, Ltd., as Co-Documentation Agents. (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 Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (11) | |
|
|
||
|
10.13
|
First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (11) | |
|
|
||
|
10.14
|
Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (11) | |
|
|
||
|
10.15
|
First Amendment to National Oilwell Varco Long-Term Incentive Plan. (12)* | |
|
|
||
|
10.16
|
Second Amendment to Employment Agreement dated as of December 31, 2009 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (13) | |
|
|
||
|
10.17
|
Third Amendment to Executive Agreement, dated as of December 31, 2009, of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (13) | |
|
|
||
|
10.18
|
Second Amendment to Employment Agreement dated as of December 31, 2009 between Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (13) |
27
Table of Contents
|
10.19
|
Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (13) | |
|
|
||
|
10.20
|
First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (13) | |
|
|
||
|
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. | |
|
|
||
|
101
|
The following materials from our Quarterly Report on Form 10-Q for the period ended March 31, 2011 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. (14) |
| * | Compensatory plan or arrangement for management or others. | |
| (1) | Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 11, 2000. | |
| (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 Annex D to our Amendment No. 1 to Registration Statement on Form S-4 filed on January 31, 2005. | |
| (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 February 21, 2008. | |
| (10) | Filed as an Exhibit to our Current Report on Form 8-K filed on April 22, 2008. | |
| (11) | Filed as an Exhibit to our Current Report on Form 8-K filed on December 23, 2008. | |
| (12) | Filed as Appendix I to our Proxy Statement filed on April 1, 2009. | |
| (13) | Filed as an Exhibit to our Current Report on Form 8-K filed on January 5, 2010. | |
| (14) | 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.
28
TABLE OF CONTENTS
Part I Financial InformationprintItem 1. Financial StatementsprintItem 2. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 3. Quantitative and Qualitative Disclosures About Market RiskprintItem 4. Controls and ProceduresprintPart II Other InformationprintItem 6. Exhibitsprint