NOV Inc. - Quarter Report: 2010 March (Form 10-Q)
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, 2010
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 | (I.R.S. Employer | |
of incorporation or organization) | Identification No.) |
7909 Parkwood Circle Drive
Houston, Texas
77036-6565
Houston, Texas
77036-6565
(Address of principal executive offices)
(713) 346-7500
(Registrants 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 3, 2010 the registrant had 419,017,996 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, | |||||||
2010 | 2009 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 2,608 | $ | 2,622 | ||||
Receivables, net |
2,111 | 2,187 | ||||||
Inventories, net |
3,423 | 3,490 | ||||||
Costs in excess of billings |
918 | 740 | ||||||
Deferred income taxes |
228 | 290 | ||||||
Prepaid and other current assets |
257 | 269 | ||||||
Total current assets |
9,545 | 9,598 | ||||||
Property, plant and equipment, net |
1,810 | 1,836 | ||||||
Deferred income taxes |
131 | 92 | ||||||
Goodwill |
5,544 | 5,489 | ||||||
Intangibles, net |
3,987 | 4,052 | ||||||
Investment in unconsolidated affiliate |
390 | 393 | ||||||
Other assets |
59 | 72 | ||||||
Total assets |
$ | 21,466 | $ | 21,532 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 538 | $ | 584 | ||||
Accrued liabilities |
2,245 | 2,267 | ||||||
Billings in excess of costs |
681 | 1,090 | ||||||
Current portion of long-term debt and short-term borrowings |
156 | 7 | ||||||
Accrued income taxes |
124 | 226 | ||||||
Total current liabilities |
3,744 | 4,174 | ||||||
Long-term debt |
724 | 876 | ||||||
Deferred income taxes |
2,166 | 2,091 | ||||||
Other liabilities |
252 | 163 | ||||||
Total liabilities |
6,886 | 7,304 | ||||||
Commitments and contingencies |
||||||||
Stockholders equity: |
||||||||
Common stock par value $.01; 418,938,789 and 418,451,731 shares issued
and outstanding at March 31, 2010 and December 31, 2009 |
4 | 4 | ||||||
Additional paid-in capital |
8,228 | 8,214 | ||||||
Accumulated other comprehensive income |
50 | 90 | ||||||
Retained earnings |
6,185 | 5,805 | ||||||
Total Company stockholders equity |
14,467 | 14,113 | ||||||
Noncontrolling interests |
113 | 115 | ||||||
Total stockholders equity |
14,580 | 14,228 | ||||||
Total liabilities and stockholders equity |
$ | 21,466 | $ | 21,532 | ||||
See notes to unaudited consolidated financial statements.
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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, | ||||||||
2010 | 2009 | |||||||
Revenue |
$ | 3,032 | $ | 3,481 | ||||
Cost of revenue |
2,070 | 2,442 | ||||||
Gross profit |
962 | 1,039 | ||||||
Selling, general and administrative |
325 | 319 | ||||||
Operating profit |
637 | 720 | ||||||
Interest and financial costs |
(13 | ) | (13 | ) | ||||
Interest income |
2 | 2 | ||||||
Equity income in unconsolidated affiliate |
6 | 28 | ||||||
Other income (expense), net |
(16 | ) | (36 | ) | ||||
Income before income taxes |
616 | 701 | ||||||
Provision for income taxes |
197 | 228 | ||||||
Net income |
419 | 473 | ||||||
Net income (loss) attributable to noncontrolling interests |
(3 | ) | 3 | |||||
Net income attributable to Company |
$ | 422 | $ | 470 | ||||
Net income attributable to Company per share: |
||||||||
Basic |
$ | 1.01 | $ | 1.13 | ||||
Diluted |
$ | 1.01 | $ | 1.13 | ||||
Weighted average shares outstanding: |
||||||||
Basic |
417 | 416 | ||||||
Diluted |
419 | 418 | ||||||
See notes to unaudited consolidated financial statements.
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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, | ||||||||
2010 | 2009 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 419 | $ | 473 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
127 | 116 | ||||||
Equity income in unconsolidated affiliate |
(6 | ) | (28 | ) | ||||
Other, net |
138 | 51 | ||||||
Change in operating assets and liabilities, net of acquisitions: |
||||||||
Receivables |
74 | 227 | ||||||
Inventories |
67 | (39 | ) | |||||
Costs in excess of billings |
(178 | ) | 3 | |||||
Prepaid and other current assets |
13 | (126 | ) | |||||
Accounts payable |
(46 | ) | 3 | |||||
Billings in excess of costs |
(409 | ) | (77 | ) | ||||
Other assets/liabilities, net |
(104 | ) | 182 | |||||
Net cash provided by operating activities |
95 | 785 | ||||||
Cash flows from investing activities: |
||||||||
Purchases of property, plant and equipment |
(31 | ) | (79 | ) | ||||
Business acquisitions, net of cash acquired |
(46 | ) | | |||||
Other |
12 | | ||||||
Net cash used in investing activities |
(65 | ) | (79 | ) | ||||
Cash flows from financing activities: |
||||||||
Repayments on debt |
(2 | ) | | |||||
Cash dividends paid |
(42 | ) | | |||||
Other, net |
8 | 1 | ||||||
Net cash provided by (used in) financing activities |
(36 | ) | 1 | |||||
Effect of exchange rates on cash |
(8 | ) | (18 | ) | ||||
Increase (decrease) in cash equivalents |
(14 | ) | 689 | |||||
Cash and cash equivalents, beginning of period |
2,622 | 1,543 | ||||||
Cash and cash equivalents, end of period |
$ | 2,608 | $ | 2,232 | ||||
Supplemental disclosures of cash flow information: |
||||||||
Cash payments during the period for: |
||||||||
Interest |
$ | 11 | $ | 10 | ||||
Income taxes |
$ | 101 | $ | 78 |
See notes to unaudited consolidated financial statements.
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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 2009 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, 2010 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, | |||||||
2010 | 2009 | |||||||
Raw materials and supplies |
$ | 681 | $ | 704 | ||||
Work in process |
1,266 | 1,307 | ||||||
Finished goods and purchased products |
1,476 | 1,479 | ||||||
Total |
$ | 3,423 | $ | 3,490 | ||||
3. Accrued Liabilities
Accrued liabilities consist of (in millions):
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
Compensation |
$ | 222 | $ | 272 | ||||
Customer prepayments and billings |
436 | 500 | ||||||
Warranty |
210 | 217 | ||||||
Interest |
15 | 11 | ||||||
Taxes (non income) |
57 | 95 | ||||||
Insurance |
59 | 58 | ||||||
Accrued purchase orders |
968 | 853 | ||||||
Fair value of derivatives |
71 | 61 | ||||||
Other |
207 | 200 | ||||||
Total |
$ | 2,245 | $ | 2,267 | ||||
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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, 2009 |
$ | 217 | ||
Net provisions for warranties issued during the year |
12 | |||
Amounts incurred |
(10 | ) | ||
Foreign currency translation and other |
(9 | ) | ||
Balance at March 31, 2010 |
$ | 210 | ||
4. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
Costs incurred on uncompleted contracts |
$ | 6,718 | $ | 6,276 | ||||
Estimated earnings |
4,191 | 3,735 | ||||||
10,909 | 10,011 | |||||||
Less: Billings to date |
10,672 | 10,361 | ||||||
$ | 237 | $ | (350 | ) | ||||
Costs and estimated earnings in excess of billings on uncompleted contracts |
$ | 918 | $ | 740 | ||||
Billings in excess of costs and estimated earnings on uncompleted contracts |
(681 | ) | (1,090 | ) | ||||
$ | 237 | $ | (350 | ) | ||||
5. Comprehensive Income
The components of comprehensive income are as follows (in millions):
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
Net income |
$ | 419 | $ | 473 | ||||
Currency translation adjustments, net of tax |
(14 | ) | (55 | ) | ||||
Changes in derivative financial instruments, net of tax |
(26 | ) | 22 | |||||
Comprehensive income |
379 | 440 | ||||||
Comprehensive income (loss) attributable to noncontrolling interest |
(3 | ) | 3 | |||||
Comprehensive income attributable to Company |
$ | 382 | $ | 437 | ||||
The Companys reporting currency is the U.S. dollar. A majority of the Companys
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, 2010, a majority of these local currencies weakened against the U.S. dollar resulting in
a net decrease to Other Comprehensive Income of $14 million (net of tax of $8 million) upon the
translation of their financial statements from their local currency to the U.S. dollar.
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During the first quarter of 2010, the Venezuelan government officially devalued the Venezuelan
bolivar against the U.S. dollar. As a result the Company converted its Venezuela ledgers to U.S.
dollar functional currency, devalued monetary assets resulting in a $27 million charge, and wrote-down certain accounts receivable in view of deteriorating business conditions in Venezuela,
resulting in an additional $11 million charge.
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 a decrease in Other
Comprehensive Income of $26 million (net of tax of $10 million) for the three months ended March
31, 2010.
6. Business Segments
Operating results by segment are as follows (in millions):
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
Revenue: |
||||||||
Rig Technology |
$ | 1,886 | $ | 2,199 | ||||
Petroleum Services & Supplies |
923 | 1,014 | ||||||
Distribution Services |
334 | 408 | ||||||
Elimination |
(111 | ) | (140 | ) | ||||
Total Revenue |
$ | 3,032 | $ | 3,481 | ||||
Operating Profit: |
||||||||
Rig Technology |
$ | 581 | $ | 606 | ||||
Petroleum Services & Supplies |
113 | 164 | ||||||
Distribution Services |
11 | 25 | ||||||
Unallocated expenses and eliminations |
(68 | ) | (75 | ) | ||||
Total Operating Profit |
$ | 637 | $ | 720 | ||||
Operating Profit %: |
||||||||
Rig Technology |
30.8 | % | 27.6 | % | ||||
Petroleum Services & Supplies |
12.2 | % | 16.2 | % | ||||
Distribution Services |
3.3 | % | 6.1 | % | ||||
Total Operating Profit % |
21.0 | % | 20.7 | % |
The Company had revenues of 21% and 12% of total revenue from one of its customers for the three
months ended March 31, 2010 and 2009, respectively. This customer is a shipyard acting as a
general contractor for its customers, who are drillship owners and drilling contractors. This
shipyards customers have specified that the Companys drilling equipment be installed on their
drillships and have required the shipyard to issue contracts to the Company.
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7. Debt
Debt consists of (in millions):
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
Senior Notes, interest at 6.5% payable semiannually,
principal due on March 15, 2011 |
$ | 150 | $ | 150 | ||||
Senior Notes, interest at 7.25% payable semiannually,
principal due on May 1, 2011 |
205 | 205 | ||||||
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 |
151 | 151 | ||||||
Senior Notes, interest at 6.125% payable semiannually,
principal due on August 15, 2015 |
151 | 151 | ||||||
Other |
23 | 26 | ||||||
Total debt |
880 | 883 | ||||||
Less current portion |
156 | 7 | ||||||
Long-term debt |
$ | 724 | $ | 876 | ||||
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, 2010, there were no borrowings against
the remaining credit facility, and there were $584 million in outstanding letters of credit issued
under this facility, resulting in $1,416 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 $1,808 million of additional outstanding letters of credit at March 31, 2010,
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,
2010.
Other
Other debt includes approximately $3 million in promissory notes due to former owners of businesses
acquired who remain employed by the Company.
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8. Tax
The effective tax rate for the three months ended March 31, 2010 was 32.0% compared to 32.5% for
the same period in 2009. The effective tax rate was positively impacted by the increase in
earnings taxed at lower rates in foreign jurisdictions, offset by lost tax benefits
associated with non-deductible foreign exchange losses resulting from the devaluation of the
Venezuelan bolivar.
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, | ||||||||
2010 | 2009 | |||||||
Federal income tax at U.S. federal statutory rate |
$ | 215 | $ | 245 | ||||
Foreign income tax rate differential |
(40 | ) | (32 | ) | ||||
State income tax, net of federal benefit |
2 | 6 | ||||||
Foreign dividends, net of foreign tax credits |
1 | 1 | ||||||
Benefit of U.S. Manufacturing Deduction |
(3 | ) | (4 | ) | ||||
Nondeductible expenses |
19 | 8 | ||||||
Other |
3 | 4 | ||||||
Provision for income taxes |
$ | 197 | $ | 228 | ||||
The Company accounts for uncertainty in income taxes in accordance with ASC Topic 740, Income
Taxes (ASC Topic 740). ASC Topic 740 clarifies the accounting for uncertainty in income
taxes recognized in an entitys financial statements and prescribes a recognition threshold and
measurement attributes for financial statement disclosure of tax positions taken or expected to be
taken on a return. Under ASC Topic 740, the impact of an uncertain income tax position, in
managements opinion, on the income tax return must be recognized at the largest amount that is
more-likely-than-not to be sustained upon audit by the relevant taxing authority. An uncertain
income tax position will not be recognized if it has a less than 50% likelihood of being sustained.
The balance of unrecognized tax benefits at March 31, 2010 was $123 million. Included in the
change in the balance of unrecognized tax benefits was an increase of $73 million associated with a
foreign tax position previously evaluated as more-likely-than-not to be sustained upon audit.
Based on new information obtained this quarter, we now believe it is more-likely-than-not this foreign tax position may not be sustained. Tax payments for this
liability can be claimed as a U.S. foreign tax credit due to sufficient excess limitation in prior
years to cover the potential exposure. Accordingly, the company has recorded a corresponding
deferred tax asset of $73 million, resulting in no impact to earnings.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in
millions):
Balance at December 31, 2009 |
$ | 58 | ||
Additions for tax positions of prior years |
73 | |||
Reductions for lapse of applicable statutes of limitations |
(8 | ) | ||
Balance at March 31, 2010 |
$ | 123 | ||
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 2005 and outside the U.S. for tax years ending
after 2002.
To the extent penalties and interest would be assessed on any underpayment of income tax, such
accrued amounts have been classified as a component of income tax expense in the financial
statements.
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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, 2010, 8,046,586 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 and $16 million for the
three months ended March 31, 2010 and 2009, respectively. 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 both the three months ended March 31, 2010 and 2009, respectively.
During the three months ended March 31, 2010, the Company granted 3,443,107 stock options and
543,035 restricted stock awards, which includes 171,400 performance-based restricted stock awards.
The stock options were granted February 16, 2010 with an exercise price of $44.07. These options
generally vest over a three-year period from the grant date. The restricted stock awards were
granted February 16, 2010 and vest on the third anniversary of the date of grant. The
performance-based restricted stock awards were granted February 16, 2010. 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 Companys average operating income growth, measured on a
percentage basis, from January 1, 2010 through December 31, 2012 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 statement of financial position 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 Companys fixed and floating-rate borrowings.
The Company records all derivative financial instruments at their fair value in our consolidated
balance sheet. Except for certain non-designated hedges discussed below, all derivative financial
instruments we hold 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. We may also use interest rate contracts
to mitigate our exposure to changes in interest rates on anticipated long-term debt issuances.
At March 31, 2010, the Company has determined that its financial assets of $79 million and
liabilities of $70 million (primarily currency related derivatives) are level 2 in the fair value
hierarchy. At March 31, 2010, the fair value of the Companys foreign currency forward contracts
totaled $9 million.
As of March 31, 2010, the Company did not have any interest rate swaps and our financial
instruments do not contain any credit-risk-related or other contingent features that could cause
accelerated payments when our financial instruments are in net liability positions. We do not use
derivative financial instruments for trading or speculative purposes.
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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, 2010, 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:
Currency | ||||||
Foreign Currency | Denomination | |||||
(in millions) | ||||||
British Pound Sterling |
£ | 30 | ||||
Danish Krone |
DKK | 106 | ||||
Euro |
| 143 | ||||
Norwegian Krone |
NOK | 6,307 | ||||
U.S. Dollar |
$ | 264 | ||||
Korean Won |
KRW | 781 |
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 Companys 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, 2010, 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:
Currency | ||||
Foreign Currency | Denomination | |||
(in millions) | ||||
U.S. Dollar |
$ | 20 |
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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 the
same line item associated with the hedged item in current earnings.
The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary
accounts. The purpose of the Companys 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, 2010, the Company had the following outstanding foreign currency forward contracts
that hedge the fair value of nonfunctional currency monetary accounts:
Currency | ||||||
Foreign Currency | Denomination | |||||
(in millions) | ||||||
British Pound Sterling |
£ | 24 | ||||
Danish Krone |
DKK | 174 | ||||
Euro |
| 64 | ||||
Norwegian Krone |
NOK | 3,777 | ||||
Swedish Krone |
SEK | 5 | ||||
U.S. Dollar |
$ | 491 | ||||
Korean Won |
KRW | 4,348 |
As of March 31, 2010, 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 | 2010 | 2009 | Location | 2010 | 2009 | |||||||||||||||||||
Derivatives designated as hedging
instruments under ASC Topic 815 |
||||||||||||||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 37 | $ | 56 | Accrued liabilities | $ | 37 | $ | 39 | ||||||||||||||
Foreign exchange contracts |
Other Assets | 10 | 17 | Other Liabilities | 6 | 7 | ||||||||||||||||||
Total derivatives designated as
hedging
instruments under ASC Topic 815 |
$ | 47 | $ | 73 | $ | 43 | $ | 46 | ||||||||||||||||
Derivatives not designated as
hedging
instruments under ASC Topic 815 |
||||||||||||||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 31 | $ | 30 | Accrued liabilities | $ | 26 | $ | 8 | ||||||||||||||
Foreign exchange contracts |
Other Assets | 1 | 1 | Other Liabilities | 1 | 1 | ||||||||||||||||||
Total derivatives not designated
as hedging
instruments under ASC Topic 815 |
$ | 32 | $ | 31 | $ | 27 | $ | 9 | ||||||||||||||||
Total derivatives |
$ | 79 | $ | 104 | $ | 70 | $ | 55 | ||||||||||||||||
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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, | ||||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||||
Revenue | 7 | (1 | ) | |||||||||||||||||||||||||||||
Foreign exchange contracts |
(34 | ) | 4 | Cost of revenue | (6 | ) | (28 | ) | Other income (expense), net | 5 | (6 | ) | ||||||||||||||||||||
Total |
(34 | ) | 4 | 1 | (29 | ) | 5 | (6 | ) | |||||||||||||||||||||||
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, | |||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
Foreign exchange contracts |
Revenue | (1 | ) | (6 | ) | Firm commitments | Revenue | 1 | 6 | |||||||||||||||||||
Foreign exchange contracts |
Cost of revenue | | 1 | Firm commitments | Cost of revenue | | (1 | ) | ||||||||||||||||||||
Total |
(1 | ) | (5 | ) | 1 | 5 | ||||||||||||||||||||||
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, | ||||||||||||
2010 | 2009 | |||||||||||
Foreign exchange contracts |
Other income (expense), net | (1 | ) | (20 | ) | |||||||
Total |
(1 | ) | (20 | ) | ||||||||
(a) | The Company expects that $5 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 $5 million and $(9) million related to the ineffective portion of the hedging relationships for the three months ended March 31, 2010 and 2009, respectively, and $4 million and $3 million related to the amount excluded from the assessment of the hedge effectiveness for the three months ended March 31, 2010 and 2009, respectively. |
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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, | ||||||||
2010 | 2009 | |||||||
Numerator: |
||||||||
Net income attributable to Company |
$ | 422 | $ | 470 | ||||
Denominator: |
||||||||
Basicweighted average common shares outstanding |
417 | 416 | ||||||
Dilutive effect of employee stock options and other
unvested stock awards |
2 | 2 | ||||||
Diluted outstanding shares |
419 | 418 | ||||||
Net income attributable to Company per share: |
||||||||
Basic |
$ | 1.01 | $ | 1.13 | ||||
Diluted |
$ | 1.01 | $ | 1.13 | ||||
Cash dividends per share |
$ | 0.10 | $ | | ||||
In addition, the Company had stock options outstanding that were anti-dilutive totaling 5 million
and 7 million shares for the three months ended March 31, 2010 and 2009, respectively.
12. Cash Dividends
On February 24, 2010, the Companys Board of Directors approved a cash dividend of $0.10 per share.
The cash dividend was paid on March 26, 2010 to each stockholder of record on March 12, 2010. Cash
dividends aggregated $42 million and nil for the three months ended March 31, 2010 and 2009,
respectively. The declaration and payment of future dividends is at the discretion of the Companys
Board of Directors and will be dependent upon the Companys results of operations, financial
condition, capital requirements and other factors deemed relevant by the Board of Directors.
13. Recently Issued Accounting Standards
In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update (ASU) No. 2010-06 Improving Disclosures about Fair Value Measurements (ASU No.
2010-06) as an update to Accounting Standards Codification Topic 820, Fair Value Measurements and
Disclosures (ASC Topic 820). ASU No. 2010-06 requires additional disclosures about transfers
between Levels 1 and 2 of the fair value hierarchy and disclosures about purchases, sales,
issuances and settlements in the roll forward of activity in Level 3 fair value measurements. ASU
No. 2010-06 is effective for interim and annual reporting periods beginning after December 15,
2009, except for the disclosures about purchases, sales, issuances, and settlements in the
rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for
fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.
The Company adopted the required provisions of ASU No. 2010-06 in the first quarter of 2010. There
was no significant impact to the Companys Consolidated Financial Statements from the adopted
provisions of ASU No. 2010-06.
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Item 2. | Managements 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. The
following describes our business segments:
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; and cranes. 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 segments 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, China, Belarus, India, Turkey,
the Netherlands, Singapore, Brazil, 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 pipelines, 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, casing and pipelines; 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, China, Kazakhstan, Mexico,
Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, Brazil, 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 segments 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, 2009, 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 and income taxes. Our estimates are based on historical
experience and on our future expectations that we believe are reasonable. The combination of these
factors forms the basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Actual results are likely to differ from our
current estimates and those differences may be material.
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EXECUTIVE SUMMARY
National Oilwell Varco generated $422 million in net income attributable to Company or $1.01 per
fully diluted share in its first quarter ended March 31, 2010. Compared to the fourth quarter of
2009 revenue declined three percent but net income attributable to Company increased seven percent.
Compared to the first quarter of 2009 revenue decreased 13 percent and net income attributable to
Company decreased 10 percent.
The first quarter of 2010 included impairment and devaluation charges totaling $38 million pre-tax,
or $0.09 per share after-tax, related to the Companys operations in Venezuela. In January 2010 the
government of Venezuela devalued the bolivar from 2.15 per U.S. dollar to 4.3 per U.S. dollar. As
a result during the first quarter of 2010 the Company converted to U.S. dollar functional currency
for its Venezuela ledgers in view of hyperinflationary conditions there; devalued monetary assets
resulting in a $27 million pre-tax charge; and wrote-down certain accounts receivable in view of
deteriorating business conditions in Venezuela, resulting in an additional $11 million charge. These charges
served to reduce the Companys net investment in Venezuela to approximately $42 million at the end
of the first quarter.
Operating profit excluding the Venezuela charge was $648 million or 21.4 percent of sales, the
highest operating margin generated by the Company since late 2008. Despite the sequential revenue
decline, operating profit on this basis increased $26 million from the fourth quarter of 2009. All
three segments posted higher sequential margins, without benefit of significant sequential sales
growth for any of the three, generally due to two major factors. First, favorable cost experience
on large offshore rig building projects being constructed in somewhat deflationary economic
conditions within Rig Technology led to higher margins than originally planned. As the Rig
Technology group has successfully executed the construction of dozens of land and offshore rigs,
the teams have successfully navigated the many complexities of rig construction, and developed
expertise that has increased efficiencies and lowered costs. As a result the segment posted record
margins of 30.8 percent during the first quarter.
Second, the Company generally experienced lower sequential and year-over-year operating costs
across all three segments, due to many initiatives undertaken to reduce costs in view of depressed
market conditions during 2009. These helped to further improve margins during the first quarter of
2010.
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 throughout 2009, but credit and
financial markets have not yet fully recovered by the first quarter of 2010, and the credit-driven
worldwide economic recession continues to dampen economic growth in most developed economies.
Asset and commodity prices, including oil and gas prices, have declined. After rising steadily for
six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to average
$42.91 per barrel during the first quarter of 2009, but recovered to average
$78.64 per barrel during the first quarter of 2010. Higher oil and gas prices over the past
several years 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 1,482 on April 23, 2010, and
averaged 1,345 rigs during the first quarter of 2010. 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 $4.00 per mmbtu
(the first quarter average was $5.15 per mmbtu). 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 986 in September 2009, but recently
climbing back to 1,074 in March 2010.
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During 2009 and the first quarter of 2010 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
modestly since the third quarter of 2009. The Companys Rig Technology
segment was less impacted owing to its high level of contracted backlog which it executed on very
well since the economic downturn.
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 worlds 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 1980s and 1990s 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, 71 percent of the existing
459 jackup rigs are more than 25 years old); 2.) to replace older mechanical and DC electric land
rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and
rigdown technology; and 3.) to build out additional deepwater floating drilling rigs, including
semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit
unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency,
safety, and capability, and that many will effectively replace a portion of the existing fleet, and
that declining dayrates may accelerate the retirement of older rigs. As a result of these trends
the Companys 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 have declined below amounts flowing out of backlog as
revenue, causing the backlog to decline to $5.4 billion by March 31, 2010.
The land rig backlog comprised 13 percent and equipment destined for offshore operations comprised
87 percent of the total backlog as of March 31, 2010. Equipment destined for international markets
totaled 91 percent of the backlog. The Company believes that its existing contracts for rig
equipment are very strong in that they carry significant down payment and progress billing terms
favorable to the ultimate completion of these projects, and generally do not allow customers to
cancel projects for convenience. Nevertheless, since the third quarter of 2008 the Company removed
$424 million in orders due to cancellations, adjustments, and changes requested by customers, which
represents 3.6 percent of the starting backlog balance. We do not expect the credit crisis or
softer market to result in additional material cancelation of contracts or abandonment of major
projects; however, there can be no assurance that such discontinuance of projects will not occur.
Segment Performance
The Rig Technology segment revenues of $1.9 billion in the first quarter of 2010 declined five
percent sequentially and declined 14 percent compared to the first quarter of 2009. Segment
operating profit was $581 million and operating margins were 30.8 percent during the first quarter.
Compared to the first quarter of 2009 decremental leverage or flow-through (the change in
operating profit divided by the change in revenue) was eight percent, and sequentially operating
profit increased $15 million despite a $91 million decline in revenue. Project margins increased as
favorable cost experience on completed rig construction projects was applied to remaining estimated
costs on ongoing projects, resulting in margins rising above original expectations. Many of these
projects were contracted at high prices in 2007 and 2008, and are now being manufactured in much
lower cost environments, and benefitting from greater project execution experience within the
group. Additionally, downsizing in certain portions of our Rig Technology manufacturing
infrastructure in the second half of 2009 contributed to the stronger margins. Non-backlog revenue
declined in Q1 due to declines in small capital equipment that do not qualify for inclusion in
backlog (generally individual orders less than $250,000), while aftermarket spares and services
were relatively flat sequentially for the group. First quarter orders for stimulation equipment
and top drives for both domestic and international markets were very strong, contributing to $618
million in gross orders booked into the backlog during the quarter. Large shale play fracture
stimulation jobs are consuming equipment at a more rapid pace owing to the upturn in oilfield
activity and higher equipment intensity in these type 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 Companys well-intervention equipment in the quarter.
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Offshore rig sales have remained muted, and although the group won three jackup rig packages in the
first quarter, no floating rig packages were won. The Company continues to pursue a large 28 rig
tender for Petrobras in Brazil, but does not expect to book many orders from this tender until
2011. These orders will require a high and rising level of local content in the construction of
new rigs.
The Petroleum Services & Supplies segment generated total sales of $923 million in the first
quarter of 2010, down $13 million or one percent sequentially from the fourth quarter of 2009 and
down $91 million or nine percent compared to the first quarter of 2009. Operating profit was $113
million or 12.2 percent of sales. Operating profit increased $6 million sequentially despite the
revenue decline, and compared to the first quarter of 2009 operating leverage or flow-through was
56 percent on the revenue decline due to lower pricing year-over-year. Strong North America rig
activity led to sequentially higher revenues across most service businesses within the segment, but
lower drill pipe sales offset these sequential improvements. Downhole tools, bits, coring
services, solids control and waste management services and equipment posted the largest gains in
North America, as customers increased drilling activity and replenished depleted inventories,
particularly in shale plays and oil productive areas. Drill pipe revenues fell nearly 40 percent
sequentially, at high decremental margins due to an unfavorable mix shift. Drill pipe revenue per
foot has trended down with the mix and is likely to decline further in the second quarter due to
higher sales in China, a very price-competitive market. However, first quarter drill pipe order
intake increased, as land drilling contractors reentered the market after a long hiatus, leading to
the first increase in drill pipe backlog since the third quarter of 2008. Overall North America
accounted for 56 percent of the segments first quarter sales, and international markets, which
constituted the majority of the groups 2009 sales, accounted for only 44 percent.
Distribution Services generated $334 million in revenue during the first quarter of 2010,
increasing one percent sequentially but decreasing 18 percent compared to the first quarter of
2009. Operating profit was $11 million, and operating margin was 3.3 percent of sales. Operating
leverage or flow-through on the small sequential sales gain was 100 percent, and decremental
flow-through on the year-over-year revenue decline was 19 percent, due to generally lower pricing.
The strong sequential margin gain in the first quarter came largely from double-digit volume
increases in the U.S., due to higher drilling activity in shale plays and oil drilling areas,
increased well hookup jobs, and higher rebates from suppliers during the quarter. Canada posted
sequential sales improvements due to higher rig counts, and industrial products posted higher
margins despite lower sales, and remain challenged due to weak economic conditions. International
sales declined sequentially due to lower sales in Mexico and lower artificial lift revenues, only
partly offset by sales into new rigs being outfitted in the Middle East.
Outlook
While the credit market downturn, global recession, and lower commodity prices presented challenges
to our business in 2009, we believe we are seeing signs of stabilization in many of our markets.
Specifically, we are encouraged by higher drilling activity in North America, and steadily higher international 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 have seen a modest improvement in orders through the
last six months on land and pressure pumping equipment. We also continue to bid a number of large
projects, including up to 28 new offshore floating rigs to be built in Brazil. We are hopeful that
these will translate into more orders late in 2010 or 2011, assuming, among other things, that rig
dayrates generally hold up well; that commodity prices remain high; and that broad economic
conditions do not deteriorate further. Nevertheless, we expect lower backlogs to lead to 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 Companys 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. Second quarter results for these segments will be
adversely affected by the seasonal decline in drilling in Canada due to spring breakup. All groups
are expecting higher steel costs to begin to flow in through the remainder of the year, owing to
tight iron ore supplies to the steel mills, which may adversely affect margins as the year unfolds.
18
Table of Contents
Operating Environment Overview
The Companys 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, pipeline maintenance activity, and
worldwide oil and gas inventory levels. Key industry indicators for the first quarter of 2010 and
2009, and the fourth quarter of 2009 include the following:
% | % | |||||||||||||||||||
1Q10 v | 1Q10 v | |||||||||||||||||||
1Q10* | 1Q09* | 4Q09* | 1Q09 | 4Q09 | ||||||||||||||||
Active Drilling Rigs: |
||||||||||||||||||||
U.S. |
1,345 | 1,326 | 1,108 | 1.4 | % | 21.4 | % | |||||||||||||
Canada |
470 | 329 | 278 | 42.9 | % | 69.1 | % | |||||||||||||
International |
1,063 | 1,026 | 1,011 | 3.6 | % | 5.1 | % | |||||||||||||
Worldwide |
2,878 | 2,681 | 2,397 | 7.3 | % | 20.1 | % | |||||||||||||
West Texas Intermediate
Crude Prices (per barrel) |
$ | 78.64 | $ | 42.91 | $ | 76.06 | 83.3 | % | 3.4 | % | ||||||||||
Natural Gas Prices
($/mmbtu) |
$ | 5.15 | $ | 4.57 | $ | 4.34 | 12.7 | % | 18.7 | % |
* | 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, 2010 on a quarterly basis:
![(PERFORMANCE GRAPH)](https://www.sec.gov/Archives/edgar/data/0001021860/000095012310046332/h70196h7019601.gif)
Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude and
Natural Gas Prices: Department of Energy, Energy Information
Administration (www.eia.doe.gov).
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The worldwide and U.S. quarterly average rig count increased 20% (from 2,397 to 2,878) and 21%
(from 1,108 to 1,345), respectively, in the first quarter of 2010 compared to the fourth quarter of
2009. The average per barrel price of West Texas Intermediate Crude increased 3% (from $76.06 per
barrel to $78.64 per barrel) and natural gas prices increased 19% (from $4.34 per mmbtu to $5.15
per mmbtu) in the first quarter of 2010 compared to the fourth quarter of 2009.
U.S. rig activity at April 23, 2010 was 1,482 rigs compared to the first quarter average of 1,345
rigs, increasing 10%. The price for West Texas Intermediate Crude was at $84.42 per barrel as of
April 23, 2010, increasing 7% from the first quarter 2010 average. The price for natural gas was
at $4.07 per mmbtu as of April 23, 2010, decreasing 21% from the first quarter 2010 average.
Results of Operations
Operating results by segment are as follows (in millions):
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
Revenue: |
||||||||
Rig Technology |
$ | 1,886 | $ | 2,199 | ||||
Petroleum Services & Supplies |
923 | 1,014 | ||||||
Distribution Services |
334 | 408 | ||||||
Elimination |
(111 | ) | (140 | ) | ||||
Total Revenue |
$ | 3,032 | $ | 3,481 | ||||
Operating Profit: |
||||||||
Rig Technology |
$ | 581 | $ | 606 | ||||
Petroleum Services & Supplies |
113 | 164 | ||||||
Distribution Services |
11 | 25 | ||||||
Unallocated expenses and eliminations |
(68 | ) | (75 | ) | ||||
Total Operating Profit |
$ | 637 | $ | 720 | ||||
Operating Profit %: |
||||||||
Rig Technology |
30.8 | % | 27.6 | % | ||||
Petroleum Services & Supplies |
12.2 | % | 16.2 | % | ||||
Distribution Services |
3.3 | % | 6.1 | % | ||||
Total Operating Profit % |
21.0 | % | 20.7 | % |
Rig Technology
Three Months Ended March 31, 2010 and 2009. Rig Technology revenue in the first quarter of 2010
was $1,886 million, a decrease of $313 million compared to the same period in 2009. Backlog was
$5.4 billion, down 43%, and new orders were $618 million, up 126% from the prior year period. This
increase in new orders is mainly driven by higher demand for safe, efficient and more powerful
equipment needed to drill in the shale gas plays.
Operating profit from Rig Technology was $581 million for the first quarter ended March 31, 2010, a
decrease of $25 million (4.1%) over the same period of 2009. Operating profit percentage increased
to 30.8%, up from 27.6% for the same prior year period primarily due to declining costs resulting
in estimate revisions on large rig projects and improved manufacturing efficiencies.
Petroleum Services & Supplies
Three Months Ended March 31, 2010 and 2009. Revenue from Petroleum Services & Supplies was $923
million for the first quarter of 2010 compared to $1,014 million for the first quarter of 2009, a
decrease of $91 million (9.0%). The decrease was primarily attributable to lower drill pipe
activity as excess pipe inventory in the market hindered customer demand for new drill
pipe.
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Operating profit from Petroleum Services & Supplies was $113 million for the first quarter of 2010
compared to $164 million for the same period in 2009, a decrease of $51 million (31.1%), and
operating profit percentage decreased to 12.2% down from 16.2% in the same period of 2009.
Decremental operating profit is a result of strong price competition and reduced volumes mainly
related to the drill pipe and downhole tool products.
Distribution Services
Three Months Ended March 31, 2010 and 2009. Revenue from Distribution Services was $334 million, a
decrease of $74 million (18.1%) during the first quarter of 2010 over the comparable 2009 period.
This decrease was primarily attributable to lower volumes and large non-recurring deliveries in the
U.S. and international markets; however, this was partly offset by improved sales in Canada as rig
count improved 43% over the same prior year period.
Operating profit from Distribution Services was $11 million for the first quarter of 2010, a
decrease of $14 million over the same period in 2009. Operating profit percentage decreased to
3.3%, from 6.1% for the same prior year period as a result of strong price competition and reduced
volumes.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $68 million for the three months ended March 31, 2010,
compared to $75 million for the same period in 2009. This decrease is primarily due to lower
intercompany profit elimination related to sales between the segments. The first quarter 2010 results included an $11 million write-down of certain accounts receivable in Venezuela.
Interest and financial costs
Interest and financial costs remained constant at $13 million for both the three months ended March
31, 2010 and 2009, respectively, due to overall debt levels remaining constant for the same
respective periods.
Other income (expense), net
Other income (expense), net were expenses, net of $16 million and $36 million for the three months
ended March 31, 2010 and 2009, respectively. The decrease in other expense was mainly due to
foreign exchange gains of $11 million in 2010 as a result
of favorable exchange rate movements in 2010, primarily related to the strengthening of the U.S.
dollar. The decrease was offset by a $27 million charge relating to the devaluation of monetary
assets the Company has in Venezuela. The charge was a result of the Venezuela bolivar being
officially devalued against the U.S. dollar.
Provision for income taxes
The effective tax rate for the three months ended March 31, 2010 was 32.0% compared to 32.5% for
the same period in 2009. The effective tax rate was positively impacted by the increase in
earnings taxed at lower rates in foreign jurisdictions, offset by lost tax benefits
associated with non-deductible foreign exchange losses resulting from the devaluation of the
Venezuelan bolivar.
Liquidity and Capital Resources
Overview
At March 31, 2010, the Company had cash and cash equivalents of $2,608 million, and total debt of
$880 million. At December 31, 2009, cash and cash equivalents were $2,622 million and total debt
was $883 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 our credit facility. The Companys outstanding
debt at March 31, 2010 consisted of $200 million of 5.65% Senior Notes due 2012, $200 million of
7.25% Senior Notes due 2011, $150 million of 6.5% Senior Notes due 2011, $150 million of 5.5%
Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $29 million.
The Company had $1,808 million of additional outstanding letters of credit at March 31, 2010,
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,
2010.
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There were no borrowings against the Companys unsecured credit facility, and there were $584
million in outstanding letters of credit issued under the facility, resulting in $1,416 million of
funds available under the Companys unsecured revolving credit facility at March 31, 2010.
The following table summarizes our net cash flows provided by operating activities, net cash used
in investing activities and net cash provided by (used in) financing activities for the periods
presented (in millions):
Three Months Ended March 31, | ||||||||
2010 | 2009 | |||||||
Net cash provided by operating activities |
$ | 95 | $ | 785 | ||||
Net cash used in investing activities |
(65 | ) | (79 | ) | ||||
Net cash provided by (used in) financing
activities |
(36 | ) | 1 |
Operating Activities
For the first three months of 2010, cash provided by operating activities decreased $690 million to
$95 million compared to cash provided by operating activities of $785 million in the same period of
2009. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by
operations primarily through net income of $419 million plus non-cash charges of $265 million less
$6 million in equity income from the Companys unconsolidated affiliate. During the first quarter
of 2010, net changes in operating assets and liabilities, net of acquisitions, decreased cash
provided by operating activities by $583 million. Total customer financing on projects, in the
form of prepayments and billings in excess of costs, less costs in excess of billings was down $670
million from December 31, 2009 due to the increase in revenues out of backlog during the first
quarter of 2010.
Investing Activities
For the first three months of 2010, cash used in investing activities was $65 million compared to
cash used in investing of $79 million for the same period of 2009. The primary reason for the
decrease in cash used in investing activities for the first
three months of 2010 related to a decrease in capital expenditures, to approximately $31 million
compared to $79 million used in the same period of 2009. In addition, the Company used $46 million
for an acquisition in the first three months of 2010, compared to nil for the same period in 2009.
Financing Activities
For the first three months of 2010, cash used in financing activities was $36 million compared to
cash provided by financing activities of $1 million for the same period of 2009. The cash used in
financing activities for the first three months of 2010 primarily related to $42 million in cash
dividends paid. No such dividends were paid in the same period of 2009. For the first three months
of 2010, the Company used its cash on hand to fund its acquisitions.
The effect of the change in exchange rates on cash flows was a negative $8 million and $18 million
for the three months ended March 31, 2010 and 2009, 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.
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Recently Issued Accounting Standards
In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update (ASU) No. 2010-06 Improving Disclosures about Fair Value Measurements (ASU No.
2010-06) as an update to Accounting Standards Codification Topic 820, Fair Value Measurements and
Disclosures (ASC Topic 820). ASU No. 2010-06 requires additional disclosures about transfers
between Levels 1 and 2 of the fair value hierarchy and disclosures about purchases, sales,
issuances and settlements in the roll forward of activity in Level 3 fair value measurements. ASU
No. 2010-06 is effective for interim and annual reporting periods beginning after December 15,
2009, except for the disclosures about purchases, sales, issuances, and settlements in the
rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for
fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.
The Company adopted the required provisions of ASU No. 2010-06 in the first quarter of 2010. There
was no significant impact to the Companys Consolidated Financial Statements from the adopted
provisions of ASU No. 2010-06.
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, 2009,
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.
23
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 do impact income. We recorded a
foreign exchange gain in our income statement of approximately $11 million in the first three
months of 2010, compared to a $26 million foreign exchange loss in the same period of the prior
year. The gains/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 the current economic environment. 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 gives 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 Companys foreign currency exchange risk grouped by functional
currency and their expected maturity periods as of March 31, 2010 (in millions, except contract
rates):
As of March 31, 2010 | December 31, | |||||||||||||||||||
Functional Currency | 2010 | 2011 | 2012 | Total | 2009 | |||||||||||||||
CAD Buy USD/Sell CAD: |
||||||||||||||||||||
Notional amount to buy (in Canadian dollars) |
295 | | | 295 | 291 | |||||||||||||||
Average CAD to USD contract rate |
1.0415 | | | 1.0415 | 1.0418 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
(6 | ) | | | (6 | ) | 2 | |||||||||||||
Sell USD/Buy CAD: |
||||||||||||||||||||
Notional amount to sell (in Canadian dollars) |
73 | 10 | | 83 | 69 | |||||||||||||||
Average CAD to USD contract rate |
1.0768 | 1.0615 | | 1.0749 | 1.1109 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
4 | | | 4 | 4 | |||||||||||||||
EUR Buy USD/Sell EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
92 | | | 92 | 98 | |||||||||||||||
Average USD to EUR contract rate |
1.4340 | | | 1.4340 | 1.4356 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
8 | | | 8 | | |||||||||||||||
Sell USD/Buy EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
52 | 12 | | 64 | 91 | |||||||||||||||
Average USD to EUR contract rate |
1.4242 | 1.3936 | | 1.4184 | 1.3896 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
(4 | ) | (1 | ) | | (5 | ) | 4 | ||||||||||||
KRW Sell EUR/Buy KRW: |
||||||||||||||||||||
Notional amount to buy (in South Korean won) |
2,952 | 273 | | 3,225 | 5,050 | |||||||||||||||
Average KRW to EUR contract rate |
1,659.06 | 1,742.53 | | 1,665.81 | 1,639.00 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
| | | | |
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As of March 31, 2010 | December 31, | |||||||||||||||||||
Functional Currency | 2010 | 2011 | 2012 | Total | 2009 | |||||||||||||||
Sell USD/Buy KRW: |
||||||||||||||||||||
Notional amount to buy (in South Korean won) |
66,468 | 61,779 | 3,264 | 131,511 | 153,226 | |||||||||||||||
Average KRW to USD contract rate |
1,030.97 | 1,083.50 | 1,118.05 | 1,057.09 | 1,046.00 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
(6 | ) | (3 | ) | | (9 | ) | (18 | ) | |||||||||||
GBP Buy USD/Sell GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds
Sterling) |
11 | | | 11 | 11 | |||||||||||||||
Average USD to GBP contract rate |
1.5880 | | | 1.5880 | 1.5880 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
| | | | | |||||||||||||||
Sell USD/Buy GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds
Sterling) |
18 | 4 | | 22 | 2 | |||||||||||||||
Average USD to GBP contract rate |
1.4592 | 1.4934 | | 1.4949 | 1.5313 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
| | | | | |||||||||||||||
USD Buy DKK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
44 | | | 44 | 44 | |||||||||||||||
Average DKK to USD contract rate |
5.0891 | | | 5.0891 | 5.1219 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
(4 | ) | | | (4 | ) | (1 | ) | ||||||||||||
Buy EUR/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
256 | 11 | | 267 | 382 | |||||||||||||||
Average USD to EUR contract rate |
1.3823 | 1.4028 | | 1.3831 | 1.4578 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
(7 | ) | (1 | ) | | (8 | ) | (7 | ) | |||||||||||
Buy GBP/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
74 | | | 74 | 76 | |||||||||||||||
Average USD to GBP contract rate |
1.6251 | | | 1.6251 | 1.6348 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
(5 | ) | | | (5 | ) | (2 | ) | ||||||||||||
Buy NOK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
748 | 387 | 77 | 1,212 | 1,094 | |||||||||||||||
Average NOK to USD contract rate |
6.1116 | 6.2326 | 6.0559 | 6.1467 | 6.2269 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
13 | 10 | | 23 | 67 | |||||||||||||||
Sell DKK/Buy USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
11 | | | 11 | 6 | |||||||||||||||
Average DKK to USD contract rate |
5.3125 | | | 5.3125 | 5.0009 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
| | | | | |||||||||||||||
Sell EUR/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
13 | 4 | | 17 | 56 | |||||||||||||||
Average USD to EUR contract rate |
1.3802 | 1.2809 | | 1.3568 | 1.4324 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
| | | | | |||||||||||||||
Sell NOK/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
419 | 24 | 4 | 447 | 408 | |||||||||||||||
Average NOK to USD contract rate |
5.8930 | 6.0495 | 6.1352 | 5.9034 | 5.8307 | |||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
7 | | | 7 | | |||||||||||||||
Other Currencies |
||||||||||||||||||||
Fair Value at March 31, 2010 in U.S. dollars |
3 | 1 | | 4 | | |||||||||||||||
Total Fair Value at March 31, 2010 in U.S. dollars |
3 | 6 | | 9 | 49 | |||||||||||||||
The Company had other financial market risk sensitive instruments denominated in foreign currencies
totaling $70 million as of March 31, 2010 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 these other financial market risk sensitive instruments could
affect net income by $5 million.
25
Table of Contents
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, 2010 our long term borrowings consisted of $150 million in 6.5% Senior Notes, $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 other
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 Companys management, including the Companys Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of
the Companys disclosure controls and procedures. The Companys 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
Companys management, including the Companys 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 Companys Chief Executive
Officer and Chief Financial Officer concluded that the Companys 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.
26
Table of Contents
PART II OTHER INFORMATION
Item 6. | Exhibits |
Reference is hereby made to the Exhibit Index commencing on page 28.
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 7, 2010
|
By: /s/ Clay C. Williams
|
|||
Executive Vice President and Chief Financial Officer | ||||
(Duly Authorized Officer, Principal Financial and Accounting Officer) |
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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) |
28
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
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Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended. | |
31.2
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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
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Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101
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The following materials from our Quarterly Report on Form 10-Q for the period ended March 31, 2010 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.
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