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EXCEL - IDEA: XBRL DOCUMENT - NOV Inc. | Financial_Report.xls |
EX-32.2 - EX-32.2 - NOV Inc. | h84351exv32w2.htm |
EX-31.1 - EX-31.1 - NOV Inc. | h84351exv31w1.htm |
EX-31.2 - EX-31.2 - NOV Inc. | h84351exv31w2.htm |
EX-32.1 - EX-32.1 - NOV Inc. | h84351exv32w1.htm |
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, 2011
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 1-12317
NATIONAL OILWELL VARCO, INC.
(Exact name of registrant as specified in its charter)
Delaware | 76-0475815 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
7909 Parkwood Circle Drive
Houston, Texas
77036-6565
(Address of principal executive offices)
Houston, Texas
77036-6565
(Address of principal executive offices)
(713) 346-7500
(Registrants telephone number, including area code)
(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 (Do not check if a smaller reporting company) | Smaller reporting company o |
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, 2011 the registrant had 423,842,605 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, | |||||||
2011 | 2010 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 3,870 | $ | 3,333 | ||||
Receivables, net |
3,109 | 2,425 | ||||||
Inventories, net |
3,907 | 3,388 | ||||||
Costs in excess of billings |
531 | 815 | ||||||
Deferred income taxes |
282 | 316 | ||||||
Prepaid and other current assets |
339 | 258 | ||||||
Total current assets |
12,038 | 10,535 | ||||||
Property, plant and equipment, net |
1,967 | 1,840 | ||||||
Deferred income taxes |
194 | 341 | ||||||
Goodwill |
5,942 | 5,790 | ||||||
Intangibles, net |
3,995 | 4,103 | ||||||
Investment in unconsolidated affiliate |
371 | 386 | ||||||
Other assets |
37 | 55 | ||||||
Total assets |
$ | 24,544 | $ | 23,050 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 802 | $ | 628 | ||||
Accrued liabilities |
2,154 | 2,105 | ||||||
Billings in excess of costs |
1,117 | 511 | ||||||
Current portion of long-term debt and short-term borrowings |
2 | 373 | ||||||
Accrued income taxes |
399 | 468 | ||||||
Deferred income taxes |
270 | 451 | ||||||
Total current liabilities |
4,744 | 4,536 | ||||||
Long-term debt |
510 | 514 | ||||||
Deferred income taxes |
1,776 | 1,885 | ||||||
Other liabilities |
275 | 253 | ||||||
Total liabilities |
7,305 | 7,188 | ||||||
Commitments and contingencies |
||||||||
Stockholders equity: |
||||||||
Common stock
par value $.01; 423,817,646 and 421,141,751 shares issued and outstanding at September 30, 2011 and December 31, 2010 |
4 | 4 | ||||||
Additional paid-in capital |
8,513 | 8,353 | ||||||
Accumulated other comprehensive income |
37 | 91 | ||||||
Retained earnings |
8,580 | 7,300 | ||||||
Total Company stockholders equity |
17,134 | 15,748 | ||||||
Noncontrolling interests |
105 | 114 | ||||||
Total stockholders equity |
17,239 | 15,862 | ||||||
Total liabilities and stockholders equity |
$ | 24,544 | $ | 23,050 | ||||
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, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenue |
$ | 3,740 | $ | 3,011 | $ | 10,399 | $ | 8,984 | ||||||||
Cost of revenue |
2,576 | 2,066 | 7,177 | 6,149 | ||||||||||||
Gross profit |
1,164 | 945 | 3,222 | 2,835 | ||||||||||||
Selling, general and administrative |
392 | 349 | 1,133 | 1,012 | ||||||||||||
Operating profit |
772 | 596 | 2,089 | 1,823 | ||||||||||||
Interest and financial costs |
(8 | ) | (12 | ) | (31 | ) | (38 | ) | ||||||||
Interest income |
5 | 4 | 13 | 9 | ||||||||||||
Equity income in unconsolidated affiliate |
11 | 8 | 34 | 22 | ||||||||||||
Other income (expense), net |
| (23 | ) | (26 | ) | (42 | ) | |||||||||
Income before income taxes |
780 | 573 | 2,079 | 1,774 | ||||||||||||
Provision for income taxes |
252 | 169 | 667 | 552 | ||||||||||||
Net income |
528 | 404 | 1,412 | 1,222 | ||||||||||||
Net loss attributable to noncontrolling interests |
(4 | ) | | (8 | ) | (5 | ) | |||||||||
Net income attributable to Company |
$ | 532 | $ | 404 | $ | 1,420 | $ | 1,227 | ||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 1.26 | $ | 0.97 | $ | 3.37 | $ | 2.94 | ||||||||
Diluted |
$ | 1.25 | $ | 0.96 | $ | 3.35 | $ | 2.93 | ||||||||
Cash dividends per share |
$ | 0.11 | $ | 0.10 | $ | 0.33 | $ | 0.30 | ||||||||
Weighted average shares outstanding: |
||||||||||||||||
Basic |
422 | 417 | 421 | 417 | ||||||||||||
Diluted |
425 | 419 | 424 | 419 | ||||||||||||
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, | ||||||||
2011 | 2010 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 1,412 | $ | 1,222 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
413 | 378 | ||||||
Deferred income taxes |
(179 | ) | (87 | ) | ||||
Equity income in unconsolidated affiliate |
(34 | ) | (22 | ) | ||||
Dividend from unconsolidated affiliate |
45 | 17 | ||||||
Other, net |
70 | 116 | ||||||
Change in operating assets and liabilities, net of acquisitions: |
||||||||
Receivables |
(646 | ) | (238 | ) | ||||
Inventories |
(530 | ) | (101 | ) | ||||
Costs in excess of billings |
284 | (29 | ) | |||||
Prepaid and other current assets |
(78 | ) | (15 | ) | ||||
Accounts payable |
146 | 1 | ||||||
Billings in excess of costs |
606 | (797 | ) | |||||
Other assets/liabilities, net |
12 | 290 | ||||||
Net cash provided by operating activities |
1,521 | 735 | ||||||
Cash flows from investing activities: |
||||||||
Purchases of property, plant and equipment |
(317 | ) | (140 | ) | ||||
Business acquisitions, net of cash acquired |
(315 | ) | (69 | ) | ||||
Dividend from unconsolidated affiliate |
13 | 16 | ||||||
Other |
43 | 23 | ||||||
Net cash used in investing activities |
(576 | ) | (170 | ) | ||||
Cash flows from financing activities: |
||||||||
Borrowings against lines of credit and other debt |
| 2 | ||||||
Repayments on debt |
(374 | ) | (13 | ) | ||||
Cash dividends paid |
(140 | ) | (126 | ) | ||||
Other |
116 | 14 | ||||||
Net cash used in financing activities |
(398 | ) | (123 | ) | ||||
Effect of exchange rates on cash |
(10 | ) | 6 | |||||
Increase in cash and cash equivalents |
537 | 448 | ||||||
Cash and cash equivalents, beginning of period |
3,333 | 2,622 | ||||||
Cash and cash equivalents, end of period |
$ | 3,870 | $ | 3,070 | ||||
Supplemental disclosures of cash flow information: |
||||||||
Cash payments during the period for: |
||||||||
Interest |
$ | 34 | $ | 38 | ||||
Income taxes |
$ | 805 | $ | 344 |
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 2010 Annual Report on
Form 10-K.
In our opinion, the consolidated financial statements include all adjustments, all of which are of
a normal recurring nature, necessary for a fair presentation of the results for the interim
periods. The results of operations for the three and nine months ended September 30, 2011 are not
necessarily indicative of the results to be expected for the full year.
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, receivables, and
payables approximated fair value because of the relatively short maturity of these instruments.
Cash equivalents include only those investments having a maturity date of three months or less at
the time of purchase. The carrying values of other financial instruments approximate their
respective fair values.
2. Inventories, net
Inventories consist of (in millions):
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
Raw materials and supplies |
$ | 823 | $ | 661 | ||||
Work in process |
833 | 953 | ||||||
Finished goods and purchased products |
2,251 | 1,774 | ||||||
Total |
$ | 3,907 | $ | 3,388 | ||||
5
3. Accrued Liabilities
Accrued liabilities consist of (in millions):
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
Customer prepayments and billings |
$ | 638 | $ | 387 | ||||
Accrued purchase orders |
405 | 597 | ||||||
Compensation |
358 | 403 | ||||||
Warranty |
232 | 215 | ||||||
Taxes (non income) |
89 | 93 | ||||||
Insurance |
70 | 49 | ||||||
Fair value of derivatives |
47 | 22 | ||||||
Interest |
8 | 11 | ||||||
Other |
307 | 328 | ||||||
Total |
$ | 2,154 | $ | 2,105 | ||||
Service and Product Warranties
The Company provides service and warranty policies on certain of its products. The Company accrues
liabilities under service and warranty policies based upon specific claims and a review of
historical warranty and service claim experience in accordance with Accounting Standards
Codification (ASC) Topic 450 Contingencies (ASC Topic 450). Adjustments are made to accruals
as claim data and historical experience change. In addition, the Company incurs discretionary costs
to service its products in connection with product performance issues and accrues for them when
they are encountered.
The changes in the carrying amount of service and product warranties are as follows (in millions):
Balance at December 31, 2010 |
$ | 215 | ||
Net provisions for warranties issued during the year |
44 | |||
Amounts incurred |
(28 | ) | ||
Foreign currency translation and other |
1 | |||
Balance at September 30, 2011 |
$ | 232 | ||
4. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
Costs incurred on uncompleted contracts |
$ | 7,570 | $ | 6,676 | ||||
Estimated earnings |
5,280 | 4,665 | ||||||
12,850 | 11,341 | |||||||
Less: Billings to date |
13,436 | 11,037 | ||||||
$ | (586 | ) | $ | 304 | ||||
Costs and estimated earnings in excess
of billings on uncompleted contracts |
$ | 531 | $ | 815 | ||||
Billings in excess of costs and
estimated earnings on uncompleted
contracts |
(1,117 | ) | (511 | ) | ||||
$ | (586 | ) | $ | 304 | ||||
6
5. Comprehensive Income
The components of comprehensive income are as follows (in millions):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income |
$ | 528 | $ | 404 | $ | 1,412 | $ | 1,222 | ||||||||
Currency translation adjustments |
(117 | ) | 92 | (25 | ) | 16 | ||||||||||
Changes in derivative financial instruments, net of tax |
(71 | ) | 84 | (29 | ) | 3 | ||||||||||
Comprehensive income |
340 | 580 | 1,358 | 1,241 | ||||||||||||
Comprehensive loss attributable to noncontrolling interest |
(4 | ) | | (8 | ) | (5 | ) | |||||||||
Comprehensive income attributable to Company |
$ | 344 | $ | 580 | $ | 1,366 | $ | 1,246 | ||||||||
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, 2011, a majority of these local currencies weakened against the
U.S. dollar resulting in a net decrease to Other Comprehensive Income of $117 million upon the
translation of their financial statements from their local currency to the U.S. dollar. For the
nine months ended September 30, 2011, foreign exchange movements have been insignificant with the
majority of the local currencies strengthening slightly, offset by a slightly weaker Canadian
dollar, resulting in a net decrease to Other Comprehensive Income of $25 million.
The effect of changes in the fair values of derivatives designated as cash flow hedges are
accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which
they are designed to hedge are realized. The movement in Other Comprehensive Income from period to
period will be the result of the combination of changes in fair value for open derivatives and the
outflow of accumulated Other Comprehensive Income related to the fair value of derivatives that
have settled in the current or prior periods. The accumulated effect is a decrease in Other
Comprehensive Income of $71 million (net of tax of $28 million) and $29 million (net of tax of $12
million) for the three and nine months ended September 30, 2011, respectively.
7
6. Business Segments
Operating results by segment are as follows (in millions):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 1,970 | $ | 1,650 | $ | 5,472 | $ | 5,208 | ||||||||
Petroleum Services & Supplies |
1,460 | 1,089 | 4,084 | 3,045 | ||||||||||||
Distribution Services |
480 | 424 | 1,313 | 1,123 | ||||||||||||
Elimination |
(170 | ) | (152 | ) | (470 | ) | (392 | ) | ||||||||
Total Revenue |
$ | 3,740 | $ | 3,011 | $ | 10,399 | $ | 8,984 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology |
$ | 523 | $ | 478 | $ | 1,456 | $ | 1,564 | ||||||||
Petroleum Services & Supplies |
298 | 164 | 777 | 415 | ||||||||||||
Distribution Services |
37 | 24 | 90 | 48 | ||||||||||||
Unallocated expenses and eliminations |
(86 | ) | (70 | ) | (234 | ) | (204 | ) | ||||||||
Total Operating Profit |
$ | 772 | $ | 596 | $ | 2,089 | $ | 1,823 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology |
26.5 | % | 29.0 | % | 26.6 | % | 30.0 | % | ||||||||
Petroleum Services & Supplies |
20.4 | % | 15.1 | % | 19.0 | % | 13.6 | % | ||||||||
Distribution Services |
7.7 | % | 5.7 | % | 6.9 | % | 4.3 | % | ||||||||
Total Operating Profit % |
20.6 | % | 19.8 | % | 20.1 | % | 20.3 | % |
The Company had revenues of 13% and 12% of total revenue from one of its customers for the
three and nine months ended September 30, 2011, respectively, and revenues of 14% and 17% of total
revenue from one of its customers for the three and nine months ended September 30, 2010,
respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general
contractor for its customers, who are drillship owners and drilling contractors. This 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, | |||||||
2011 | 2010 | |||||||
Senior Notes, interest at 6.5% payable semiannually,
principal due on March 15, 2011 |
$ | | $ | 150 | ||||
Senior Notes, interest at 7.25% payable semiannually,
principal due on May 1, 2011 |
| 201 | ||||||
Senior Notes, interest at 5.65% payable semiannually,
principal due on November 15, 2012 |
200 | 200 | ||||||
Senior Notes, interest at 5.5% payable semiannually,
principal due on November 19, 2012 |
150 | 151 | ||||||
Senior Notes, interest at 6.125% payable semiannually,
principal due on August 15, 2015 |
151 | 151 | ||||||
Other |
11 | 34 | ||||||
Total debt |
512 | 887 | ||||||
Less current portion |
2 | 373 | ||||||
Long-term debt |
$ | 510 | $ | 514 | ||||
Senior Notes
On March 15, 2011, the Company repaid $150 million of its 6.5% unsecured Senior Notes using
available cash balances and on May 1, 2011, the Company repaid $200 million of its 7.25% unsecured
Senior Notes using available cash balances. The remaining Senior Notes contain reporting covenants,
and the Company was in compliance at September 30, 2011.
Revolving Credit Facilities
On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit
facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to
finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2
billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility
which was terminated early in February 2009. At September 30, 2011 there were no borrowings
against the remaining credit facility, and there were $731 million in outstanding letters of credit
issued under this facility, resulting in $1,269 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 credit facility contains a
financial covenant regarding maximum debt to capitalization and the Company was in compliance at
September 30, 2011.
The Company also had $1,773 million of additional outstanding letters of credit at September 30,
2011, primarily in Norway, that are under various bilateral committed letter of credit facilities.
Other letters of credit are issued as bid bonds and performance bonds.
9
8. Tax
The effective tax rate for the three and nine months ended September 30, 2011 was 32.3% and 32.1%,
respectively, compared to 29.5% and 31.1% for the same period in 2010. The effective tax rate was
positively impacted in the period by the effect of tax rate reductions on timing differences in
foreign jurisdictions, an increase in the benefit of the manufacturing deduction as a result of
increasing income in the U.S., plus the recognition of reduced tax expense related to prior
periods. This was offset by additional current and prior period taxes on foreign dividends. The impact of these prior
period discrete items is not material to any individual prior 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, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Federal income tax at U.S. federal statutory rate |
$ | 273 | $ | 201 | $ | 728 | $ | 621 | ||||||||
Foreign income tax rate differential |
(29 | ) | (28 | ) | (94 | ) | (86 | ) | ||||||||
State income tax, net of federal benefit |
6 | 3 | 17 | 10 | ||||||||||||
Nondeductible expenses |
9 | 6 | 33 | 30 | ||||||||||||
Tax benefit of manufacturing deduction |
(14 | ) | (8 | ) | (26 | ) | (14 | ) | ||||||||
Foreign dividends, net of foreign tax credits |
33 | 2 | 43 | 9 | ||||||||||||
Tax rate change on temporary differences |
(5 | ) | | (18 | ) | | ||||||||||
Other |
(21 | ) | (7 | ) | (16 | ) | (18 | ) | ||||||||
Provision for income taxes |
$ | 252 | $ | 169 | $ | 667 | $ | 552 | ||||||||
The balance of unrecognized tax benefits at September 30, 2011 was $117 million. The Company
recognized no material changes in the balance of unrecognized tax benefits for the three and nine
months ended September 30, 2011.
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 2007 and outside the U.S. for tax years ending
after 2004.
The Company does not anticipate that its total unrecognized tax benefits will significantly change
due to the settlement of audits or the expiration of statutes of limitation within 12 months of
this reporting date.
To the extent penalties and interest would be assessed on any underpayment of income tax, such
accrued amounts have been classified as a component of income tax expense in the financial
statements.
10
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, 2011, 5,702,740 shares remain available for future grants under the Plan, all of
which are available for grants of stock options, performance-based share awards, restricted stock
awards, phantom shares, stock payments and stock appreciation rights. Total stock-based
compensation for all stock-based compensation arrangements under the Plan was $19 million and $55
million for the three and nine months ended September 30, 2011, respectively, and $17 million and
$50 million for the three and nine months ended September 30, 2010, respectively. The total income
tax benefit recognized in the Consolidated Statements of Income for all stock-based compensation
arrangements under the Plan was $6 million and $17 million for the three and nine months ended
September 30, 2011, respectively, and $5 million and $15 million for the three and nine months
ended September 30, 2010, respectively.
During the nine months ended September 30, 2011, the Company granted 2,277,946 stock options and
374,425 shares of restricted stock and restricted stock units, which includes 131,300
performance-based restricted stock awards. Out of the total number of stock options granted,
2,255,322 were granted February 22, 2011 with an exercise price of $79.80. These options generally
vest over a three-year period from the grant date. The remaining 22,624 options were granted May
19, 2011 to the non-employee members of the board of directors at an exercise price of $67.93.
These options generally vest over a three-year period from the grant date. Out of the total number
of restricted stock and restricted stock units, 234,620 were granted February 22, 2011 and vest on
the third anniversary of the date of grant. On May 19, 2011, 8,505 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 were granted February 22, 2011. The performance-based restricted stock
awards granted will be 100% vested 36 months from the date of grant, subject to the performance
condition of the Companys operating income growth, measured on a percentage basis, from January 1,
2011 through December 31, 2013 exceeding the median operating income level growth of a designated
peer group over the same period.
10. Derivative Financial Instruments
ASC Topic 815, Derivatives and Hedging (ASC Topic 815) requires companies to recognize all of
its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at
fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative
instrument depends on whether it has been designated and qualifies as part of a hedging
relationship and further, on the type of hedging relationship. For those derivative instruments
that are designated and qualify as hedging instruments, a company must designate the hedging
instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a
hedge of a net investment in a foreign operation.
The Company is exposed to certain risks relating to its ongoing business operations. The primary
risks managed by using derivative instruments are foreign currency exchange rate risk and interest
rate risk. Forward contracts against various foreign currencies are entered into to manage the
foreign currency exchange rate risk on forecasted revenue and expenses denominated in currencies
other than the functional currency of the operating unit (cash flow hedge). Other forward exchange
contracts against various foreign currencies are entered into to manage the foreign currency
exchange rate risk associated with certain firm commitments denominated in currencies other than
the functional currency of the operating unit (fair value hedge). In addition, the Company will
enter into non-designated forward contracts against various foreign currencies to manage the
foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts
(non-designated hedge). Interest rate swaps are entered into to manage interest rate risk
associated with the 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, 2011, the Company has determined that its financial assets of $42 million and
liabilities of $55 million (primarily currency related derivatives) are level 2 in the fair value
hierarchy. At September 30, 2011, the net fair value of the Companys foreign currency forward
contracts totaled a liability of $13 million.
11
As of September 30, 2011, the Company did not have any interest rate swaps and its financial
instruments do not contain any credit-risk-related or other contingent features that could cause
accelerated payments when the 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.
The Company had the following outstanding foreign currency forward contracts that were entered into
to hedge nonfunctional currency cash flows from forecasted revenues and costs (in millions):
Currency Denomination | ||||||||
September 30, | December 31, | |||||||
Foreign Currency | 2011 | 2010 | ||||||
British Pound Sterling |
£ | 6 | £ | 4 | ||||
Danish Krone |
DKK | 65 | DKK | 31 | ||||
Euro |
| 304 | | 122 | ||||
Norwegian Krone |
NOK | 5,527 | NOK | 4,983 | ||||
U.S. Dollar |
$ | 389 | $ | 247 | ||||
Japanese Yen |
¥ | 122 | ¥ | - | ||||
Singapore Dollar |
SGD | 3 | SGD | - | ||||
Swedish Krone |
SEK | 2 | SEK | - |
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
The Company had the following outstanding foreign currency forward contracts that were entered into
to hedge nonfunctional currency fair values of firm commitments of revenues and costs (in
millions):
Currency Denomination | ||||||||
September 30, | December 31, | |||||||
Foreign Currency | 2011 | 2010 | ||||||
U.S. Dollar |
$ | | $ | 1 |
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.
The Company had the following outstanding foreign currency forward contracts that hedge the fair
value of nonfunctional currency monetary accounts (in millions):
Currency Denomination | ||||||||
September 30, | December 31, | |||||||
Foreign Currency | 2011 | 2010 | ||||||
British Pound Sterling |
£ | 8 | £ | 8 | ||||
Danish Krone |
DKK | 120 | DKK | 115 | ||||
Euro |
| 97 | | 97 | ||||
Norwegian Krone |
NOK | 1,544 | NOK | 1,442 | ||||
U.S. Dollar |
$ | 561 | $ | 328 | ||||
Swedish Krone |
SEK | 19 | SEK | | ||||
Russian Ruble |
RUB | 683 | RUB | 780 | ||||
Brazilian Real |
BRL | | BRL | | ||||
Japanese Yen |
¥ | 351 | ¥ | | ||||
Singapore Dollar |
SGD | 4 | SGD | |
The Company has the following fair values of its derivative instruments and their balance sheet
classifications (in millions):
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Fair Value | Fair Value | |||||||||||||||||||||||
Balance Sheet | September 30, | December 31, | Balance Sheet | September 30, | December 31, | |||||||||||||||||||
Location | 2011 | 2010 | Location | 2011 | 2010 | |||||||||||||||||||
Derivatives designated as hedging
instruments under ASC Topic 815 |
||||||||||||||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 23 | $ | 28 | Accrued liabilities | $ | 37 | $ | 12 | ||||||||||||||
Foreign exchange contracts |
Other Assets | 5 | 12 | Other Liabilities | 8 | 1 | ||||||||||||||||||
Total derivatives designated as
hedging
instruments under ASC Topic 815 |
$ | 28 | $ | 40 | $ | 45 | $ | 13 | ||||||||||||||||
Derivatives not designated as hedging
instruments under ASC Topic 815 |
||||||||||||||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 14 | $ | 7 | Accrued liabilities | $ | 10 | $ | 10 | ||||||||||||||
Total derivatives not designated as
hedging
instruments under ASC Topic 815 |
$ | 14 | $ | 7 | $ | 10 | $ | 10 | ||||||||||||||||
Total derivatives |
$ | 42 | $ | 47 | $ | 55 | $ | 23 | ||||||||||||||||
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, | ||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||
Revenue | 11 | 6 | ||||||||||||||||||||||||||||||
Foreign exchange contracts |
6 | (14 | ) | Cost of revenue | 38 | (26 | ) | Other income (expense), net | 11 | 5 | ||||||||||||||||||||||
Total |
6 | (14 | ) | 49 | (20 | ) | 11 | 5 | ||||||||||||||||||||||||
Derivatives in ASC Topic 815 | Location of Gain (Loss) | Amount of Gain (Loss) | ASC Topic 815 | Location of Gain (Loss) | Recognized in Income on | |||||||||||||||||||||||
Fair Value | Recognized in Income | Recognized in Income on | Fair Value Hedge | Recognized in Income on | Related Hedged | |||||||||||||||||||||||
Hedging Relationships | on Derivative | Derivative | Relationships | Related Hedged Item | Items | |||||||||||||||||||||||
Nine Months Ended | Nine Months Ended | |||||||||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
Foreign exchange contracts |
Revenue | | (1 | ) | Firm commitments | Revenue | | 1 | ||||||||||||||||||||
Total |
| (1 | ) | | 1 | |||||||||||||||||||||||
Derivatives Not Designated as | Location of Gain (Loss) | Amount of Gain (Loss) | ||||||||||
Hedging Instruments under | Recognized in Income | Recognized in Income on | ||||||||||
ASC Topic 815 | on Derivative | Derivative | ||||||||||
Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2011 | 2010 | |||||||||||
Foreign exchange contracts |
Other income (expense), net | (20 | ) | 8 | ||||||||
Total |
(20 | ) | 8 | |||||||||
(a) | The Company expects that ($18) 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 recognized in income represents $11 million and $5 million related to the ineffective portion of the hedging relationships for the nine months ended September 30, 2011 and 2010, respectively, and $13 million and $8 million related to the amount excluded from the assessment of the hedge effectiveness for the nine months ended September 30, 2011 and 2010, 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, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Numerator: |
||||||||||||||||
Net income attributable to Company |
$ | 532 | $ | 404 | $ | 1,420 | $ | 1,227 | ||||||||
Denominator: |
||||||||||||||||
Basicweighted average common shares outstanding |
422 | 417 | 421 | 417 | ||||||||||||
Dilutive effect of employee stock options and
other unvested stock awards |
3 | 2 | 3 | 2 | ||||||||||||
Diluted outstanding shares |
425 | 419 | 424 | 419 | ||||||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 1.26 | $ | 0.97 | $ | 3.37 | $ | 2.94 | ||||||||
Diluted |
$ | 1.25 | $ | 0.96 | $ | 3.35 | $ | 2.93 | ||||||||
Cash dividends per share |
$ | 0.11 | $ | 0.10 | $ | 0.33 | $ | 0.30 | ||||||||
In addition, the Company had stock options outstanding that were anti-dilutive totaling 2 million
and 3 million shares for the three and nine months ended September 30, 2011, respectively, and 6
million shares for each of the three and nine months ended September 30, 2010, respectively.
12. Cash Dividends
On August 17, 2011 the Companys Board of Directors approved a cash dividend of $0.11 per share.
The cash dividend was paid on September 23, 2011 to each stockholder of record on September 9,
2011. Cash dividends aggregated $47 million and $140 million for the three and nine months ended
September 30, 2011, respectively, and $42 million and $126 million for the three and nine months
ended September 30, 2010, respectively. The declaration and payment of future dividends is at the
discretion of the Companys Board of Directors and will be dependent upon the Companys results of
operations, financial condition, capital requirements and other factors deemed relevant by the
Companys Board of Directors.
13. Subsequent Event
On October 5, 2011, the Company completed its previously announced acquisition of Ameron
International Corporation (Ameron) for approximately $777 million. Under the agreement, Amerons
stockholders received $85.00 per share in cash in return for each of the approximately 9.1 million
shares outstanding.
14. Recently Issued Accounting Standards
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update
(ASU) No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure
Requirements in U.S. GAAP and IFRSs (ASU No. 2011-04), which provides guidance about how fair
value should be applied where it is already required or permitted under U.S. GAAP. The ASU does
not extend the use of fair value or require additional fair value measurements, but rather provides
explanations about how to measure fair value. ASU No. 2011-04 requires prospective application and
will be effective for interim and annual reporting periods beginning after December 15, 2011. The
Company is currently assessing the impact ASU No. 2011-04 will have on its financial statements,
but does not expect a significant impact from adoption of the pronouncement.
In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income (ASU No.
2011-05), which eliminates the option to present components of other comprehensive income as part
of the statement of changes in equity and requires that all nonowner changes in equity be presented
either in a single continuous statement of comprehensive income or in two separate but consecutive
statements. ASU No. 2011-05 requires retrospective application and will be effective for interim
and annual reporting periods beginning after December 15, 2011. The Company is currently assessing
the impact ASU No. 2011-05 will have on its financial statements, but does not expect a significant
impact from adoption of the pronouncement.
15
In September 2011, the FASB issued ASU No. 2011-8 Intangibles-Goodwill and Other (ASU No.
2011-08), which amends its guidance on the testing of goodwill for impairment allowing entities
to perform a qualitative assessment on goodwill impairment to determine whether it is more likely
than not (defined as having a likelihood of more than 50 percent) that the fair value of a
reporting unit is less than its carrying amount as a basis for determining whether it is necessary
to perform the two-step goodwill impairment test. This guidance is effective for goodwill
impairment tests performed in interim and annual periods for fiscal years beginning after December
15, 2011, with early adoption permitted. The Company is currently assessing the impact ASU No.
2011-08 will have on its financial statements, but does not expect a significant impact from
adoption of the pronouncement.
16
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.
Unless indicated otherwise, results of operations data are presented in accordance with accounting
principles generally accepted in the United States (GAAP). In an effort to provide investors with
additional information regarding our results of operations, certain non-GAAP financial measures,
including operating profit excluding other costs, operating profit percentage excluding other costs
and diluted earnings per share excluding other costs, are provided. See Non-GAAP Financial Measures
and Reconciliations in Results of Operations for an explanation of our use of non-GAAP financial
measures and reconciliations to their corresponding measures calculated in accordance with GAAP.
Rig Technology
Our Rig Technology segment designs, manufactures, sells and services complete systems for the
drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line
of highly-engineered equipment that automates complex well construction and management operations,
such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly
systems; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well
workover rigs; wireline winches; wireline trucks; cranes; and turret mooring systems and other
products for Floating Production, Storage and Offloading vessels (FPSOs) and other offshore
vessels and terminals. Demand for Rig Technology products is primarily dependent on capital
spending plans by drilling contractors, oilfield service companies, and oil and gas companies; and
secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts
for the segments large installed base of equipment. We have made strategic acquisitions and other
investments during the past several years in an effort to expand our product offering and our
global manufacturing capabilities, including adding additional operations in the United States,
Canada, Norway, the United Kingdom, Brazil, China, Belarus, India, Turkey, the Netherlands,
Singapore, and South Korea.
Petroleum Services & Supplies
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used
to drill, complete, remediate and workover oil and gas wells and service flowlines and other
oilfield tubular goods. The segment manufactures, rents and sells a variety of products and
equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer
pumps, solids control systems, drilling motors, drilling fluids, drill bits, reamers and other
downhole tools, and mud pump consumables. Demand for these services and supplies is determined
principally by the level of oilfield drilling and workover activity by drilling contractors, major
and independent oil and gas companies, and national oil companies. Oilfield tubular services
include the provision of inspection and internal coating services and equipment for drill pipe,
line pipe, tubing, and casing; and the design, manufacture and sale of coiled tubing pipe and
advanced composite pipe for application in highly corrosive environments. The segment sells its
tubular goods and services to oil and gas companies; drilling contractors; pipe distributors,
processors and manufacturers; and pipeline operators. This segment has benefited from several
strategic acquisitions and other investments completed during the past few years, including
additional operations in the United States, Canada, the United Kingdom, Brazil, China, Kazakhstan,
Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, and the
United Arab Emirates.
Distribution Services
Our Distribution Services segment provides maintenance, repair and operating supplies (MRO) and
spare parts to drill site and production locations worldwide. In addition to its comprehensive
network of field locations supporting land drilling operations throughout North America, the
segment supports major offshore drilling contractors through locations in Mexico, the Middle East,
Europe, Southeast Asia and South America. Distribution Services employs advanced information
technologies to provide complete procurement, inventory management and logistics services to its
customers around the globe. Demand for the segments services is determined primarily by the level
of drilling, servicing, and oil and gas production activities.
17
Critical Accounting Estimates
In our annual report on Form 10-K for the year ended December 31, 2010, we identified our most
critical accounting policies. In preparing the financial statements, we make assumptions, estimates
and judgments that affect the amounts reported. We periodically evaluate our estimates and
judgments that are most critical in nature which are related to revenue recognition under long-term
construction contracts; allowance for doubtful accounts; inventory reserves; impairments of
long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and
other indefinite-lived intangible assets; service and product warranties and income taxes. Our
estimates are based on historical experience and on our future expectations that we believe are
reasonable. The combination of these factors forms the basis for making judgments about the
carrying values of assets and liabilities that are not readily apparent from other sources. Actual
results are likely to differ from our current estimates and those differences may be material.
18
EXECUTIVE SUMMARY
National Oilwell Varco generated $532 million in net income attributable to Company, or $1.25 per
fully diluted share, on $3.74 billion in revenue in its third quarter ended September 30, 2011.
Compared to the second quarter of 2011 revenue increased six percent and net income attributable to
Company increased 11 percent. Compared to the third quarter of 2010 revenue increased 24 percent
and net income attributable to Company increased 32 percent.
The third quarter of 2011 included pre-tax transaction charges of $6 million, the second quarter of
2011 included pre-tax transaction charges of $4 million, and the third quarter of 2010 included
pre-tax transaction charges of $2 million. Excluding transaction charges from all periods, third
quarter 2011 earnings were $1.26 per fully diluted share, compared to $1.14 per fully diluted share
last quarter and $0.97 per fully diluted share a year ago. Operating profit excluding transaction
charges was $778 million or 20.8 percent of sales in the third quarter of 2011, compared to $712
million or 20.3 percent of sales last quarter, and $598 million or 19.9 percent of sales a year
ago.
Revenues and operating profit increased both sequentially and year-over-year for all three of the
Companys segments. The Rig Technology segment received a record level of orders for capital
equipment totaling over $3.9 billion, including the largest order ever in the history of the
Company, during the third quarter of 2011. Demand for offshore rigs and well stimulation equipment
were particularly strong. The Petroleum Services & Supplies segment generated record quarterly
revenues, and pushed operating margins above the 20 percent level, due to rising rig activity
associated with unconventional plays in the U.S., and seasonal increases in activity in Canada.
Distribution Services posted its third highest quarterly sales ever, at very strong operating
margins of 7.7 percent.
Oil & Gas Equipment and Services Market
Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset
write-downs at major financial institutions paralyzed credit markets and sparked a serious global
banking crisis. Major central banks responded vigorously through 2009, but economic growth in many
developed economies continues to be weak. As a result asset and commodity prices, including oil
and gas prices, declined in 2009. After rising steadily for six years to peak at around $140 per
barrel earlier in 2008, oil prices collapsed back to average $43 per barrel (West Texas
Intermediate Crude Prices) during the first quarter of 2009, but recovered to $76 per barrel range
by the end of 2009 and increased to average about $90 per barrel by the third quarter of 2011,
partly due to unrest in the Middle East. North American gas prices declined to $3.17 per mmbtu in
the third quarter of 2009 but recovered to average $4.12 per mmbtu in the third quarter of 2011.
The steadily rising oil and gas prices seen between 2003 and 2008 led to high levels of exploration
and development drilling in many oil and gas basins around the globe by 2008, but activity slowed
sharply in 2009 with lower oil and gas prices and tightening credit availability. However, higher
commodity prices led to a recovery in drilling activity through the past two years.
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 2,013 in late October 2011, and
averaged 1,945 rigs during the third quarter of 2011. Many oil and gas operators reliant on
external financing to fund their drilling programs significantly curtailed their drilling activity
in 2009, but drilling recovered across North America as gas prices firmed above $4 per mmbtu and,
more recently, as operators began to drill unconventional shale plays targeting oil, rather than
gas. Oil drilling has risen to over 50 percent of the total domestic drilling effort.
Most international activity is driven by oil exploration and production by national oil companies,
which has historically been less susceptible to short-term commodity price swings, but the
international rig count has exhibited modest declines nonetheless, falling from its September 2008
peak of 1,108 to 947 in August 2009, but recently climbing back to 1,174 in September 2011.
During 2009 the Company saw its Petroleum Services & Supplies and its Distribution Services margins
affected most acutely by a drilling downturn, through both volume and price declines; nevertheless,
both of these segments saw pricing stabilize and revenues recover since third quarter 2009 lows.
The Companys Rig Technology segment increased revenues and margins through 2009 owing to its high
level of contracted backlog which it executed on very well since the economic downturn. In the
first half of 2010 the segment posted operating margins of more than 30 percent, but saw its
margins decline modestly since then, due to a declining mix of higher margin sales made in the
2007-2008 timeframe, and a rising mix of more recent sales made at lower pricing.
19
The economic decline beginning in late 2008 followed an extended period of high drilling activity
which fueled strong demand for oilfield services between 2003 and 2008. Incremental drilling
activity through the upswing shifted toward harsh environments, employing increasingly
sophisticated technology to find and produce reserves. Higher utilization of drilling rigs tested
the capability 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, 70 percent of the existing
476 jackup rigs are more than 25 years old); 2.) replace older mechanical and DC electric land rigs
with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown
technology; and 3.) build out additional deepwater floating drilling rigs, including
semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit
unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency,
safety, and capability, and that many will effectively replace a portion of the existing fleet.
As a result of 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. The
credit crisis and slowing drilling activity led to lower orders in 2009, causing the backlog to
decline to $4.9 billion by June 30, 2010. Orders have risen sharply since then, lifting the
segments backlog to $10.3 billion as of September 30, 2011. Orders totaled $3.9 billion for the
third quarter of 2011, more than double the revenue out of backlog, and representing a record level
for the Rig Technology segments capital equipment sales. Approximately $1.5 billion of these
orders are scheduled to flow out as revenue during the fourth quarter of 2011; $6.4 billion in
2012, and the balance thereafter. The land rig backlog comprised 15 percent and equipment destined
for offshore operations comprised 85 percent of the total backlog as of September 30, 2011.
Equipment destined for international markets totaled 87 percent of the backlog.
Segment Performance
The Rig Technology segment revenues of $1,970 million in the third quarter of 2011 increased four
percent sequentially and increased 19 percent compared to the third quarter of 2010. Segment
operating profit was $523 million and operating margins were 26.5 percent during the third quarter.
Compared to the second quarter of 2011 incremental operating leverage or flow-through (the
increase in operating profit divided by the increase in revenue) was 12 percent, and compared to
the third quarter of 2010 incremental operating leverage was 14 percent. The reason for the lower
than average incremental leverage was a mix shift away from higher margin offshore projects won a
few years ago, toward lower-priced offshore work, and more land business, which typically carries
lower margins. Many offshore projects were contracted at high prices in 2007 and 2008 and
subsequently manufactured in much lower cost environments in 2009 and 2010. Year-over-year
operating margin declined 250 basis points, and sequentially margins declined 60 basis points, due
to this mix effect. Sequentially, revenue out of backlog improved one percent and aftermarket
spares and services revenues improved 18 percent, helped partly by the Companys acquisition of a
drilling equipment repair business in the Far East during the third quarter. Compared to the third
quarter of 2010 revenue out of backlog grew 22 percent and aftermarket spares and services revenues
improved 31 percent. An order for seven deepwater drillships to be built for Petrobras in Brazil;
orders for seven additional floating rigs and 14 jackup rig packages; and strong demand for well
stimulation, intervention and pressure pumping equipment contributed to the segments record order
level during the third quarter of 2011.
The Petroleum Services & Supplies segment generated total sales of $1,460 million in the third
quarter of 2011, up seven percent from the second quarter of 2011 and up 34 percent from the third
quarter of 2010. Operating profit was $298 million or 20.4 percent of sales for the third
quarter, compared to 18.3 percent in the second quarter of 2011 and 15.1 percent in the third
quarter of 2010. Operating leverage or flow-through was 49 percent from the second quarter of
2011, and 36 percent from the third quarter of 2010 to the third quarter of 2011. High sequential
flowthroughs and margins were due to the impact of the seasonal turnaround out of breakup in
Canada, continued favorable pricing within most product lines within the segment, and improved
profitability and volume within the segments downhole tools product line. Favorable trends were
partly offset by higher startup costs for a number of new locations. Operations in North Africa
and the Middle East continue to face low levels of activity due to continuing unrest in that
region.
20
The Distribution Services segment generated $480 million in revenue during the third quarter of
2011, up 13 percent from both sequential and prior year quarters. Operating profit was $37
million, and operating margin was 7.7 percent of sales, up from both the second quarter of 2011 as
well as the third quarter of 2010. Operating leverage or flow-through was 21 percent sequentially
and 23 percent year-over-year. The segment posted sharply improved results in Canada due to
seasonal improvements, as well as good growth and higher margins in the U.S. due to increasing
drilling activity associated with unconventional shale plays. International operations posted
increasing revenues but margins declined slightly on mix. The segments Mono business posted
higher sales of artificial lift products into international markets during the third quarter.
Outlook
Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw
signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher
drilling activity in North America and slowly improving international drilling activity. Order
levels for new drilling rigs has rebounded sharply, and the Rig Technology segment continues to
experience a high level of interest in new capital equipment. Rig dayrates appear to have
stabilized for certain classes of newer technology rigs, and appear to be trending higher for
deepwater offshore rigs. We expect lower pricing in our backlog to lead to modest declines in Rig
Technology margins over the next few quarters, until recently won offshore rig construction orders
begin to generate revenues at higher margins.
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. Many products are beginning to see higher steel, alloy,
resin and fiberglass costs impact their business, and are attempting to raise prices to offset
rising costs. Continuing tight iron ore supplies to the steel mills could adversely affect margins
as the year unfolds.
The Company believes it is well positioned, and should benefit from its strong balance sheet and
capitalization, access to credit, and a high level of contracted orders which are expected to
continue to generate earnings during the remainder of year. The Company has a long history of
cost-control and downsizing in response to depressed market conditions, and of executing strategic
acquisitions during difficult periods. Such a period may present opportunities to the Company to
effect new organic growth and acquisition initiatives, and we remain hopeful that a downturn will
generate new opportunities.
Still the recovery of the world economy continues to move forward with a great deal of uncertainty
as the world watches the sovereign debt crises in several European countries unfold, market
turbulence and general global economic worries. If such global economic uncertaintanties develop
adversely, world oil and gas prices could be impacted which in turn could negatively impact the
worldwide rig count and the Companys future financial results.
21
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 2011 and 2010, and the second quarter of
2011 include the following:
% | % | |||||||||||||||||||
3Q11 v | 3Q11 v | |||||||||||||||||||
3Q11* | 2Q11* | 3Q10* | 2Q11 | 3Q10 | ||||||||||||||||
Active Drilling Rigs: |
||||||||||||||||||||
U.S. |
1,945 | 1,829 | 1,622 | 6.3 | % | 19.9 | % | |||||||||||||
Canada |
443 | 188 | 361 | 135.6 | % | 22.7 | % | |||||||||||||
International |
1,169 | 1,147 | 1,110 | 1.9 | % | 5.3 | % | |||||||||||||
Worldwide |
3,557 | 3,164 | 3,093 | 12.4 | % | 15.0 | % | |||||||||||||
West Texas Intermediate |
$ | 89.82 | $ | 102.23 | $ | 76.05 | (12.1 | %) | 18.1 | % | ||||||||||
Crude Prices (per barrel) |
||||||||||||||||||||
Natural Gas Prices ($/mmbtu) |
$ | 4.12 | $ | 4.36 | $ | 4.28 | (5.5 | %) | (3.7 | %) |
* | Averages for the quarters indicated. See sources below. |
The following table details the U.S., Canadian, and international rig activity and West Texas
Intermediate Oil prices for the past nine quarters ended September 30, 2011 on a quarterly basis:
Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude and
Natural Gas Prices: Department of Energy, Energy Information
Administration (www.eia.doe.gov).
22
The Worldwide and U.S. quarterly average rig count increased 12% (from 3,164 to 3,557) and 6% (from
1,829 to 1,945), in the third quarter of 2011 compared to the second quarter of 2011. The average
per barrel price of West Texas Intermediate Crude decreased 12% (from $102.23 per barrel to $89.82
per barrel) and natural gas prices decreased 6% (from $4.36 per mmbtu to $4.12 per mmbtu) in the
third quarter of 2011 compared to the second quarter of 2011.
U.S. rig activity at October 21, 2011 was 2,013 rigs compared to the third quarter average of 1,945
rigs, increasing 3%. The price for West Texas Intermediate Crude was at $87.40 per barrel as of
October 21, 2011, decreasing 3% from the third quarter average. The price for natural gas was at
$3.63 per mmbtu as of October 21, 2011, decreasing 12% from the third quarter average.
Results of Operations
Operating results by segment are as follows (in millions):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 1,970 | $ | 1,650 | $ | 5,472 | $ | 5,208 | ||||||||
Petroleum Services & Supplies |
1,460 | 1,089 | 4,084 | 3,045 | ||||||||||||
Distribution Services |
480 | 424 | 1,313 | 1,123 | ||||||||||||
Elimination |
(170 | ) | (152 | ) | (470 | ) | (392 | ) | ||||||||
Total Revenue |
$ | 3,740 | $ | 3,011 | $ | 10,399 | $ | 8,984 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology |
$ | 523 | $ | 478 | $ | 1,456 | $ | 1,564 | ||||||||
Petroleum Services & Supplies |
298 | 164 | 777 | 415 | ||||||||||||
Distribution Services |
37 | 24 | 90 | 48 | ||||||||||||
Unallocated expenses and eliminations |
(86 | ) | (70 | ) | (234 | ) | (204 | ) | ||||||||
Total Operating Profit |
$ | 772 | $ | 596 | $ | 2,089 | $ | 1,823 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology |
26.5 | % | 29.0 | % | 26.6 | % | 30.0 | % | ||||||||
Petroleum Services & Supplies |
20.4 | % | 15.1 | % | 19.0 | % | 13.6 | % | ||||||||
Distribution Services |
7.7 | % | 5.7 | % | 6.9 | % | 4.3 | % | ||||||||
Total Operating Profit % |
20.6 | % | 19.8 | % | 20.1 | % | 20.3 | % |
Rig Technology
Three Months Ended September 30, 2011 and 2010. Rig Technology revenue in the third quarter of
2011 was $1,970 million, an increase of $320 million (19.4%) compared to the same period in 2010.
Backlog rose to $10.3 billion, up 111% from the same period last year. Backlog and non-backlog
revenue increased 22% and 14%, respectively, from the prior year period reflecting increased rig construction activity
associated with offshore rigs and active shale plays in the U.S. as well as increased demand for aftermarket spare
parts and services.
Operating profit from Rig Technology was $523 million for the third quarter ended September 30,
2011, an increase of $45 million (9.4%) over the same period of 2010. Operating profit percentage
decreased to 26.5%, from 29.0% for the same prior
year period primarily due to a decrease in the average margin of revenue out of backlog as
contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won
during the order ramp-up from 2005 to 2008.
Nine Months Ended September 30, 2011 and 2010. Rig Technology revenue for the first nine months of
2011 was $5,472 million, an increase of $264 million (5.1%) compared to the same period in 2010.
Revenue out of backlog remained relatively flat while revenue out of non-backlog increased 20%
primarily due to the increased demand for aftermarket spare parts and services.
23
Operating profit from Rig Technology was $1,456 million for the first nine months of 2011, a
decrease of $108 million (6.9%) over the same period of 2010. Operating profit percentage
decreased to 26.6%, from 30.0% for the same prior year period primarily due to a decrease in the
average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less
favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. This
decrease in margins was partially offset by the increase in demand for aftermarket spare parts and
services.
Petroleum Services & Supplies
Three Months Ended September 30, 2011 and 2010. Revenue from Petroleum Services & Supplies was
$1,460 million for the third quarter of 2011 compared to $1,089 million for the third quarter of
2010, an increase of $371 million (34.1%). The increase was primarily attributable to shale plays
leading to a strong North American market with a 19.9% increase in
U.S. rig activity and a 22.7% increase in Canada rig activity compared to the third
quarter of 2010.
Operating profit from Petroleum Services & Supplies was $298 million for the third quarter ended
September 30, 2011, an increase of $134 million (81.7%) over the same period of 2010. Operating
profit percentage increased to 20.4%, up from 15.1% for the same prior year period primarily due to
favorable pricing as well as increased volume with a strong North American demand fueled by an
increase in rig count.
Nine Months Ended September 30, 2011 and 2010. Revenue from Petroleum Services & Supplies was
$4,084 million for the first nine months of 2011 compared to $3,045 million for the first nine
months of 2010, an increase of $1,039 million (34.1%). The increase was primarily attributable to
shale plays leading to a strong North American market with an 22.7%
increase in U.S. rig activity and a 22.3% increase in Canada rig
activity compared to
the first nine months of 2010.
Operating profit from Petroleum Services & Supplies was $777 million for the nine months ended
September 30, 2011, an increase of $362 million (87.2%) over the same period of 2010. Operating
profit percentage increased to 19.0%, up from 13.6% for the same prior year period primarily due to
favorable pricing as well as increased volume with a strong North American demand fueled by an
increase in rig count. The increase was offset by the write-down, in the first quarter, of Libyan
assets of $15 million, mostly related to accounts receivable affected by sanctions enacted during
the quarter along with the write off of certain inventory and fixed assets in the country. The
Companys Rig Technology and Distribution Services segments incurred $2 million of such asset
write-downs during the first quarter for a total of $17 million in Libyan asset write-downs
incurred by the Company.
Distribution Services
Three Months Ended September 30, 2011 and 2010. Revenue from Distribution Services was $480
million for the third quarter of 2011 compared to $424 million for the third quarter of 2010, an
increase of $56 million (13.2%). This increase was primarily attributable to increased U.S. rig
count activity.
Operating profit from Distribution Services was $37 million for the third quarter ended September
30, 2011, an increase of $13 million (54.2%) over the same period of 2010. Operating profit
percentage increased to 7.7%, up from 5.7% for the same prior year period primarily due to better
pricing related to strong demand fueled by an increase in U.S. rig count activity.
Nine Months Ended September 30, 2011 and 2010. Revenue from Distribution Services was $1,313
million for the first nine months of 2011 compared to $1,123 million for the first nine months of
2010, an increase of $190 million (16.9%). This increase was primarily attributable to increased
U.S. rig count activity.
Operating profit from Distribution Services was $90 million for the first nine months of 2011
compared to $48 million for the same period in 2010, an increase of $42 million (87.5%). Operating
profit percentage increased to 6.9%, up from 4.3% for the same prior year period primarily due to
greater cost efficiencies and better pricing related to strong demand fueled by an increase in U.S.
rig count activity.
Unallocated expenses and eliminations
Unallocated
expenses and eliminations were $86 million and $234 million for the three and nine
months ended September 30, 2011, respectively, compared to $70 million and $204 million, respectively, for
the same periods in 2010. This increase is primarily due to higher legal costs associated with
acquisitions and intersegment eliminations.
24
Interest and financial costs
Interest and financial costs were $8 million and $31 million for the three and nine months ended
September 30, 2011, respectively, compared to $12 million and $38 million, respectively, for the
same periods in 2010. 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, 2011 compared to the same periods
in 2010.
Other income (expense), net
Other income (expense), net were expenses of nil and $26 million for the three and nine months
ended September 30, 2011, respectively, compared to $23 million and $42 million, respectively for
the same periods in 2010. The increase for the three and nine months ended September 30, 2011, was
mainly due to lower foreign exchange losses during 2011 as a result of exchange rate movements,
primarily related to the strengthening of the U.S. dollar.
Provision for income taxes
The effective tax rate for the three and nine months ended September 30, 2011 was 32.3% and 32.1%,
respectively, compared to 29.5% and 31.1% for the same period in 2010. The effective tax rate was
positively impacted in the period by the effect of tax rate reductions on timing differences in
foreign jurisdictions, an increase in the benefit of the manufacturing deduction as a result of
increasing income in the U.S., plus the recognition of reduced tax expense related to prior
periods. This was offset by additional current and prior period taxes on foreign dividends. The impact of these prior period discrete items is not material to any individual prior period.
25
Non-GAAP Financial Measures and Reconciliations
In an effort to provide investors with additional information regarding our results as determined
by GAAP, we disclose various non-GAAP financial measures in our quarterly earnings press releases
and other public disclosures. The primary non-GAAP financial measures we focus on are: (i)
operating profit excluding other costs, (ii) operating profit percentage excluding other costs, and
(iii) diluted earnings per share excluding other costs. Each of these financial measures excludes
the impact of certain other costs and therefore has not been calculated in accordance with GAAP. A
reconciliation of each of these non-GAAP financial measures to its most comparable GAAP financial
measure is included below.
We use these non-GAAP financial measures because we believe it provides useful supplemental
information regarding the Companys on-going economic performance and, therefore, use these
non-GAAP financial measures internally to evaluate and manage the Companys operations. We have
chosen to provide this information to investors to enable them to perform more meaningful
comparisons of operating results and as a means to emphasize the results of on-going operations.
The following tables set forth the reconciliations of these non-GAAP financial measures to their
most comparable GAAP financial measures (in millions, except per share data):
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | June 30, | September 30, | ||||||||||||||||||
2011 | 2010 | 2011 | 2011 | 2010 | ||||||||||||||||
Reconciliation of operating profit: |
||||||||||||||||||||
GAAP operating profit |
$ | 772 | $ | 596 | $ | 708 | $ | 2,089 | $ | 1,823 | ||||||||||
Other costs: |
||||||||||||||||||||
Transaction costs |
6 | 2 | 4 | 12 | 6 | |||||||||||||||
Libya asset write-down |
| | | 17 | | |||||||||||||||
Devaluation costs |
| | | | 11 | |||||||||||||||
Operating profit excluding other costs |
$ | 778 | $ | 598 | $ | 712 | $ | 2,118 | $ | 1,840 | ||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | June 30, | September 30, | ||||||||||||||||||
2011 | 2010 | 2011 | 2011 | 2010 | ||||||||||||||||
Reconciliation of operating profit %: |
||||||||||||||||||||
GAAP operating profit % |
20.6 | % | 19.8 | % | 20.2 | % | 20.1 | % | 20.3 | % | ||||||||||
Other costs % |
0.2 | % | 0.1 | % | 0.1 | % | 0.3 | % | 0.2 | % | ||||||||||
Operating profit % excluding other costs |
20.8 | % | 19.9 | % | 20.3 | % | 20.4 | % | 20.5 | % | ||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | June 30, | September 30, | ||||||||||||||||||
2011 | 2010 | 2011 | 2011 | 2010 | ||||||||||||||||
Reconciliation of diluted earnings per share: |
||||||||||||||||||||
GAAP earnings per share |
$ | 1.25 | $ | 0.96 | $ | 1.13 | $ | 3.35 | $ | 2.93 | ||||||||||
Other costs |
0.01 | 0.01 | 0.01 | 0.06 | 0.11 | |||||||||||||||
Earnings per share excluding other costs |
$ | 1.26 | $ | 0.97 | $ | 1.14 | $ | 3.41 | $ | 3.04 | ||||||||||
26
Liquidity and Capital Resources
Overview
At September 30, 2011, the Company had cash and cash equivalents of $3,870 million, and total debt
of $512 million. At December 31, 2010, cash and cash equivalents were $3,333 million and total debt
was $887 million. A significant portion of the consolidated cash balances are maintained in
accounts in various foreign subsidiaries and, if such amounts were transferred among countries or
repatriated to the U.S., such amounts may be subject to additional tax obligations. Rather than
repatriating this cash, the Company may choose to borrow against its credit facility. The
Companys outstanding debt at September 30, 2011 consisted of $200 million of 5.65% Senior Notes
due 2012, $150 million of 5.5% Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015,
and other debt of $11 million.
There were no borrowings against the Companys unsecured revolving credit facility, and there were
$731 million in outstanding letters of credit issued under the facility, resulting in $1,269
million of funds available under the Companys unsecured revolving credit facility at September 30,
2011.
The Company had $1,773 million of additional outstanding letters of credit at September 30, 2011,
primarily in Norway, that are 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, 2011.
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, | ||||||||
2011 | 2010 | |||||||
Net cash provided by operating activities |
$ | 1,521 | $ | 735 | ||||
Net cash used in investing activities |
(576 | ) | (170 | ) | ||||
Net cash used in financing activities |
(398 | ) | (123 | ) |
Operating Activities
For the first nine months of 2011, cash provided by operating activities was $1,521 million, an
increase of $786 million compared to cash provided by operating activities of $735 million in the
same period of 2010. Before changes in operating assets and liabilities, net of acquisitions, cash
was provided by operations primarily through net income of $1,412 million plus non-cash charges of
$234 million and $45 million of the dividend received from the Companys unconsolidated affiliate
less $34 million in equity income from the Companys unconsolidated affiliate.
Net changes in operating assets and liabilities, net of acquisitions, used $206 million for the
first nine months of 2011 compared to $889 million used in the same period in 2010. Due to an
increase in market activity during the first nine months of 2011 compared to the same period in
2010, revenue and backlog (milestone invoicing) increased which is reflected in increased accounts
receivable coupled with a buildup in inventory, partially offset by a decrease in costs in excess of billings and an increase in billings in excess of costs. Incentive compensation and tax payments contributed
to the reduction in other assets/liabilities, net for the first nine months of 2011 compared to the
same period in 2010.
The Company received $58 million and $33 million in dividends from its unconsolidated affiliate in
2011 and 2010, respectively. The portion included in operating activities in 2011 and 2010 was $45
million and $17 million, respectively. The remaining $13 million and $16 million were included in
investing activities in 2011 and 2010, respectively.
Investing Activities
For the first nine months of 2011, cash used in investing activities was $576 million compared to
cash used in investing activities of $170 million for the same period of 2010. The primary reason
for the increase related to the increase in cash paid for acquisitions to approximately $315
million during the first nine months of 2011 compared to $69 million during the same period of
2010. In addition, capital expenditures increased to approximately $317 million as capital was
spent on several U.S. and international expansion projects during the first nine months of 2011
compared to $140 million used in the same period of 2010.
27
Financing Activities
For the first nine months of 2011, cash used in financing activities was $398 million compared to
cash used in financing activities of $123 million for the same period of 2010. The $275 million
increase in cash used in financing activities for the first nine months of 2011 primarily related
to the repayment of $150 million in Senior Notes that were due late in the first quarter, $200
million in Senior Notes that were due in the second quarter as well as $20 million in other current
borrowings. The Company increased its dividend slightly to $140 million for the first nine months
of 2011 compared to $126 million for the same period of 2010. The increase in cash used was
partially offset by $71 million in proceeds from stock options exercised during the first nine
months of 2011 compared to $8 million in proceeds from stock options exercised during the same
period in 2010. For the first nine months of 2011, the Company used its cash on hand to fund its
acquisitions.
The effect of the change in exchange rates on cash flows was a negative $10 million and a positive
$6 million for the nine months ended September 30, 2011 and 2010, respectively.
We believe that cash on hand, cash generated from operations and amounts available under the credit
facilities and from other sources of debt will be sufficient to fund operations, working capital
needs, capital expenditure requirements, dividends and financing obligations.
We intend to pursue additional acquisition candidates, but the timing, size or success of any
acquisition effort and the related potential capital commitments cannot be predicted. We expect to
fund future cash acquisitions primarily with cash flow from operations and borrowings, including
the unborrowed portion of the credit facility or new debt issuances, but may also issue additional
equity either directly or in connection with acquisitions. There can be no assurance that
additional financing for acquisitions will be available at terms acceptable to us.
Recently Issued Accounting Standards
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update
(ASU) No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure
Requirements in U.S. GAAP and IFRSs ( ASU No. 2011-04), which provides guidance about how fair
value should be applied where it is already required or permitted under U.S. GAAP. The ASU does
not extend the use of fair value or require additional fair value measurements, but rather provides
explanations about how to measure fair value. ASU No. 2011-04 requires prospective application and
will be effective for interim and annual reporting periods beginning after December 15, 2011. The
Company is currently assessing the impact ASU No. 2011-04 will have on its financial statements,
but does not expect a significant impact from adoption of the pronouncement.
In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income (ASU No.
2011-05), which eliminates the option to present components of other comprehensive income as part
of the statement of changes in equity and requires that all nonowner changes in equity be presented
either in a single continuous statement of comprehensive income or in two separate but consecutive
statements. ASU No. 2011-05 requires retrospective application and will be effective for interim
and annual reporting periods beginning after December 15, 2011. The Company is currently assessing
the impact ASU No. 2011-05 will have on its financial statements, but does not expect a significant
impact from adoption of the pronouncement.
In September 2011, the FASB issued ASU No. 2011-8 Intangibles-Goodwill and Other (ASU No.
2011-08), which amends its guidance on the testing of goodwill for impairment allowing entities
to perform a qualitative assessment on goodwill impairment to determine whether it is more likely
than not (defined as having a likelihood of more than 50 percent) that the fair value of a
reporting unit is less than its carrying amount as a basis for determining whether it is necessary
to perform the two-step goodwill impairment test. This guidance is effective for goodwill
impairment tests performed in interim and annual periods for fiscal years beginning after December
15, 2011, with early adoption permitted. The Company is currently assessing the impact ASU No.
2011-08 will have on its financial statements, but does not expect a significant impact from
adoption of the pronouncement.
28
Forward-Looking Statements
Some of the information in this document contains, or has incorporated by reference,
forward-looking statements. Statements that are not historical facts, including statements about
our beliefs and expectations, are forward-looking statements. Forward-looking statements typically
are identified by use of terms such as may, will, expect, anticipate, estimate, and
similar words, although some forward-looking statements are expressed differently. All statements
herein regarding expected merger synergies are forward-looking statements. You should be aware
that our actual results could differ materially from results anticipated in the forward-looking
statements due to a number of factors, including but not limited to changes in oil and gas prices,
customer demand for our products, difficulties encountered in integrating mergers and acquisitions,
and worldwide economic activity. You should also consider carefully the statements under Risk
Factors, as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010,
which address additional factors that could cause our actual results to differ from those set forth
in the forward-looking statements. Given these uncertainties, current or prospective investors are
cautioned not to place undue reliance on any such forward-looking statements. We undertake no
obligation to update any such factors or forward-looking statements to reflect future events or
developments.
29
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to changes in foreign currency exchange rates and interest rates. Additional
information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these
operations are exposed to changes in foreign currency exchange rates, although such fluctuations
generally do not affect income since their functional currency is typically the local currency.
These operations also have net assets and liabilities not denominated in the functional currency,
which exposes us to changes in foreign currency exchange rates that impact income. We recorded a
foreign exchange loss in our income statement of approximately $8 million in the first nine months
of 2011, compared to a $29 million foreign exchange loss in the same period of the prior year. The
gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances
denominated in currencies other than the functional currency and adjustments to our hedged
positions as a result of changes in foreign currency exchange rates. Strengthening of currencies
against the U.S. dollar may create losses in future periods to the extent we maintain net assets
and liabilities not denominated in the functional currency of the countries using the local
currency as their functional currency.
Some of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes
in foreign currency exchange rates impact our earnings to the extent that costs associated with
those U.S. dollar revenues are denominated in the local currency. Similarly some of our revenues
are denominated in foreign currencies, but have associated U.S. dollar costs, which also give rise
to foreign currency exchange rate exposure. In order to mitigate that risk, we may utilize foreign
currency forward contracts to better match the currency of our revenues and associated costs. We do
not use foreign currency forward contracts for trading or speculative purposes.
The following table details the Companys foreign currency exchange risk grouped by functional
currency and their expected maturity periods as of September 30, 2011 (in millions, except contract
rates):
As of September 30, 2011 | December 31, | |||||||||||||||||||
Functional Currency | 2011 | 2012 | 2013 | Total | 2010 | |||||||||||||||
CAD Buy USD/Sell CAD: |
||||||||||||||||||||
Notional amount to buy (in Canadian dollars) |
279 | 1 | | 280 | 267 | |||||||||||||||
Average CAD to USD contract rate |
1.0210 | 0.9879 | | 1.0209 | 1.0072 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
6 | | | 6 | (1 | ) | ||||||||||||||
Sell USD/Buy CAD: |
||||||||||||||||||||
Notional amount to sell (in Canadian dollars) |
98 | 84 | 2 | 184 | 55 | |||||||||||||||
Average CAD to USD contract rate |
0.9853 | 0.9842 | 1.0189 | 0.9853 | 1.0237 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
(5 | ) | (4 | ) | | (9 | ) | 1 | ||||||||||||
EUR Buy USD/Sell EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
5 | 8 | | 13 | 1 | |||||||||||||||
Average USD to EUR contract rate |
1.4150 | 1.4185 | | 1.4164 | 1.3884 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
| | | | | |||||||||||||||
Sell USD/Buy EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
84 | 88 | | 172 | 74 | |||||||||||||||
Average USD to EUR contract rate |
1.3550 | 1.3943 | | 1.3751 | 1.3172 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
| 3 | | 3 | 1 | |||||||||||||||
KRW Sell EUR/Buy KRW: |
||||||||||||||||||||
Notional amount to buy (in South Korean won) |
35,627 | 3,416 | 639 | 39,682 | 273 | |||||||||||||||
Average KRW to EUR contract rate |
1,077.0160 | 1,118.6770 | 1,020.2500 | 1,079.5090 | 1,742.5300 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
(3 | ) | | | (3 | ) | |
30
As of September 30, 2011 | December 31, | |||||||||||||||||||
Functional Currency | 2011 | 2012 | 2013 | Total | 2010 | |||||||||||||||
Sell USD/Buy KRW: |
||||||||||||||||||||
Notional amount to buy (in South Korean won) |
| 123 | 261 | 384 | 67,657 | |||||||||||||||
Average KRW to USD contract rate |
| 923.7000 | 918.8200 | 920.3811 | 1,085.6800 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
| | | | (3 | ) | ||||||||||||||
GBP Buy USD/Sell GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds
Sterling) |
77 | | | 77 | | |||||||||||||||
Average USD to GBP contract rate |
1.5625 | | | 1.5625 | | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
| | | | | |||||||||||||||
Sell USD/Buy GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds
Sterling) |
21 | 16 | | 37 | 49 | |||||||||||||||
Average USD to GBP contract rate |
1.6023 | 1.5979 | | 1.6004 | 1.4952 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
(1 | ) | (1 | ) | | (2 | ) | 2 | ||||||||||||
USD Buy DKK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
13 | 13 | | 26 | 19 | |||||||||||||||
Average DKK to USD contract rate |
5.2992 | 5.3172 | | 5.3086 | 5.5064 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
| | | | | |||||||||||||||
Buy EUR/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
115 | 353 | 27 | 495 | 224 | |||||||||||||||
Average USD to EUR contract rate |
1.4089 | 1.4012 | 1.3971 | 1.4027 | 1.3243 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
(4 | ) | (10 | ) | (1 | ) | (15 | ) | | |||||||||||
Buy GBP/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
19 | | | 19 | 18 | |||||||||||||||
Average USD to GBP contract rate |
1.6134 | | | 1.6134 | 1.5724 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
(1 | ) | | | (1 | ) | | |||||||||||||
Buy NOK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
225 | 607 | 160 | 992 | 810 | |||||||||||||||
Average NOK to USD contract rate |
5.7352 | 5.9349 | 5.8941 | 5.8830 | 6.2022 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
(2 | ) | 9 | (1 | ) | 6 | 32 | |||||||||||||
Sell DKK/Buy USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
9 | | | 9 | 8 | |||||||||||||||
Average DKK to USD contract rate |
5.3043 | | | 5.3043 | 5.5998 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
| | | | | |||||||||||||||
Sell EUR/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
43 | 22 | 1 | 66 | 66 | |||||||||||||||
Average USD to EUR contract rate |
1.3972 | 1.3860 | 1.4019 | 1.3936 | 1.3423 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
1 | | | 1 | 1 | |||||||||||||||
Sell NOK/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
158 | 59 | 1 | 218 | 229 | |||||||||||||||
Average NOK to USD contract rate |
5.5777 | 5.7842 | 5.9030 | 5.6349 | 6.1282 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
6 | | | 6 | (7 | ) | ||||||||||||||
Sell RUB/Buy USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
21 | | | 21 | 25 | |||||||||||||||
Average DKK to USD contract rate |
32.5400 | | | 32.5400 | 31.2030 | |||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
| | | | (1 | ) | ||||||||||||||
Other Currencies |
||||||||||||||||||||
Fair Value at September 30, 2011 in U.S.
dollars |
(1 | ) | (5 | ) | 1 | (5 | ) | (1 | ) | |||||||||||
Total Fair Value at September 30, 2011 in U.S. dollars |
(4 | ) | (8 | ) | (1 | ) | (13 | ) | 24 | |||||||||||
The Company had other financial market risk sensitive instruments denominated in foreign currencies
for transactional exposures totaling $181 million and translation exposures totaling $653 million
as of September 30, 2011 excluding trade receivables and payables, which approximate fair value.
These market risk sensitive instruments consisted of cash balances and overdraft facilities. The
Company estimates that a hypothetical 10% movement of all applicable foreign currency
exchange rates on the transactional exposures financial market risk sensitive instruments could
affect net income by $12 million and the transactional exposures financial market risk sensitive
instruments could affect the future fair value by $65 million.
31
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, 2011 our long term borrowings consisted of $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.
32
PART II OTHER INFORMATION
Item 5. Other Information
Consistent with the recommendation of our stockholders at our 2011 Annual Meeting, the Company will
include an advisory stockholder vote on executive compensation in its proxy materials every year
until the next required advisory vote on the frequency of stockholder votes on executive
compensation, which will occur no later than our annual meeting of stockholders in 2017.
Item 6. Exhibits
Reference is hereby made to the Exhibit Index commencing on page 34.
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 4, 2011 | By: | /s/ Clay C. Williams | ||
Clay C. Williams | ||||
Executive Vice President and Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer) |
33
INDEX TO EXHIBITS
(a) Exhibits
2.1
|
Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 between National-Oilwell, Inc. and Varco International, Inc. (4) | |
2.2
|
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (8) | |
3.1
|
Fifth Amended and Restated Certificate of Incorporation of National Oilwell Varco, Inc. (Exhibit 3.1) (1) | |
3.2
|
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (9) | |
10.1
|
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2) | |
10.2
|
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, 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) |
34
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, 2011 formatted in eXtensible Business Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (14) |
* | Compensatory plan or arrangement for management or others. |
(1)
|
Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 5, 2011. | |
(2)
|
Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002. | |
(3)
|
Filed as an Exhibit to Varco International, Inc.s Quarterly Report on Form 10-Q filed on May 6, 2004. | |
(4)
|
Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004. | |
(5)
|
Filed as 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 August 17, 2011. | |
(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.
35