NOV Inc. - Quarter Report: 2010 September (Form 10-Q)
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 SEPTEMBER 30, 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 November 1, 2010 the
registrant had 419,635,478 shares of common stock, par value $.01 per share,
outstanding.
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 3,070 | $ | 2,622 | ||||
Receivables, net |
2,408 | 2,187 | ||||||
Inventories, net |
3,562 | 3,490 | ||||||
Costs in excess of billings |
769 | 740 | ||||||
Deferred income taxes |
232 | 290 | ||||||
Prepaid and other current assets |
285 | 269 | ||||||
Total current assets |
10,326 | 9,598 | ||||||
Property, plant and equipment, net |
1,808 | 1,836 | ||||||
Deferred income taxes |
269 | 92 | ||||||
Goodwill |
5,525 | 5,489 | ||||||
Intangibles, net |
3,877 | 4,052 | ||||||
Investment in unconsolidated affiliate |
365 | 393 | ||||||
Other assets |
61 | 72 | ||||||
Total assets |
$ | 22,231 | $ | 21,532 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 585 | $ | 584 | ||||
Accrued liabilities |
2,289 | 2,267 | ||||||
Billings in excess of costs |
293 | 1,090 | ||||||
Current portion of long-term debt and short-term borrowings |
354 | 7 | ||||||
Accrued income taxes |
351 | 226 | ||||||
Total current liabilities |
3,872 | 4,174 | ||||||
Long-term debt |
516 | 876 | ||||||
Deferred income taxes |
2,197 | 2,091 | ||||||
Other liabilities |
242 | 163 | ||||||
Total liabilities |
6,827 | 7,304 | ||||||
Commitments and contingencies |
||||||||
Stockholders equity: |
||||||||
Common stock par value $.01; 419,167,762 and 418,451,731 shares issued
and outstanding at September 30, 2010 and December 31, 2009 |
4 | 4 | ||||||
Additional paid-in capital |
8,267 | 8,214 | ||||||
Accumulated other comprehensive income |
109 | 90 | ||||||
Retained earnings |
6,906 | 5,805 | ||||||
Total Company stockholders equity |
15,286 | 14,113 | ||||||
Noncontrolling interests |
118 | 115 | ||||||
Total stockholders equity |
15,404 | 14,228 | ||||||
Total liabilities and stockholders equity |
$ | 22,231 | $ | 21,532 | ||||
See notes to unaudited consolidated financial statements.
2
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 | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenue |
$ | 3,011 | $ | 3,087 | $ | 8,984 | $ | 9,578 | ||||||||
Cost of revenue |
2,066 | 2,196 | 6,149 | 6,773 | ||||||||||||
Gross profit |
945 | 891 | 2,835 | 2,805 | ||||||||||||
Selling, general and administrative |
349 | 279 | 1,012 | 932 | ||||||||||||
Intangible asset impairment |
| | | 147 | ||||||||||||
Transaction and restructuring costs |
| 11 | | 19 | ||||||||||||
Operating profit |
596 | 601 | 1,823 | 1,707 | ||||||||||||
Interest and financial costs |
(12 | ) | (14 | ) | (38 | ) | (40 | ) | ||||||||
Interest income |
4 | 4 | 9 | 8 | ||||||||||||
Equity income in unconsolidated affiliate |
8 | 1 | 22 | 45 | ||||||||||||
Other income (expense), net |
(23 | ) | (13 | ) | (42 | ) | (87 | ) | ||||||||
Income before income taxes |
573 | 579 | 1,774 | 1,633 | ||||||||||||
Provision for income taxes |
169 | 192 | 552 | 551 | ||||||||||||
Net income |
404 | 387 | 1,222 | 1,082 | ||||||||||||
Net income (loss) attributable to noncontrolling interests |
| 2 | (5 | ) | 7 | |||||||||||
Net income attributable to Company |
$ | 404 | $ | 385 | $ | 1,227 | $ | 1,075 | ||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 0.97 | $ | 0.93 | $ | 2.94 | $ | 2.58 | ||||||||
Diluted |
$ | 0.96 | $ | 0.92 | $ | 2.93 | $ | 2.58 | ||||||||
Cash dividends per share |
$ | 0.10 | $ | | $ | 0.30 | $ | | ||||||||
Weighted average shares outstanding: |
||||||||||||||||
Basic |
417 | 416 | 417 | 416 | ||||||||||||
Diluted |
419 | 418 | 419 | 417 | ||||||||||||
See notes to unaudited consolidated financial statements.
3
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 1,222 | $ | 1,082 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
378 | 364 | ||||||
Equity income in unconsolidated affiliate |
(22 | ) | (45 | ) | ||||
Dividend from unconsolidated affiliate |
17 | 86 | ||||||
Intangible asset impairment |
| 147 | ||||||
Other, net |
29 | (53 | ) | |||||
Change in operating assets and liabilities, net of acquisitions: |
||||||||
Receivables |
(238 | ) | 979 | |||||
Inventories |
(101 | ) | 103 | |||||
Costs in excess of billings |
(29 | ) | 7 | |||||
Prepaid and other current assets |
(15 | ) | (122 | ) | ||||
Accounts payable |
1 | (384 | ) | |||||
Billings in excess of costs |
(797 | ) | (545 | ) | ||||
Other assets/liabilities, net |
290 | 350 | ||||||
Net cash provided by operating activities |
735 | 1,969 | ||||||
Cash flows from investing activities: |
||||||||
Purchases of property, plant and equipment |
(140 | ) | (186 | ) | ||||
Business acquisitions, net of cash acquired |
(69 | ) | (392 | ) | ||||
Business divestitures, net of cash disposed |
| 251 | ||||||
Dividend from unconsolidated affiliate |
16 | 8 | ||||||
Other |
23 | | ||||||
Net cash used in investing activities |
(170 | ) | (319 | ) | ||||
Cash flows from financing activities: |
||||||||
Borrowings against lines of credit and other debt |
2 | 7 | ||||||
Repayments on debt |
(13 | ) | (35 | ) | ||||
Cash dividends paid |
(126 | ) | | |||||
Other, net |
14 | 3 | ||||||
Net cash used in financing activities |
(123 | ) | (25 | ) | ||||
Effect of exchange rates on cash |
6 | 24 | ||||||
Increase in cash equivalents |
448 | 1,649 | ||||||
Cash and cash equivalents, beginning of period |
2,622 | 1,543 | ||||||
Cash and cash equivalents, end of period |
$ | 3,070 | $ | 3,192 | ||||
Supplemental disclosures of cash flow information: |
||||||||
Cash payments during the period for: |
||||||||
Interest |
$ | 38 | $ | 37 | ||||
Income taxes |
$ | 344 | $ | 603 |
See notes to unaudited consolidated financial statements.
4
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 and nine months ended September 30, 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):
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Raw materials and supplies |
$ | 671 | $ | 704 | ||||
Work in process |
1,184 | 1,307 | ||||||
Finished goods and purchased products |
1,707 | 1,479 | ||||||
Total |
$ | 3,562 | $ | 3,490 | ||||
5
3. Accrued Liabilities
Accrued liabilities consist of (in millions):
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Compensation |
$ | 344 | $ | 272 | ||||
Customer prepayments and
billings |
396 | 500 | ||||||
Warranty |
220 | 217 | ||||||
Interest |
14 | 11 | ||||||
Taxes (non income) |
83 | 95 | ||||||
Insurance |
52 | 58 | ||||||
Accrued purchase orders |
869 | 853 | ||||||
Fair value of derivatives |
42 | 61 | ||||||
Other |
269 | 200 | ||||||
Total |
$ | 2,289 | $ | 2,267 | ||||
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 |
43 | |||
Amounts incurred |
(31 | ) | ||
Foreign currency translation and other |
(9 | ) | ||
Balance at September 30, 2010 |
$ | 220 | ||
4. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
Costs incurred on uncompleted contracts |
$ | 7,114 | $ | 6,276 | ||||
Estimated earnings |
4,858 | 3,735 | ||||||
11,972 | 10,011 | |||||||
Less: Billings to date |
11,496 | 10,361 | ||||||
$ | 476 | $ | (350 | ) | ||||
Costs and estimated earnings in excess of
billings on uncompleted contracts |
$ | 769 | $ | 740 | ||||
Billings in excess of costs and estimated
earnings on uncompleted contracts |
(293 | ) | (1,090 | ) | ||||
$ | 476 | $ | (350 | ) | ||||
6
5. Comprehensive Income
The components of comprehensive income are as follows (in millions):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net income |
$ | 404 | $ | 387 | $ | 1,222 | $ | 1,082 | ||||||||
Currency translation adjustments, net of tax |
92 | 22 | 16 | 79 | ||||||||||||
Changes in derivative financial instruments, net of tax |
84 | 69 | 3 | 174 | ||||||||||||
Changes in defined benefit plans, net of tax |
| 1 | | | ||||||||||||
Comprehensive income |
580 | 479 | 1,241 | 1,335 | ||||||||||||
Comprehensive income (loss) attributable to noncontrolling interest |
| 2 | (5 | ) | 7 | |||||||||||
Comprehensive income attributable to Company |
$ | 580 | $ | 477 | $ | 1,246 | $ | 1,328 | ||||||||
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 September 30, 2010, a majority of these local currencies strengthened against
the U.S. dollar resulting in a net increase to Other Comprehensive Income of $92 million upon the
translation of their financial statements from their local currency to the U.S. dollar.
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 Companys net investment in Venezuela was $34
million at September 30, 2010.
The effect of changes in the fair values of derivatives designated as cash flow hedges are
accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which
they are designed to hedge are realized. The movement in Other Comprehensive Income from period to
period will be the result of the combination of changes in fair value for open derivatives and the
outflow of accumulated Other Comprehensive Income related to the fair value of derivatives that
have settled in the current or prior periods. The accumulated effect
is an increase in Other
Comprehensive Income of $84 million (net of tax of $33 million) for the three months ended
September 30, 2010.
7
6. Business Segments
Operating results by segment are as follows (in millions):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 1,650 | $ | 2,000 | $ | 5,208 | $ | 6,116 | ||||||||
Petroleum Services & Supplies |
1,089 | 882 | 3,045 | 2,809 | ||||||||||||
Distribution Services |
424 | 306 | 1,123 | 1,019 | ||||||||||||
Elimination |
(152 | ) | (101 | ) | (392 | ) | (366 | ) | ||||||||
Total Revenue |
$ | 3,011 | $ | 3,087 | $ | 8,984 | $ | 9,578 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology |
$ | 478 | $ | 577 | $ | 1,564 | $ | 1,717 | ||||||||
Petroleum Services & Supplies |
164 | 82 | 415 | 195 | ||||||||||||
Distribution Services |
24 | 7 | 48 | 42 | ||||||||||||
Unallocated expenses and
eliminations |
(70 | ) | (54 | ) | (204 | ) | (228 | ) | ||||||||
Transaction costs |
| (11 | ) | | (19 | ) | ||||||||||
Total Operating Profit |
$ | 596 | $ | 601 | $ | 1,823 | $ | 1,707 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology |
29.0 | % | 28.9 | % | 30.0 | % | 28.1 | % | ||||||||
Petroleum Services & Supplies |
15.1 | % | 9.3 | % | 13.6 | % | 6.9 | % | ||||||||
Distribution Services |
5.7 | % | 2.3 | % | 4.3 | % | 4.1 | % | ||||||||
Total Operating Profit % |
19.8 | % | 19.5 | % | 20.3 | % | 17.8 | % |
The Company had revenues of 14% and 17% of total revenue from one of its customers for the
three and nine months ended September 30, 2010, respectively, and revenues of 19% and 17% of total
revenue from one of its customers for the three and nine months ended September 30, 2009,
respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are
drillship owners and drilling contractors. This 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.
8
7. Debt
Debt consists of (in millions):
September 30, | 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 |
202 | 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 |
16 | 26 | ||||||
Total debt |
870 | 883 | ||||||
Less current portion |
354 | 7 | ||||||
Long-term debt |
$ | 516 | $ | 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 September 30, 2010, there were no borrowings
against the remaining credit facility, and there were $517 million in outstanding letters of credit
issued under this facility, resulting in $1,483 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 $1,213 million of additional outstanding letters of credit at September 30,
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 September 30,
2010.
9
8. Tax
The effective tax rate for the three and nine months ended September 30, 2010 was 29.5% and 31.1%,
respectively, compared to 33.2% and 33.7% for the same period in 2009. The effective tax rate was
positively impacted by earnings taxed at lower rates in foreign jurisdictions, and the reversal of
reserves associated with uncertain tax positions related to prior years for which the statute of
limitations expired during the period.
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 | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Federal income tax at U.S. federal
statutory rate |
$ | 201 | $ | 203 | $ | 621 | $ | 572 | ||||||||
Foreign income tax rate differential |
(28 | ) | (23 | ) | (86 | ) | (81 | ) | ||||||||
State income tax, net of federal benefit |
3 | 4 | 10 | 12 | ||||||||||||
Foreign dividends, net of foreign tax
credits |
2 | 3 | 9 | 10 | ||||||||||||
Benefit of U.S. Manufacturing Deduction |
(8 | ) | (6 | ) | (14 | ) | (13 | ) | ||||||||
Change in tax reserves, including interest |
(5 | ) | 7 | (19 | ) | 4 | ||||||||||
Prior year tax on revaluation gains in
Norway |
| | | 21 | ||||||||||||
Other |
4 | 4 | 31 | 26 | ||||||||||||
Provision for income taxes |
$ | 169 | $ | 192 | $ | 552 | $ | 551 | ||||||||
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 September 30, 2010 was $121 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 in the first quarter of 2010, we now believe it is
more-likely-than-not this foreign tax position will 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 |
80 | |||
Reductions for lapse of applicable statutes of
limitations |
(17 | ) | ||
Balance at September 30, 2010 |
$ | 121 | ||
The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The
Company has significant operations in the U.S., Canada, the U.K., the Netherlands and Norway. Tax
years that remain subject to examination by major tax jurisdiction vary by legal entity, but are
generally open in the U.S. for the tax years after 2006 and outside the U.S. for tax years ending
after 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.
10
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
September 30, 2010, 8,120,958 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 share-based compensation arrangements under the Plan was $17 million and $50
million for the three and nine months ended September 30, 2010, respectively, and $15 million and
$46 million for the three and nine months ended September 30, 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 and $15 million for the three and nine months ended
September 30, 2010, respectively, and $5 million and $17 million for the three and nine months
ended September 30, 2009, respectively.
During the nine months ended September 30, 2010, the Company granted 3,485,283 stock options and
558,531 restricted stock awards, which includes 171,400 performance-based restricted stock awards.
Out of the total number of stock options granted, 3,443,107 were granted on February 16, 2010 with
an exercise price of $44.07, 10,844 were granted on May 12, 2010 with an exercise price of $41.09
and the remaining 31,332 options were granted May 12, 2010 to the non-employee members of the Board
of Directors at an exercise price of $41.09. These options generally vest over a three-year period
from the grant date. Out of the total number of restricted stock awards granted, 543,035 were
granted on February 16, 2010 and 1,440 were granted on May 12, 2010 and vest on the third
anniversary of the date of grant. In addition, on May 12, 2010, 14,056 restricted stock awards were
granted to the non-employee members of the Board of Directors. These restricted stock awards vest
in equal thirds over three years on the anniversary of the grant date. The performance-based
restricted stock awards of 171,400 were granted on 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 Consolidated Balance Sheet at
fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative
instrument depends on whether it has been designated and qualifies as part of a hedging
relationship and further, on the type of hedging relationship. For those derivative instruments
that are designated and qualify as hedging instruments, a company must designate the hedging
instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a
hedge of a net investment in a foreign operation.
The Company is exposed to certain risks relating to its ongoing business operations. The primary
risks managed by using derivative instruments are foreign currency exchange rate risk and interest
rate risk. Forward contracts against various foreign currencies are entered into to manage the
foreign currency exchange rate risk on forecasted revenue and expenses denominated in currencies
other than the functional currency of the operating unit (cash flow hedge). Other forward exchange
contracts against various foreign currencies are entered into to manage the foreign currency
exchange rate risk associated with certain firm commitments denominated in currencies other than
the functional currency of the operating unit (fair value hedge). In addition, the Company will
enter into non-designated forward contracts against various foreign currencies to manage the
foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts
(non-designated hedge). Interest rate swaps are entered into to manage interest rate risk
associated with the Companys fixed and floating-rate borrowings.
The Company records all derivative financial instruments at their fair value in its Consolidated
Balance Sheet. Except for certain non-designated hedges discussed below, all derivative financial
instruments that the Company holds are designated as either cash flow or fair value hedges and are
highly effective in offsetting movements in the underlying risks. Such arrangements typically have
terms between two and 24 months, but may have longer terms depending on the underlying cash flows
being hedged, typically related to the projects in our backlog. The Company may also use interest
rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt
issuances.
At September 30, 2010, the Company has determined that its financial assets of $84 million and
liabilities of $43 million (primarily currency related derivatives) are level 2 in the fair value
hierarchy. At September 30, 2010, the net fair value of the Companys foreign currency forward
contracts totaled an asset of $41 million.
11
As of September 30, 2010, the Company did not have any interest rate swaps and its financial
instruments do not contain any credit-risk-related or other contingent features that could cause
accelerated payments when the Companys financial instruments are in net liability positions. We do
not use derivative financial instruments for trading or speculative purposes.
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 September 30, 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 |
£ | 11 | ||
Danish Krone |
DKK | 48 | ||
Euro |
| 107 | ||
Norwegian Krone |
NOK | 5,231 | ||
U.S. Dollar |
$ | 244 |
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.
12
As of September 30, 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 |
$ | 10 | ||
Korean Won |
KRW | 5,479 |
Non-designated Hedging Strategy
For derivative instruments that are non-designated, the gain or loss on the derivative instrument
subject to the hedged risk (i.e. nonfunctional currency monetary accounts) are recognized in
other income (expense), net in current earnings.
The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary
accounts. The purpose of the 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 September 30, 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 |
£ | 14 | ||
Danish Krone |
DKK | 136 | ||
Euro |
| 56 | ||
Norwegian Krone |
NOK | 2,072 | ||
U.S. Dollar |
$ | 447 |
As of September 30, 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 | |||||||||||||||||||
September 30, | December 31, | Balance Sheet | September 30, | December 31, | ||||||||||||||||
Balance Sheet | 2010 | 2009 | Location | 2010 | 2009 | |||||||||||||||
Derivatives designated as hedging
instruments under ASC Topic 815 |
||||||||||||||||||||
Foreign exchange contracts |
Prepaid and other current assets |
$ | 55 | $ | 56 | Accrued liabilities | $ | 14 | $ | 39 | ||||||||||
Foreign exchange contracts |
Other Assets | 13 | 17 | Other Liabilities | 3 | 7 | ||||||||||||||
Total derivatives designated as hedging
instruments under ASC Topic 815 |
$ | 68 | $ | 73 | $ | 17 | $ | 46 | ||||||||||||
Derivatives not designated as hedging
instruments under ASC Topic 815 |
||||||||||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 16 | $ | 30 | Accrued liabilities | $ | 26 | $ | 8 | ||||||||||
Foreign exchange contracts |
Other Assets | | 1 | Other Liabilities | | 1 | ||||||||||||||
Total derivatives not designated as hedging
instruments under ASC Topic 815 |
$ | 16 | $ | 31 | $ | 26 | $ | 9 | ||||||||||||
Total derivatives |
$ | 84 | $ | 104 | $ | 43 | $ | 55 | ||||||||||||
13
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) | |||||||||||||||||||||||||||
Nine Months Ended | Nine Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||
September 30, | September 30, | September 30, | ||||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||||
Revenue | 6 | 18 | ||||||||||||||||||||||||||||||
Foreign exchange contracts |
(14 | ) | 162 | Cost of revenue | (26 | ) | (51 | ) | Other income (expense), net | 5 | (27 | ) | ||||||||||||||||||||
Total |
(14 | ) | 162 | (20 | ) | (33 | ) | 5 | (27 | ) | ||||||||||||||||||||||
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 | |||||||||||||||||||||||
Nine Months Ended | Nine Months Ended | |||||||||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
Foreign exchange contracts |
Revenue | (1 | ) | (5 | ) | Firm commitments | Revenue | 1 | 5 | |||||||||||||||||||
Foreign exchange contracts |
Cost of revenue | | 1 | Firm commitments | Cost of revenue | | (1 | ) | ||||||||||||||||||||
Total |
(1 | ) | (4 | ) | 1 | 4 | ||||||||||||||||||||||
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 | ||||||||||
Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2010 | 2009 | |||||||||||
Foreign exchange contracts |
Other income (expense), net | 8 | (14 | ) | ||||||||
Total |
8 | (14 | ) | |||||||||
(a) | The Company expects that ($35) 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 $(27) million related to the ineffective portion of the hedging relationships for the nine months ended September 30, 2010 and 2009, respectively, and $8 million and $2 million related to the amount excluded from the assessment of the hedge effectiveness for the nine months ended September 30, 2010 and 2009, respectively. |
14
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 | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Numerator: |
||||||||||||||||
Net income attributable to Company |
$ | 404 | $ | 385 | $ | 1,227 | $ | 1,075 | ||||||||
Denominator: |
||||||||||||||||
Basicweighted average common shares outstanding |
417 | 416 | 417 | 416 | ||||||||||||
Dilutive effect of employee stock options and
other unvested stock awards |
2 | 2 | 2 | 1 | ||||||||||||
Diluted outstanding shares |
419 | 418 | 419 | 417 | ||||||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 0.97 | $ | 0.93 | $ | 2.94 | $ | 2.58 | ||||||||
Diluted |
$ | 0.96 | $ | 0.92 | $ | 2.93 | $ | 2.58 | ||||||||
Cash dividends per share |
$ | 0.10 | $ | | $ | 0.30 | $ | | ||||||||
In addition, the Company had stock options outstanding that were anti-dilutive totaling 6
million shares for both the three and nine months ended September 30, 2010, and 4 million and 6
million for the three and nine months ending September 30, 2009, respectively.
12. Cash Dividends
On August 18, 2010, the Companys Board of Directors approved a cash dividend of $0.10 per share.
The cash dividend was paid on September 24, 2010 to each stockholder of record on September 10,
2010. Cash dividends aggregated $42 million and $126 million for the three and nine months ended
September 30, 2010, respectively, and nil for both the three and nine months ended September 30,
2009. 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 Companys 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.
15
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 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 adding
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; service and product warranties and income taxes. Our
estimates are based on historical experience and on our future expectations that we believe are
reasonable. The combination of these factors forms the basis for making judgments about the
carrying values of assets and liabilities that are not readily apparent from other sources. Actual
results are likely to differ from our current estimates and those differences may be material.
16
EXECUTIVE SUMMARY
National Oilwell Varco generated $404 million in net income attributable to the Company, or $0.96
per fully diluted share, on $3.0 billion in revenue in its third quarter ended September 30, 2010.
Compared to the second quarter of 2010 revenue increased two percent and net income attributable to
the Company increased one percent. Compared to the third quarter of 2009 revenue decreased two
percent and net income attributable to the Company increased five percent.
Operating profit excluding transaction charges of $2 million was $598 million or 19.9 percent of
sales in the third quarter of 2010, compared to $594 million or 20.2 percent of sales in the second
quarter of 2010 excluding transaction charges of $4 million. Operating profit excluding
transaction and restructuring charges was $618 million or 20.0 percent of sales for the third
quarter of 2009.
Revenues, operating profit and operating margins increased both sequentially and year-over-year for
the Companys Petroleum Services & Supplies and Distribution Services segments. The Companys Rig
Technology segment posted one percent lower revenues sequentially and
18 percent lower revenues
compared to the prior year third quarter, due primarily to lower revenues from the segments
backlog of capital equipment orders. The Company generally benefitted from initiatives undertaken
throughout all three segments to reduce operating costs in view of depressed market conditions
during 2009.
A moratorium on deepwater drilling in the Gulf of Mexico was enacted during the second quarter of
2010 following the Macondo well blowout and oil spill, which continued through the third quarter of
2010. We estimate that the drilling moratorium reduced earnings by approximately two cents per
fully diluted share, with most of the impact affecting the Petroleum Services & Supplies segment.
We expect a similar impact in the fourth quarter of 2010. The Distribution Services segment posted
higher sales in the Gulf Coast as it helped outfit the response effort with basic supplies during
the third quarter, but it has seen these incremental Gulf Coast sales decline significantly during
the fourth quarter. We are hopeful that the on-going rebound in U.S. drilling activity will offset
this decline to some degree. The Rig Technology group saw modestly higher purchases of spares and
consumables among the affected rigs, which appear to be utilizing this period of low drilling
activity in the Gulf of Mexico to conduct upgrade and maintenance activities. Although the
moratorium has been lifted, some offshore drilling contractors appear to be pausing to see the
ultimate resolution of new pressure control equipment requirements, and as a result some specific
purchases, such as drill pipe and conductor pipe connections, are at risk pending the outcome of
this pause.
Oil & Gas Equipment and Services Market
Worldwide, developed economies turned down sharply in late 2008 as looming housing-related asset
write-downs at major financial institutions paralyzed credit markets and sparked a serious global
banking crisis. Major central banks responded vigorously through 2009, but a credit-driven
worldwide economic recession continues to dampen economic growth in many developed economies. As a
result asset and commodity prices, including oil and gas prices, declined. After rising steadily
for six years to peak at around $140 per barrel earlier in 2008, oil prices collapsed back to
average $42.91 per barrel (West Texas Intermediate Crude Prices) during the first quarter of 2009,
but recovered into the $70 to $80 per barrel range by the end of 2009 where they are holding steady
(the third quarter of 2010 averaged $76.05 per barrel). North American gas prices declined to
$3.17 per mmbtu in the third quarter of 2009 but recovered to average $4.28 per mmbtu in the third
quarter of 2010. The steadily rising oil and gas prices seen between 2003 and 2008 led to high
levels of exploration and development drilling in many oil and gas basins around the globe by 2008,
but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit
availability.
The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the
level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a
low of 876 in June 2009. U.S. rig count has since increased to 1,672 in late October 2010, and
averaged 1,622 rigs during the third 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
and, more recently, as operators began to drill unconventional shale plays targeting oil, rather
than gas. Oil drilling has risen to 42 percent of the total domestic drilling effort.
17
Most international activity is driven by oil exploration and production by national oil companies,
which has historically been less susceptible to short-term commodity price swings, but the
international rig count has exhibited modest declines nonetheless, falling from its September 2008
peak of 1,108 to 947 in August 2009, but recently climbing back to 1,120 in September 2010.
During 2009 the Company saw its Petroleum Services & Supplies and its Distribution Services margins
affected most acutely by a drilling downturn, through both volume and price declines; nevertheless,
both of these segments saw pricing stabilize and revenues recover 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.) replace older mechanical and DC electric land rigs
with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown
technology; and 3.) build out additional deepwater floating drilling rigs, including
semisubmersibles and drillships, employing recent advancements in deepwater drilling to exploit
unexplored deepwater basins. We believe the newer rigs offer considerably higher efficiency,
safety, and capability, and that many will effectively replace a portion of the existing fleet, and
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 $4.9 billion by June
30, 2010. The decline was halted during the third quarter, when orders of $1.2 billion modestly
exceeded revenue out of backlog. Approximately $1.2 billion of contracted backlog is scheduled to
flow out as revenue during the fourth quarter of 2010; $3.3 billion in 2011, and the balance of
$0.4 billion thereafter. The land rig backlog comprised 19 percent and equipment destined for
offshore operations comprised 81 percent of the total backlog as of September 30, 2010. Equipment
destined for international markets totaled 85 percent of the backlog. The Company experienced
relatively minor levels of order cancellations since 2008 (less than four percent), and does not
expect additional material cancellation of contracts or abandonment of major projects; however,
there can be no assurance that such discontinuance of projects will not occur.
18
Segment Performance
The Rig Technology segment revenues of $1,650 million in the third quarter of 2010 declined one
percent sequentially and declined 17 percent compared to the third quarter of 2009. Segment
operating profit was $478 million and operating margins were 29.0 percent during the third quarter.
Compared to the second quarter of 2010, revenue declined $22 million and operating profit declined
$29 million. Compared to the third quarter of 2009 decremental operating leverage or flow-through
(the decrease in operating profit divided by the decrease in revenue) was 28 percent. Despite
sequentially lower project revenue, project margins increased slightly 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 segments overall margin performance in the third
quarter of 2010, which was modestly higher than the third quarter of 2009 despite lower volumes.
Sequentially, operating margin declined 130 basis points due to mix and slightly lower volumes.
Non-backlog revenue improved 17 percent from the second quarter to the third quarter of 2010, led
by higher sales of capital spares. Orders for stimulation equipment, top drives, handling and
lifting equipment, complete land rig packages for both domestic and international markets, and an
order for two deepwater rig drilling equipment packages for Brazil led to $1,175 million in orders
booked into the backlog during the third quarter. Revenue out of backlog of $1,157 million
declined 8 percent sequentially. Large shale play fracture stimulation jobs in North America are
consuming equipment at a more rapid pace owing to the upturn in oilfield activity and higher
equipment intensity in these types of jobs. Additionally, demand is shifting to larger diameter
coiled tubing strings to stimulate wells and drill out plugs, which led to demand for the Companys
well-intervention equipment in the quarter. Interest in offshore rig construction appears to be
ascending, and the Company submitted tenders for up to 28 deepwater rigs for Petrobras to shipyards
and drilling contractors during June and July 2010. The Company does not expect to book many
orders from this tender until 2011. The orders from this tender will require a high and rising
level of local Brazilian content in the construction of new rigs. Customer inquiries for pressure
control equipment are also trending higher, and orders for pressure control components, spares,
repair and services rose during the third quarter, in response to the Macondo blowout.
The Petroleum Services & Supplies segment generated total sales of $1,089 million in the third
quarter of 2010, up five percent from the second quarter of 2010 and
up 23 percent from the third
quarter of 2009. Operating profit was $164 million or 15.1 percent of sales during the third
quarter of 2010, compared to 13.4 percent in the second quarter and 9.8 percent in the third
quarter of 2009. Operating leverage or flow-through was 46 percent from the second quarter of 2010
to the third quarter of 2010, and 38 percent from the third quarter of 2009 to the third quarter of
2010. Helped by seasonal recovery out of breakup in Canada, and unconventional shale development
targeting oil production, rig counts across North America improved 19 percent sequentially. This
lifted the mix of North American sales for the segment to 56 percent for the quarter, compared to
54 percent in the preceding quarter, and drove sequentially higher sales overall. Most products
and services within the segment posted single-digit sequential sales gains, with drill pipe sales
improving the most, up about 10 percent sequentially due to higher demand for premium drill pipe
for shale drilling in the U.S. The backlog of drill pipe orders also increased again sequentially,
and coiled tubing sales increased on rising demand from pressure pumping customers in North
America. Sales of pumps, bits, downhole tools, pipe inspection and coating services, solids
control equipment, and waste management services also posted sequential increases largely due to
higher domestic activity.
The Distribution Services segment generated $424 million in revenue during the third quarter of
2010, increasing 16 percent from the second quarter and
increasing 39 percent from the third
quarter of 2009. Operating profit was $24 million, and operating margin was 5.7 percent of sales,
up 210 basis points from the second quarter of 2010. Operating leverage or flow-through was 19
percent sequentially and 14 percent year-over-year for the third quarter. The segment posted 13
percent revenue growth sequentially in the U.S., led by higher sales into unconventional shale
plays, higher sales of consumables to outfit newly constructed land rigs, and higher sales into the
Gulf of Mexico cleanup effort. Canadian sales increased 37 percent due to the seasonal recovery
out of breakup, and International sales increased 11 percent sequentially on higher sales of
capital spares and Mono products, partly offset by lower sales in Mexico and Australia.
19
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 and recovery in many of
our markets. Specifically we are encouraged by higher drilling activity in North America, and
steadily higher international drilling activity. Order levels for new drilling rigs declined
significantly in 2009 as compared to 2008 due to credit market conditions and softer rig activity,
but we were able to secure an order for one Brazil deepwater rig during the second quarter of 2010
and two more during the third quarter of 2010. We also continue to bid up to 28 new offshore
floating rigs to be built in Brazil, which we hope will translate into orders in 2011. 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. Certain products are seeing higher steel, alloy, resin
and fiberglass costs impacting their business while others have seen costs decline. Continuing
tight iron ore supplies to the steel mills could adversely affect margins as the year unfolds.
The Company believes it is well positioned to continue to manage through this recession, and should
benefit from its strong balance sheet and capitalization, access to credit, and a high level of
contracted orders which are expected to continue to generate earnings during the remainder of the
year. The Company has a long history of cost-control and downsizing in response to depressed
market conditions, and of executing strategic acquisitions during difficult periods. Such a period
may present opportunities to the Company to effect new organic growth and acquisition initiatives.
20
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, and worldwide oil and gas inventory
levels. Key industry indicators for the third quarter of 2010 and 2009, and the second quarter of
2010 include the following:
% | % | |||||||||||||||||||
3Q10 v | 3Q10 v | |||||||||||||||||||
3Q10* | 2Q10* | 3Q09* | 2Q10 | 3Q09 | ||||||||||||||||
Active Drilling Rigs: |
||||||||||||||||||||
U.S. |
1,622 | 1,508 | 974 | 7.6 | % | 66.5 | % | |||||||||||||
Canada |
361 | 166 | 187 | 117.5 | % | 93.0 | % | |||||||||||||
International |
1,110 | 1,088 | 969 | 2.0 | % | 14.6 | % | |||||||||||||
Worldwide |
3,093 | 2,762 | 2,130 | 12.0 | % | 45.2 | % | |||||||||||||
West Texas Intermediate
Crude Prices (per barrel) |
$ | 76.05 | $ | 77.79 | $ | 68.20 | (2.2 | %) | 11.5 | % | ||||||||||
Natural Gas Prices ($/mmbtu) |
$ | 4.28 | $ | 4.32 | $ | 3.17 | (0.9 | %) | 35.0 | % |
* | Averages for the quarters indicated. See sources below. |
The following table details the U.S., Canadian, and international rig activity and West Texas
Intermediate Oil prices for the past nine quarters ended September 30, 2010 on a quarterly basis:
![(BAR GRAFH)](https://www.sec.gov/Archives/edgar/data/0001021860/000095012310101447/h76485h7648501.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).
21
The worldwide and U.S. quarterly average rig count increased 12% (from 2,762 to 3,093) and 8% (from
1,508 to 1,622), respectively, in the third quarter compared to the second quarter of 2010. The
average per barrel price of West Texas Intermediate Crude decreased 2% (from $77.79 per barrel to
$76.05 per barrel) and natural gas prices decreased 1% (from $4.32 per mmbtu to $4.28 per mmbtu) in
the third quarter compared to the second quarter of 2010.
U.S. rig activity at October 22, 2010 was 1,669 rigs compared to the third quarter average of 1,622
rigs, increasing 3%. The price for West Texas Intermediate Crude was at $81.69 per barrel as of
October 22, 2010, increasing 7% from the third quarter 2010 average. The price for natural gas was
at $3.33 per mmbtu as of October 22, 2010, decreasing 22% from the third quarter 2010 average.
Results of Operations
Operating results by segment are as follows (in millions):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 1,650 | $ | 2,000 | $ | 5,208 | $ | 6,116 | ||||||||
Petroleum Services & Supplies |
1,089 | 882 | 3,045 | 2,809 | ||||||||||||
Distribution Services |
424 | 306 | 1,123 | 1,019 | ||||||||||||
Elimination |
(152 | ) | (101 | ) | (392 | ) | (366 | ) | ||||||||
Total Revenue |
$ | 3,011 | $ | 3,087 | $ | 8,984 | $ | 9,578 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology |
$ | 478 | $ | 577 | $ | 1,564 | $ | 1,717 | ||||||||
Petroleum Services & Supplies |
164 | 82 | 415 | 195 | ||||||||||||
Distribution Services |
24 | 7 | 48 | 42 | ||||||||||||
Unallocated expenses and eliminations |
(70 | ) | (54 | ) | (204 | ) | (228 | ) | ||||||||
Transaction costs |
| (11 | ) | | (19 | ) | ||||||||||
Total Operating Profit |
$ | 596 | $ | 601 | $ | 1,823 | $ | 1,707 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology |
29.0 | % | 28.9 | % | 30.0 | % | 28.1 | % | ||||||||
Petroleum Services & Supplies |
15.1 | % | 9.3 | % | 13.6 | % | 6.9 | % | ||||||||
Distribution Services |
5.7 | % | 2.3 | % | 4.3 | % | 4.1 | % | ||||||||
Total Operating Profit % |
19.8 | % | 19.5 | % | 20.3 | % | 17.8 | % |
Rig Technology
Three Months Ended September 30, 2010 and 2009. Rig Technology revenue in the third quarter of
2010 was $1,650 million, a decrease of $350 million (17.5%) compared to the same period in 2009,
primarily due to the decrease of revenue out of backlog of $442 million as total backlog declined
34% to $4.9 billion.
Operating profit from Rig Technology was $478 million for the third quarter ended September 30,
2010, a decrease of $99 million (17.2%) over the same period of 2009. Operating profit percentage
increased to 29.0%, up from 28.9% for the same prior year period primarily due to declining costs
resulting in estimate revisions on large rig projects and improved manufacturing efficiencies.
Nine Months ended September 30, 2010 and 2009. Rig Technology revenue for the first nine months of
2010 was $5,208 million, a decrease of $908 million (14.9%)
compared to the same period in 2009, primarily due to the decrease of
revenue out of backlog of $807 million.
Non-backlog revenue
decreased 7.2% primarily due to lower small capital equipment shipments in 2010.
22
Operating profit from Rig Technology for the first nine months of 2010 was $1,564 million, a
decrease of $153 million (8.9%) over the same period of 2009. Operating profit percentage
increased to 30.0%, up from 28.1% for the same prior year period primarily due to declining costs
resulting in estimate revisions on large rig projects as well as improved manufacturing
efficiencies.
Petroleum Services & Supplies
Three Months Ended September 30, 2010 and 2009. Revenue from Petroleum Services & Supplies was
$1,089 million for the third quarter of 2010 compared to $882 million for the third quarter of
2009, an increase of $207 million (23.5%). The increase was primarily attributable to shale plays
leading to a strong U.S. market with a 67% increase in rig activity compared to the third quarter
of 2009.
Operating profit from Petroleum Services & Supplies was $164 million for the third quarter ended
September 30, 2010, an increase of $82 million (100.0%) over the same period of 2009. Operating
profit percentage increased to 15.1%, up from 9.3% for the same prior year period primarily due to
strong domestic demand fueled by an increase in rig count.
Nine Months ended September 30, 2010 and 2009. Revenue from Petroleum Services & Supplies was
$3,045 million for the first nine months of 2010 compared to $2,809 million for the first nine
months of 2009, an increase of $236 million (8.4%). The increase was primarily attributable to a
higher level of rig activity in the U.S. market.
Operating profit from Petroleum Services & Supplies was $415 million for the first nine months of
2010 compared to $195 million for the same period in 2009, an increase of $220 million (112.8%),
and operating profit percentage increased to 13.6% up from 6.9% in the same period of 2009. The
first nine months of 2009 results included a $147 million impairment charge on the carrying value
of a trade name associated with this segment. In addition, strong domestic demand fueled by an
increase in domestic rig count contributed to the increase in operating profit.
Distribution Services
Three Months Ended September 30, 2010 and 2009. Revenue from Distribution Services was $424
million for the third quarter of 2010 compared to $306 million for the third quarter of 2009, an
increase of $118 million (38.6%). This increase was primarily attributable to increased U.S. rig
count activity and sales into the Gulf of Mexico cleanup effort.
Operating profit from Distribution Services was $24 million for the third quarter ended September
30, 2010, an increase of $17 million (242.9%) over the same period of 2009. Operating profit
percentage increased to 5.7%, up from 2.3% for the same prior year period primarily due to
increased volume in the quarter.
Nine Months ended September 30, 2010 and 2009. Revenue from Distribution Services was $1,123
million for the first nine months of 2010 compared to $1,019 million for the first nine months of
2009, an increase of $104 million (10.2%). This increase was primarily attributable to increased
U.S. rig count activity in general and due to the oil-spill in the Gulf of Mexico, which drove
significant emergency project work during the first nine months of 2010.
Operating profit from Distribution Services was $48 million for the first nine months of 2010
compared to $42 million for the same period in 2009, an increase of $6 million (14.3%), and
operating profit percentage increased to 4.3% up from 4.1% for the same prior year period primarily
due to increased volume in the quarter.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $70 million and $204 million for the three and nine
months ended September 30, 2010, respectively, compared to $54 million and $228, respectively, for
the same periods in 2009. The increase for the three months comparison is primarily due to higher
intercompany profit elimination related to sales between the segments. The decrease in the nine
months comparison is primarily due to $46 million of voluntary retirement costs that were taken in
the nine months ended September 30, 2009. This was slightly offset by higher intercompany profit
elimination related to sales between the segments and an $11 million write-down of certain accounts
receivable in Venezuela during the first nine months of 2010.
23
Interest and financial costs
Interest and financial costs were $12 million and $38 million for the three and nine months ended
September 30, 2010, respectively, compared to $14 million and $40 million, respectively, for the
same periods in 2009. The decrease in interest and financial costs was due to an overall decrease
in debt levels for the three and nine months ended September 30, 2010 compared to the same periods
in 2009.
Other income (expense), net
Other income (expense), net were expenses, net of $23 million and $42 million for the three and
nine months ended September 30, 2010, respectively, compared to $13 million and $87 million,
respectively for the same periods in 2009. The increase for the three months ended September 30,
2010, was mainly due to higher foreign exchange losses during the third quarter of 2010 as a result
of exchange rate movements, primarily related to the weakening of the U.S. dollar. The decrease for
the nine months ended September 30, 2010 was mainly due to lower foreign exchange losses during the
first nine months of 2010 as a result of exchange rate movements, primarily related to the strength
of the U.S. dollar in the first half of the year, inclusive of 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 and nine months ended September 30, 2010 was 29.5% and 31.1%,
respectively, compared to 33.2% and 33.7% for the same period in 2009. The effective tax rate was
positively impacted by earnings taxed at lower rates in foreign jurisdictions, and the reversal of
reserves associated with uncertain tax positions related to prior years for which the statute of
limitations expired during the period.
24
Liquidity and Capital Resources
Overview
At September 30, 2010, the Company had cash and cash equivalents of $3,070 million, and total debt
of $870 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 its credit facility. The
Companys outstanding debt at September 30, 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 $19 million.
There were no borrowings against the Companys unsecured revolving credit facility, and there were
$517 million in outstanding letters of credit issued under the facility, resulting in $1,483
million of funds available under the Companys unsecured revolving credit facility at September 30,
2010.
The Company had $1,213 million of additional outstanding letters of credit at September 30, 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 September 30,
2010.
The following table summarizes our net cash provided by operating activities, net cash used in
investing activities and net cash used in financing activities for the periods presented (in
millions):
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Net cash provided by operating activities |
$ | 735 | $ | 1,969 | ||||
Net cash used in investing activities |
(170 | ) | (319 | ) | ||||
Net cash used in financing activities |
(123 | ) | (25 | ) |
Operating Activities
For the first nine months of 2010,
cash provided by operating activities decreased by $1,234 million to $735 million compared to
cash provided by operating activities of $1,969 million in the same period of 2009. The
primary reason for the decrease is the reduction of customer financing on projects during
the first nine months of 2010, as backlog declined $1,532 million from $6,406 million to
$4,874 million during this period. Customer financing, as the net of prepayments, billings
in excess of costs, less costs in excess of billings, was down approximately $930 million from
December 31, 2009. Also, increased business activity in the first nine months of 2010
resulted in higher working capital and lower cash balance as accounts receivable increased
$238 million and inventory increased $101 million.
Before changes in operating assets and liabilities, net of acquisitions, cash was provided by
operations during the first nine months of 2010 primarily through net income of $1,222 million plus
depreciation and amortization of $378 million. Dividends from the Companys unconsolidated
affiliate were $17 million less $22 million in equity income from the Companys unconsolidated
affiliate. During the first nine months of 2010, net changes in operating assets and liabilities,
net of acquisitions, decreased cash provided by operating activities by $1,277 million.
The Company received $33 million and $94 million in dividends from its unconsolidated affiliate in
the first nine months of 2010 and 2009, respectively. The portion included in operating activities
in the first nine months of 2010 and 2009 was $17 million and $86 million, respectively. The
remainder of $16 million and $8 million was included in investing activities in the first nine
months of 2010 and 2009, respectively.
25
Investing Activities
For the first nine months of 2010, cash used in investing activities was $170 million compared to
cash used in investing of $319 million for the same period of 2009. The primary reason for the
decrease in cash used in investing activities for the first nine months of 2010 related to a
decrease in business acquisitions to approximately $69 million compared to $392 million used in the
same period of 2009, offset by $251 million in business divestitures. Capital expenditures
decreased to approximately $140 million compared to $186 million used in the same period of 2009.
The decreases in cash used in investing activities were offset by an increase in the portion of a
dividend received by the Companys unconsolidated affiliate during the first nine months of 2010
that related to investing activities.
Financing Activities
For the first nine months of 2010, cash used in financing activities was $123 million compared to
cash used in financing activities of $25 million for the same period of 2009. The increase in cash
used in financing activities for the first nine months of 2010 primarily related to $126 million in
cash dividends paid. No such dividends were paid in the same period of 2009. This increase was
partially offset by a decrease in payments on debt to approximately $13 million for the first nine
months of 2010 compared to $35 million for the same period in 2009. For the first nine 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 positive $6 million and $24 million
for the nine months ended September 30, 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.
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.
26
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 loss in our income statement of approximately $29 million in the first nine months
of 2010, compared to a $62 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 give rise
to foreign currency exchange rate exposure. In order to mitigate that risk, we may utilize foreign
currency forward contracts to better match the currency of our revenues and associated costs. We do
not use foreign currency forward contracts for trading or speculative purposes.
The following table details the Companys foreign currency exchange risk grouped by functional
currency and their expected maturity periods as of September 30, 2010 (in millions, except contract
rates):
As of September 30, 2010 | December 31, | |||||||||||||||||||
Functional Currency | 2010 | 2011 | 2012 | Total | 2009 | |||||||||||||||
CAD Buy USD/Sell CAD: |
||||||||||||||||||||
Notional amount to buy (in Canadian dollars) |
298 | | | 298 | 291 | |||||||||||||||
Average CAD to USD contract rate |
1.0396 | | | 1.0396 | 1.0418 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
(3 | ) | | | (3 | ) | 2 | |||||||||||||
Sell USD/Buy CAD: |
||||||||||||||||||||
Notional amount to sell (in Canadian dollars) |
52 | 14 | | 66 | 69 | |||||||||||||||
Average CAD to USD contract rate |
1.0540 | 1.0466 | | 1.0524 | 1.1109 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
1 | | | 1 | 4 | |||||||||||||||
EUR Buy USD/Sell EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
47 | | | 47 | 98 | |||||||||||||||
Average USD to EUR contract rate |
1.2890 | | | | 1.4356 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
(3 | ) | | | (3 | ) | | |||||||||||||
Sell USD/Buy EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
15 | 55 | | 70 | 91 | |||||||||||||||
Average USD to EUR contract rate |
1.4559 | 1.2935 | | 1.3279 | 1.3896 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
(1 | ) | 4 | | 3 | 4 | ||||||||||||||
KRW Sell EUR/Buy KRW: |
||||||||||||||||||||
Notional amount to buy (in South Korean won) |
1,364 | 273 | | 1,637 | 5,050 | |||||||||||||||
Average KRW to EUR contract rate |
1,742.53 | 1,742.53 | | 1,742.53 | 1,639.00 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
| | | | |
27
As of September 30, 2010 | December 31, | |||||||||||||||||||
Functional Currency | 2010 | 2011 | 2012 | Total | 2009 | |||||||||||||||
Sell USD/Buy KRW: |
||||||||||||||||||||
Notional amount to buy (in South Korean won) |
24,658 | 61,779 | 3,265 | 89,702 | 153,226 | |||||||||||||||
Average KRW to USD contract rate |
1,021.13 | 1,083.50 | 1,118.05 | 1,066.79 | 1,046.00 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
(3 | ) | (3 | ) | | (6 | ) | (18 | ) | |||||||||||
GBP Buy USD/Sell GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds Sterling) |
2 | | | 2 | 11 | |||||||||||||||
Average USD to GBP contract rate |
1.4605 | | | 1.4605 | 1.5880 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
| | | | | |||||||||||||||
Sell USD/Buy GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds Sterling) |
38 | 26 | | 64 | 2 | |||||||||||||||
Average USD to GBP contract rate |
1.5227 | 1.4435 | | 1.4903 | 1.5313 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
2 | 4 | | 6 | | |||||||||||||||
USD Buy DKK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
19 | 4 | | 23 | 44 | |||||||||||||||
Average DKK to USD contract rate |
5.5160 | 5.8409 | | 5.5672 | 5.1219 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
| | | | (1 | ) | ||||||||||||||
Buy EUR/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
77 | 107 | | 184 | 382 | |||||||||||||||
Average USD to EUR contract rate |
1.2981 | 1.2913 | | 1.2942 | 1.4578 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
4 | 6 | | 10 | (7 | ) | ||||||||||||||
Buy GBP/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
26 | 4 | | 30 | 76 | |||||||||||||||
Average USD to GBP contract rate |
1.5562 | 1.5531 | | 1.5558 | 1.6348 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
| | | | (2 | ) | ||||||||||||||
Buy NOK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
957 | 396 | 223 | 1,576 | 1,094 | |||||||||||||||
Average NOK to USD contract rate |
6.2977 | 6.2345 | 6.2479 | 6.2748 | 6.2269 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
73 | 20 | 11 | 104 | 67 | |||||||||||||||
Sell DKK/Buy USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
10 | | | 10 | 6 | |||||||||||||||
Average DKK to USD contract rate |
5.8694 | | | 5.8694 | 5.0009 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
(1 | ) | | | (1 | ) | | |||||||||||||
Sell EUR/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
19 | 5 | | 24 | 56 | |||||||||||||||
Average USD to EUR contract rate |
1.3263 | 1.2780 | | 1.3155 | 1.4324 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
| | | | | |||||||||||||||
Sell NOK/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
943 | 104 | 5 | 1,052 | 408 | |||||||||||||||
Average NOK to USD contract rate |
6.2398 | 6.2501 | 6.2539 | 6.2409 | 5.8307 | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
(62 | ) | (6 | ) | | (68 | ) | | ||||||||||||
DKK Sell DKK/Buy USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
82 | | | 82 | | |||||||||||||||
Average DKK to USD contract rate |
5.7872 | | | 5.7872 | | |||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
1 | | | 1 | | |||||||||||||||
Other Currencies |
||||||||||||||||||||
Fair Value at September 30, 2010 in U.S. dollars |
(1 | ) | (1 | ) | (1 | ) | (3 | ) | | |||||||||||
Total Fair Value at September 30, 2010 in U.S. dollars |
7 | 24 | 10 | 41 | 49 | |||||||||||||||
The Company had other financial market risk sensitive instruments denominated in foreign
currencies for transactional exposures totaling $357 million and translation exposures totaling
$458 million as of September 30, 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 the transactional exposures financial market risk sensitive instruments
could affect net income by $23 million and the transactional exposures financial market risk
sensitive instruments could affect the future fair value by $46 million.
28
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 September 30, 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 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.
29
PART II OTHER INFORMATION
Item 1A. Risk Factors
As of the date of this filing, the Company and its operations continue to be subject to the risk
factors previously disclosed in Part I, Item 1A Risk Factors in our 2009 Annual Report on Form
10-K, as well as the following risk factor:
The recent moratorium on deepwater drilling in the U.S. Gulf of Mexico and its consequences could
have a material adverse effect on our business.
A moratorium on deepwater drilling in the U.S. Gulf of Mexico was enacted during the second quarter
of 2010 following the Macondo well blowout and oil spill. Even though such moratorium has been
recently lifted, any prolonged reduction in oil and natural gas drilling and production activity as
a result of such moratorium could result in a corresponding decline in the demand for our products
and services, which could adversely impact our operating results and financial condition.
The following risk factor has been updated from our 2009 Annual Report on Form 10-K:
There are risks associated with our presence in international markets, including political or
economic instability, currency restrictions, and trade and economic sanctions.
Approximately 73% of our revenues in 2009 were derived from operations outside the United States
(based on revenue destination). Our foreign operations include significant operations in Canada,
Europe, the Middle East, Africa, Southeast Asia, Latin America and other international markets. Our
revenues and operations are subject to the risks normally associated with conducting business in
foreign countries, including uncertain political and economic environments, which may limit or
disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or
the taking of property without fair compensation. Government-owned petroleum companies located in
some of the countries in which we operate have adopted policies, or are subject to governmental
policies, giving preference to the purchase of goods and services from companies that are
majority-owned by local nationals. As a result of these policies, we may rely on joint ventures,
license arrangements and other business combinations with local nationals in these countries. In
addition, political considerations may disrupt the commercial relationships between us and
government-owned petroleum companies.
Our operations outside the United States could also expose us to trade and economic sanctions or
other restrictions imposed by the United States or other governments or organizations. The U.S.
Department of Justice (DOJ), the U.S. Securities and Exchange Commission and other federal
agencies and authorities have a broad range of civil and criminal penalties they may seek to impose
against corporations and individuals for violations of trading sanctions laws, the Foreign Corrupt
Practices Act and other federal statutes. Under trading sanctions laws, the DOJ may seek to impose
modifications to business practices, including cessation of business activities in sanctioned
countries, and modifications to compliance programs, which may increase compliance costs. If any
of the risks described above materialize, it could adversely impact our operating results and
financial condition.
We have received federal grand jury subpoenas and subsequent inquiries from governmental agencies
requesting records related to our compliance with export trade laws and regulations. We have
cooperated fully with agents from the Department of Justice, the Bureau of Industry and Security,
the Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcement in responding to
the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange
Commission in connection with the inquiries previously made by the aforementioned federal agencies.
We have conducted our own internal review of this matter. At the conclusion of our internal review
in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of
concern with the relevant agencies. We are currently negotiating a potential resolution with the
agencies involved related to these matters. We currently anticipate that any administrative fine
or penalty agreed to as part of a resolution would be within established accruals, and would not
have a material effect on our financial position or results of operations. To the extent a
resolution is not negotiated as anticipated, we cannot predict the timing or effect that any
resulting government actions may have on our financial position or results of operations.
30
Item 6. Exhibits
Reference is hereby made to the Exhibit Index commencing on page 32.
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: November 5, 2010 | By: | /s/ Clay C. Williams | ||
Clay C. Williams | ||||
Executive Vice President and Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer) |
31
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) |
32
10.19
|
Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (13) | |
10.20
|
First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (13) | |
31.1
|
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended. | |
31.2
|
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended. | |
32.1
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101
|
The following materials from our Quarterly Report on Form 10-Q for the period ended September 30, 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.
33