NOV Inc. - Quarter Report: 2009 September (Form 10-Q)
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 1-12317
NATIONAL OILWELL VARCO, INC.
(Exact name of registrant as specified in its charter)
Delaware | 76-0475815 | |
(State or other jurisdiction | (I.R.S. Employer | |
of incorporation or organization) | Identification No.) |
7909 Parkwood Circle Drive
Houston, Texas
77036-6565
Houston, Texas
77036-6565
(Address of principal executive offices)
(713) 346-7500
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such
files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
As of
November 2, 2009 the registrant had 418,336,718 shares of common stock, par value $.01 per
share, outstanding.
TABLE OF CONTENTS
Table of Contents
PART I FINANCIAL INFORMATION
Item 1. | Financial Statements |
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 3,192 | $ | 1,543 | ||||
Receivables, net |
2,204 | 3,136 | ||||||
Inventories, net |
3,767 | 3,806 | ||||||
Costs in excess of billings |
612 | 618 | ||||||
Deferred income taxes |
227 | 271 | ||||||
Prepaid and other current assets |
405 | 283 | ||||||
Total current assets |
10,407 | 9,657 | ||||||
Property, plant and equipment, net |
1,753 | 1,677 | ||||||
Deferred income taxes |
189 | 126 | ||||||
Goodwill |
5,405 | 5,225 | ||||||
Intangibles, net |
4,103 | 4,300 | ||||||
Investment in unconsolidated affiliate |
389 | 421 | ||||||
Other assets |
116 | 73 | ||||||
Total assets |
$ | 22,362 | $ | 21,479 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 510 | $ | 852 | ||||
Accrued liabilities |
2,454 | 2,376 | ||||||
Billings in excess of costs |
1,615 | 2,161 | ||||||
Current portion of long-term debt and short-term borrowings |
9 | 4 | ||||||
Accrued income taxes |
401 | 230 | ||||||
Total current liabilities |
4,989 | 5,623 | ||||||
Long-term debt |
875 | 870 | ||||||
Deferred income taxes |
2,098 | 2,134 | ||||||
Other liabilities |
121 | 128 | ||||||
Total liabilities |
8,083 | 8,755 | ||||||
Commitments and contingencies |
||||||||
Stockholders equity: |
||||||||
Common stock
par value $.01; 418,281,455 and 417,350,924 shares issued and outstanding at September 30, 2009 and December 31, 2008 |
4 | 4 | ||||||
Additional paid-in capital |
8,203 | 7,989 | ||||||
Accumulated other comprehensive income (loss) |
92 | (161 | ) | |||||
Retained earnings |
5,871 | 4,796 | ||||||
Total Company stockholders equity |
14,170 | 12,628 | ||||||
Noncontrolling interests |
109 | 96 | ||||||
Total stockholders equity |
14,279 | 12,724 | ||||||
Total liabilities and stockholders equity |
$ | 22,362 | $ | 21,479 | ||||
See notes to unaudited consolidated financial statements.
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NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(In millions, except per share data)
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(In millions, except per share data)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenue |
$ | 3,087 | $ | 3,611 | $ | 9,578 | $ | 9,621 | ||||||||
Cost of revenue |
2,196 | 2,511 | 6,773 | 6,743 | ||||||||||||
Gross profit |
891 | 1,100 | 2,805 | 2,878 | ||||||||||||
Selling, general and administrative |
279 | 310 | 932 | 812 | ||||||||||||
Intangible asset impairment |
| | 147 | | ||||||||||||
Transaction and restructuring costs |
11 | | 19 | 16 | ||||||||||||
Operating profit |
601 | 790 | 1,707 | 2,050 | ||||||||||||
Interest and financial costs |
(14 | ) | (19 | ) | (40 | ) | (53 | ) | ||||||||
Interest income |
4 | 11 | 8 | 37 | ||||||||||||
Equity income in unconsolidated affiliate |
1 | 20 | 45 | 37 | ||||||||||||
Other income (expense), net |
(13 | ) | 15 | (87 | ) | 14 | ||||||||||
Income before income taxes |
579 | 817 | 1,633 | 2,085 | ||||||||||||
Provision for income taxes |
192 | 264 | 551 | 707 | ||||||||||||
Net income |
387 | 553 | 1,082 | 1,378 | ||||||||||||
Net income attributable to noncontrolling interests |
2 | 5 | 7 | 11 | ||||||||||||
Net income attributable to Company |
$ | 385 | $ | 548 | $ | 1,075 | $ | 1,367 | ||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 0.93 | $ | 1.32 | $ | 2.58 | $ | 3.49 | ||||||||
Diluted |
$ | 0.92 | $ | 1.31 | $ | 2.58 | $ | 3.48 | ||||||||
Weighted average shares outstanding: |
||||||||||||||||
Basic |
416 | 416 | 416 | 391 | ||||||||||||
Diluted |
418 | 418 | 417 | 393 | ||||||||||||
See notes to unaudited consolidated financial statements.
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NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
Nine Months Ended | ||||||||
September 30, | ||||||||
2009 | 2008 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 1,082 | $ | 1,378 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
364 | 284 | ||||||
Excess tax benefit from exercise of stock options |
| (37 | ) | |||||
Equity income in unconsolidated affiliate |
(45 | ) | (37 | ) | ||||
Dividend from unconsolidated affiliate |
86 | | ||||||
Intangible asset impairment |
147 | | ||||||
Other |
(53 | ) | 36 | |||||
Change in operating assets and liabilities, net of acquisitions: |
||||||||
Receivables |
979 | (596 | ) | |||||
Inventories |
103 | (450 | ) | |||||
Costs in excess of billings |
7 | (10 | ) | |||||
Prepaid and other current assets |
(122 | ) | 69 | |||||
Accounts payable |
(384 | ) | 201 | |||||
Billings in excess of costs |
(545 | ) | 749 | |||||
Other assets/liabilities, net |
350 | 119 | ||||||
Net cash provided by operating activities |
1,969 | 1,706 | ||||||
Cash flows from investing activities: |
||||||||
Purchases of property, plant and equipment |
(186 | ) | (264 | ) | ||||
Business acquisitions, net of cash acquired |
(392 | ) | (2,988 | ) | ||||
Business divestitures, net of cash disposed |
251 | 801 | ||||||
Dividend from unconsolidated affiliate |
8 | 113 | ||||||
Other, net |
| (1 | ) | |||||
Net cash used in investing activities |
(319 | ) | (2,339 | ) | ||||
Cash flows from financing activities: |
||||||||
Borrowings against lines of credit and other debt |
7 | 2,728 | ||||||
Payments against lines of credit and other debt |
(35 | ) | (2,281 | ) | ||||
Proceeds from exercise of stock options |
3 | 84 | ||||||
Excess tax benefit from exercise of stock options |
| 37 | ||||||
Net cash provided by (used in) financing activities |
(25 | ) | 568 | |||||
Effect of exchange rates on cash |
24 | (12 | ) | |||||
Increase (decrease) in cash equivalents |
1,649 | (77 | ) | |||||
Cash and cash equivalents, beginning of period |
1,543 | 1,842 | ||||||
Cash and cash equivalents, end of period |
$ | 3,192 | $ | 1,765 | ||||
Supplemental disclosures of cash flow information: |
||||||||
Cash payments during the period for: |
||||||||
Interest |
$ | 37 | $ | 52 | ||||
Income taxes |
$ | 603 | $ | 921 |
See notes to unaudited consolidated financial statements.
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NATIONAL OILWELL VARCO, INC.
Notes to Consolidated Financial Statements (Unaudited)
Notes to Consolidated Financial Statements (Unaudited)
1. Basis of Presentation
The preparation of financial statements in conformity with generally accepted accounting principles
(GAAP) in the United States requires management to make estimates and assumptions that affect
reported and contingent amounts of assets and liabilities as of the date of the financial
statements and reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (the
Company) present information in accordance with GAAP in the United States for interim financial
information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not
include all information or footnotes required by GAAP in the United States for complete
consolidated financial statements and should be read in conjunction with our 2008 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, 2009 are not
necessarily indicative of the results to be expected for the full year. The Company has evaluated
subsequent events for potential recognition or disclosure in the consolidated financial statements
included through November 5, 2009.
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. Grant Prideco Merger and Other Acquisitions
The Grant Prideco merger was accounted for as a purchase business combination. Assets acquired and
liabilities assumed were recorded at their fair values as of April 21, 2008. The total purchase
price is $7,199 million, including Grant Prideco stock options assumed and acquisition related
transaction costs and is comprised of (in millions):
Consideration given to acquire the outstanding common stock of Grant
Prideco: |
||||
Shares issued totaled approximately 56.9 million shares at $72.74 per share |
$ | 4,135 | ||
Cash paid at $23.20 per share |
2,932 | |||
Grant Prideco stock options assumed |
55 | |||
Merger related transaction costs |
77 | |||
Total purchase price |
$ | 7,199 | ||
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Purchase Price Allocation
The following table, set forth below, displays the total purchase price allocated to Grant
Pridecos net tangible and identifiable intangible assets based on their fair values as of
April 21, 2008 (in millions):
Cash and cash equivalents |
$ | 171 | ||
Receivables |
420 | |||
Assets held for sale, net |
784 | |||
Inventories |
611 | |||
Prepaid and other current assets |
210 | |||
Property, plant and equipment |
392 | |||
Goodwill |
2,772 | |||
Intangibles |
3,696 | |||
Investment in unconsolidated affiliate |
512 | |||
Other assets |
98 | |||
Accounts payable and accrued liabilities |
(316 | ) | ||
Accrued income taxes |
(624 | ) | ||
Long-term debt |
(176 | ) | ||
Deferred income taxes |
(1,305 | ) | ||
Minority interest |
(25 | ) | ||
Other liabilities |
(21 | ) | ||
Total purchase price |
$ | 7,199 | ||
Unaudited Pro Forma Financial Information
The unaudited financial information in the table below summarizes the combined results of
operations of National Oilwell Varco and Grant Prideco, on a pro forma basis, as though the
companies had been combined as of the beginning of 2008. The pro forma financial information is
presented for informational purposes only and may not be indicative of the results of operations
that would have been achieved if the merger had taken place at the beginning of 2008. The pro forma
financial information for the three and nine months ended September 30, 2008 includes the business
combination accounting effect on historical Grant Prideco revenues, adjustments to depreciation on
acquired property, amortization charges from acquired intangible assets, financing costs on new
debt in connection with the merger and related tax effects. (in millions, except per share data):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Total revenues |
$ | 3,087 | $ | 3,611 | $ | 9,578 | $ | 10,225 | ||||||||
Net income attributable to Company |
$ | 385 | $ | 568 | $ | 1,075 | $ | 1,495 | ||||||||
Basic net income attributable to Company per share |
$ | 0.93 | $ | 1.37 | $ | 2.58 | $ | 3.61 | ||||||||
Diluted net income attributable to Company per
share |
$ | 0.92 | $ | 1.36 | $ | 2.58 | $ | 3.59 | ||||||||
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Other Acquisitions
In the nine months ended September 30, 2009, the Company completed five acquisitions for an
aggregate purchase price of $392 million, net of cash acquired. These acquisitions included:
| The shares of ASEP Group Holding B.V., a Netherlands-based manufacturer of well service equipment. | ||
| The shares of ANS (1001) Ltd. (Anson), a U.K.-based manufacturer of pumps and fluid expendibles. | ||
| The business and assets of Spirit Drilling Fluids Ltd., a U.S.-based company that provides drilling fluids and related well-site services to exploration and production companies. | ||
| The business and assets of Spirit Minerals L.P., a U.S.-based company that mines, processes and distributes barite to the oil and gas drilling fluid industry. |
From the dates of acquisition, the results of operations from ASEP are included in the Rig
Technology segment and the results of operations from Anson, Spirit Drilling Fluids, and Spirit
Minerals are included in the Petroleum Services & Supplies segment. The impact of these
acquisitions was not material to the consolidated financial statements.
3. IntelliServ Joint Venture
In September 2009, the Company sold 45 percent of certain of its IntelliServ operations and created
the IntelliServ Joint Venture (IntelliServ).
IntelliServ provides drilling technology that enables downhole drilling conditions to be measured,
evaluated and monitored.
4. Asset Impairment
Generally accepted accounting principles require the Company to test goodwill and other
indefinite-lived intangible assets for impairment at least annually or more frequently whenever
events or circumstances occur indicating that such assets might be impaired.
During the second quarter of 2009, the worldwide average rig count was 2,009 rigs, down 41% from
the fourth quarter 2008 average of 3,395 and down 25% from the first quarter 2009 average of 2,681.
The second quarter 2009 average rig count represented the lowest quarterly average in the past six
years. In addition, the Companys updated forecast was behind the Companys previous forecast
completed at the beginning of 2009. While operating profit for the first quarter of 2009 was in
line with the Companys first quarter 2009 operating profit forecast, the Companys consolidated
operating profit for the second quarter of 2009 was below its second quarter 2009 forecast. As a
result of the substantial decline in the worldwide rig count, and the decline in actual/forecasted
results compared to the original 2009 forecast, the Company concluded that events or circumstances
had occurred indicating that goodwill and other indefinite-lived intangible assets might be
impaired as described under SFAS 142, which was primarily codified into ASC Topic 350, Intangibles
Goodwill and Other (ASC Topic 350).
Therefore, the Company performed its interim impairment test of goodwill for all its reporting
units at the end of the second quarter of 2009. The implied fair value of goodwill is determined by
deducting the fair value of a reporting units identifiable assets and liabilities from the fair
value of that reporting unit as a whole. Fair value of the reporting units is determined in
accordance with SFAS 157, which was primarily codified into ASC Topic 820, Fair Value Measurements
and Disclosures (ASC Topic 820), using significant unobservable inputs, or level 3 in the fair
value hierarchy. These inputs are based on internal management estimates, forecasts and judgments,
using a combination of three methods: discounted cash flow, comparable companies, and
representative transactions. While the Company primarily uses the discounted cash flow method to
assess fair value, the Company uses the comparable companies and representative transaction methods
to validate the discounted cash flow analysis and further support managements expectations, where
possible.
The discounted cash flow is based on managements short-term and long-term forecast of operating
performance for each reporting unit. The two main assumptions used in measuring goodwill
impairment, which bear the risk of change and could impact the Companys goodwill impairment
analysis, include the cash flow from operations from each of the Companys individual business
units and the weighted average cost of capital. The starting point for each of the reporting units
cash flow
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from operations is the detailed annual plan or updated forecast. The detailed planning
and forecasting process takes into consideration a multitude of factors including worldwide rig
activity, inflationary forces, pricing strategies, customer analysis, operational issues,
competitor analysis, capital spending requirements, working capital needs, customer needs to
replace aging equipment, increased complexity of drilling, new technology, and existing backlog
among other items which impact the individual reporting unit projections. Cash flows beyond the
specific operating plans were estimated using a terminal value calculation, which incorporated
historical and forecasted financial cyclical trends for each reporting unit and considered
long-term earnings growth rates. The financial and credit market volatility directly impacts our
fair value measurement through our weighted average cost of capital that we use to determine our
discount rate. During times of volatility, significant judgment must be applied to determine
whether credit changes are a short-term or long-term trend.
Projections for the remainder of 2009 also reflected declines compared to the original 2009 annual
forecast. The Company updated its 2009 operating forecast, long-term forecast, and discounted cash
flows based on this information. The goodwill impairment analysis that we performed during the
second quarter of 2009 did not result in goodwill impairment as of June 30, 2009.
Other indefinite-lived intangible assets, representing trade names management intends to use
indefinitely, were valued using significant unobservable inputs (level 3) and are tested for
impairment using the Relief from Royalty Method, a form of the Income Approach. An impairment is
measured and recognized based on the amount the book value of the indefinite-lived intangible
assets exceeds its estimated fair value as of the date of the impairment test. Included in the
impairment test are assumptions, for each trade name, regarding the related revenue streams
attributable to the trade names which are determined consistent with the forecasting process
described above, the royalty rate, and the discount rate applied. Based on the Companys
indefinite-lived intangible asset impairment analysis performed during the second quarter of 2009,
the Company incurred an impairment charge of $147 million in the Petroleum Services & Supplies
segment related to a partial impairment of the Companys Grant Prideco trade name. The impairment
charge was primarily the result of the substantial decline in worldwide rig counts through June
2009, declines in current forecasts in rig activity for the remainder of 2009, 2010, and 2011
compared to rig count forecast at the beginning of 2009, and a current decline in the revenue
forecast for the drill pipe business unit for the remainder of 2009, 2010, and 2011.
5. Inventories, net
Inventories consist of (in millions):
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Raw materials and supplies |
$ | 762 | $ | 739 | ||||
Work in process |
1,646 | 1,326 | ||||||
Finished goods and purchased products |
1,359 | 1,741 | ||||||
Total |
$ | 3,767 | $ | 3,806 | ||||
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6. Accrued Liabilities
Accrued liabilities consist of (in millions):
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Compensation |
$ | 225 | $ | 258 | ||||
Customer prepayments and billings |
455 | 912 | ||||||
Warranty |
185 | 114 | ||||||
Interest |
16 | 11 | ||||||
Taxes (non income) |
66 | 76 | ||||||
Insurance |
59 | 50 | ||||||
Accrued purchase orders |
1,166 | 688 | ||||||
Fair value of derivatives |
81 | 59 | ||||||
Other |
201 | 208 | ||||||
Total |
$ | 2,454 | $ | 2,376 | ||||
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 SFAS 5, which was primarily
codified into 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, December 31, 2008 |
$ | 114 | ||
Net provisions for warranties issued during the year |
86 | |||
Amounts incurred |
(35 | ) | ||
Foreign currency translation and other |
20 | |||
Balance, September 30, 2009 |
$ | 185 | ||
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7. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Costs incurred on uncompleted contracts |
$ | 6,372 | $ | 4,776 | ||||
Estimated earnings |
3,453 | 2,277 | ||||||
9,825 | 7,053 | |||||||
Less: Billings to date |
10,828 | 8,596 | ||||||
$ | (1,003 | ) | $ | (1,543 | ) | |||
Costs and estimated earnings in excess of billings on
uncompleted contracts |
$ | 612 | $ | 618 | ||||
Billings in excess of costs and estimated earnings on
uncompleted contracts |
(1,615 | ) | (2,161 | ) | ||||
$ | (1,003 | ) | $ | (1,543 | ) | |||
8. Comprehensive Income
The components of comprehensive income are as follows (in millions):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Net income |
$ | 387 | $ | 553 | $ | 1,082 | $ | 1,378 | ||||||||
Currency translation adjustments, net of tax |
22 | (71 | ) | 79 | (33 | ) | ||||||||||
Changes in derivative financial instruments, net
of tax |
69 | (86 | ) | 174 | (65 | ) | ||||||||||
Changes in defined benefit plans, net of tax |
1 | | | | ||||||||||||
Comprehensive income |
479 | 396 | 1,335 | 1,280 | ||||||||||||
Comprehensive income attributable to
noncontrolling interest |
2 | 5 | 7 | 11 | ||||||||||||
Comprehensive income attributable to Company |
$ | 477 | $ | 391 | $ | 1,328 | $ | 1,269 | ||||||||
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 SFAS 52, Foreign Currency Translation, which was primarily codified
into ASC Topic 830 Foreign Currency Matters (ASC Topic 830). For the three months ended
September 30, 2009, a majority of these local currencies strengthened against the U.S. dollar
resulting in a net increase to Other Comprehensive Income of $22 million (net of tax of $12
million) upon the translation of their financial statements from their local currency to the U.S.
dollar.
The effect
of changes in the fair values of derivatives designated as Cash Flow hedges are
accumulated in Other Comprehensive Income, net of tax, until the underlying transactions to which
they are designed to hedge are realized. The movement in Other Comprehensive Income from period to
period will be the result of the combination of changes in fair value for open derivatives and
the outflow of accumulated Other Comprehensive Income related to the
fair value of derivatives that have settled in the current or prior
periods. The
accumulated effects of these scenarios have caused an increase in Other Comprehensive Income of $69
million (net of tax of $28 million) for the three months ended September 30, 2009.
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9. Business Segments
Operating results by segment are as follows (in millions). The 2008 actual results include Grant
Prideco operations from the acquisition date of April 21, 2008:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 2,000 | $ | 1,926 | $ | 6,116 | $ | 5,440 | ||||||||
Petroleum Services & Supplies |
882 | 1,310 | 2,809 | 3,264 | ||||||||||||
Distribution Services |
306 | 498 | 1,019 | 1,289 | ||||||||||||
Elimination |
(101 | ) | (123 | ) | (366 | ) | (372 | ) | ||||||||
Total Revenue |
$ | 3,087 | $ | 3,611 | $ | 9,578 | $ | 9,621 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology (a) |
$ | 577 | $ | 501 | $ | 1,717 | $ | 1,413 | ||||||||
Petroleum Services & Supplies (b) (c) |
82 | 302 | 195 | 718 | ||||||||||||
Distribution Services |
7 | 43 | 42 | 87 | ||||||||||||
Unallocated expenses and eliminations (d) |
(54 | ) | (56 | ) | (228 | ) | (152 | ) | ||||||||
Transaction and restructuring costs |
(11 | ) | | (19 | ) | (16 | ) | |||||||||
Total Operating Profit |
$ | 601 | $ | 790 | $ | 1,707 | $ | 2,050 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology (a) |
28.9 | % | 26.0 | % | 28.1 | % | 26.0 | % | ||||||||
Petroleum Services & Supplies (b) (c) |
9.3 | % | 23.0 | % | 6.9 | % | 22.0 | % | ||||||||
Distribution Services |
2.3 | % | 8.8 | % | 4.1 | % | 6.8 | % | ||||||||
Total Operating Profit % |
19.5 | % | 21.9 | % | 17.8 | % | 21.3 | % |
(a) | Under purchase accounting related to 2009 acquisitions, a fair value step up adjustment of $4 million was made to inventory and is being charged to Cost of revenue as the applicable inventory is sold. Cost of revenue includes $2 million and $4 million of these inventory charges for the three and nine months ended September 30, 2009, respectively. | |
(b) | The Company recorded a $147 million impairment charge to other indefinite-lived intangible assets during the nine months ended September 30, 2009. | |
Under purchase accounting related to 2009 acquisitions, a fair value step up adjustment of $4 million was made to inventory and is being charged to Cost of revenue as the applicable inventory is sold. Cost of revenue includes $4 million of these inventory charges for both the three and nine months ended September 30, 2009. | ||
(c) | Under purchase accounting related to the 2008 Grant Prideco acquisition, a fair value step up adjustment of $89 million was made to inventory and is being charged to Cost of revenue as the applicable inventory is sold. Cost of revenue includes $28 million and $74 million of these inventory charges for the three and nine months ended September 30, 2008. | |
(d) | Included in the nine months ended September 30, 2009 is a $46 million charge, recorded in the second quarter of 2009, related to its Voluntary Early Retirement Program. |
The Company had revenues of 16.7% of total revenue from one of its customers for the nine months
ended September 30, 2009. This customer is a shipyard acting as a general contractor for its
customers, who are drillship owners and drilling contractors. This shipyards customers have
specified that the Companys drilling equipment be installed on their drillships and have required
the shipyard to issue contracts to the Company.
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10. Debt
Debt consists of (in millions):
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Senior Notes, interest at 6.5% payable semiannually,
principal due on March 15, 2011 |
$ | 150 | $ | 150 | ||||
Senior Notes, interest at 7.25% payable semiannually,
principal due on May 1, 2011 |
206 | 208 | ||||||
Senior Notes, interest at 5.65% payable semiannually,
principal due on November 15, 2012 |
200 | 200 | ||||||
Senior Notes, interest at 5.5% payable semiannually,
principal due on November 19, 2012 |
151 | 151 | ||||||
Senior Notes, interest at 6.125% payable semiannually,
principal due on August 15, 2015 |
151 | 151 | ||||||
Other |
26 | 14 | ||||||
Total debt |
884 | 874 | ||||||
Less current portion |
9 | 4 | ||||||
Long-term debt |
$ | 875 | $ | 870 | ||||
Senior Notes
In connection with the merger of Grant Prideco, the Company completed an exchange offer relative to
the $175 million of 6.125% Senior Notes due 2015 previously issued by Grant Prideco. On April 21,
2008, $151 million of Grant Prideco Senior Notes were exchanged for National Oilwell Varco Senior
Notes. The National Oilwell Varco Senior Notes have the same interest rate, interest payment
dates, redemption terms and maturity as the Grant Prideco Senior Notes. In November 2008, the
Company repurchased $23 million of the unexchanged Grant Prideco Senior Notes.
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.
At September 30, 2009, there were no borrowings against these facilities, and there were $589
million in outstanding letters of credit issued under these facilities, resulting in $1,411 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. In early February 2009, we terminated early the $1 billion, 364-day revolving credit
facility, which matured April 20, 2009.
The Company also had $2,234 million of additional outstanding letters of credit at September 30,
2009, primarily in Norway, that are essentially under various bilateral committed letter of credit
facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior
Notes contain reporting covenants and the credit facility contains a financial covenant regarding
maximum debt to capitalization. We were in compliance with all covenants at September 30, 2009.
Other
Other debt includes approximately $4 million in promissory notes due to former owners of businesses
acquired who remain employed by the Company.
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11. Tax
The effective tax rate for the three and nine months ended September 30, 2009 was 33.2% and 33.7%,
respectively, compared to 32.3% and 33.9% for the same periods in 2008. The nine months 2009 tax
rate includes $21 million of additional tax provision recognized in the second quarter 2009 on
prior year income in Norway. These additional taxes resulted from foreign currency gains on
dollar-denominated accounts that were realized for Norwegian tax purposes.
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, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Federal income tax at U.S. federal
statutory rate |
$ | 203 | $ | 286 | $ | 572 | $ | 730 | ||||||||
Foreign income tax rate differential |
(23 | ) | (29 | ) | (81 | ) | (72 | ) | ||||||||
State income tax, net of federal benefit |
4 | 9 | 12 | 26 | ||||||||||||
Foreign dividends, net of foreign tax
credits |
3 | (1 | ) | 10 | 33 | |||||||||||
Benefit of U.S. Manufacturing Deduction |
(6 | ) | (7 | ) | (13 | ) | (13 | ) | ||||||||
Prior year tax on revaluation gains in
Norway |
| | 21 | | ||||||||||||
Other |
11 | 6 | 30 | 3 | ||||||||||||
Provision for income taxes |
$ | 192 | $ | 264 | $ | 551 | $ | 707 | ||||||||
The Company accounts for uncertainty in income taxes in accordance with Financial Accounting
Standards Board (FASB) Interpretation No. 48, Accounting for Uncertainty in Income Taxes An
Interpretation of FASB No. 109 (FIN 48) , which was primarily codified into ASC Topic 740,
Income Taxes. (ASC Topic 740) FIN 48/ASC Topic 740 clarifies the accounting for uncertainty in
income taxes recognized in an entitys financial statements in accordance with FASB Statement No.
109, Accounting for Income Taxes, which was primarily codified into ASC Topic 740, and prescribes
a recognition threshold and measurement attributes for financial statement disclosure of tax
positions taken or expected to be taken on a return. Under FIN 48/ASC Topic 740, the impact of an
uncertain income tax position, in managements opinion, on the income tax return must be recognized
at the largest amount that is more-likely-than not to be sustained upon audit by the relevant
taxing authority. An uncertain income tax position will not be recognized if it has a less than
50% likelihood of being sustained.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in
millions):
Balance at January 1, 2009 |
$ | 61 | ||
Additions based on tax positions related to the current
year |
5 | |||
Additions for tax positions of prior years |
6 | |||
Reductions for lapse of applicable statutes of limitations |
(2 | ) | ||
Settlements |
(11 | ) | ||
Balance at September 30, 2009 |
$ | 59 | ||
The Company is subject to taxation in the U.S., various states and foreign jurisdictions. The
Company has significant operations in the U.S., Canada, the U. K., the Netherlands and Norway. Tax
years that remain subject to examination by major tax jurisdiction vary by legal entity, but are
generally open in the U.S. for the tax years after 2005 and outside the U.S. for tax years ending
after 2002.
To the extent penalties and interest would be assessed on any underpayment of income tax, such
accrued amounts have been classified as a component of income tax expense in the financial
statements.
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12. 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. During the second quarter of 2009, the Company with approval from shareholders increased the
number of shares authorized under the Plan from 15 million to 26 million. As of September 30,
2009, 11,890,826 shares remain available for future grants under the Plan, all of which are
available for grants of stock options, performance-based share awards, restricted stock awards,
phantom shares, stock payments and stock appreciation rights. Total stock-based compensation for
all share-based compensation arrangements under the Plan was $15 million and $46 million for the
three and nine months ended September 30, 2009, respectively, and $23 million and $52 million for
the three and nine months ended September 30, 2008, respectively. The total income tax benefit
recognized in the Consolidated Statements of Income for all stock-based compensation arrangements
under the Plan was $5 million and $17 million for the three and nine months ended September 30,
2009, respectively, and $5 million and $16 million for the three and nine months ended September
30, 2008, respectively.
During the nine months ended September 30, 2009, the Company granted 3,234,400 stock options and
762,692 restricted stock awards, which includes 309,000 performance-based restricted stock awards.
Out of the total number of stock options granted, 3,206,400 were granted on February 20, 2009 with
an exercise price of $25.96. These options generally vest over a three-year period from the grant
date. The remaining 28,000 options were granted May 13, 2009 to the non-employee members of the
Board of Directors at an exercise price of $33.57. These options generally vest over a three-year
period from the grant date. Out of the total number of restricted stock awards granted, 434,400
were granted on February 20, 2009 and vest on the third anniversary of the date of grant. On May
13, 2009, 19,292 restricted stock awards were granted to the non-employee members of the Board of
Directors. These restricted stock awards vest in equal thirds over three years on the anniversary
of the grant date. The performance-based restricted stock awards of 309,000 were granted on
February 20, 2009. The performance-based restricted stock awards granted will be 100% vested 36
months from the date of grant, subject to the performance condition of the Companys average
operating income growth, measured on a percentage basis, from January 1, 2009 through December 31,
2011 exceeding the median operating income level growth of a designated peer group over the same
period.
13. Derivative Financial Instruments
The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended
(SFAS 133), which was primarily codified into ASC Topic 815, Derivatives and Hedging. (ASC
Topic 815) This Standard requires companies to recognize all of its derivative instruments as
either assets or liabilities in the statement of financial position at fair value. The accounting
changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it
has been designated and qualifies as part of a hedging relationship and further, on the type of
hedging relationship. For those derivative instruments that are designated and qualify as hedging
instruments, a company must designate the hedging instrument, based upon the exposure being hedged,
as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.
The Company is exposed to certain risks relating to its ongoing business operations. The primary
risks managed by using derivative instruments are foreign currency exchange rate risk, and interest
rate risk. Forward contracts against various foreign currencies are entered into to manage the
foreign currency exchange rate risk on forecasted revenue and expenses denominated in currencies
other than the functional currency of the operating unit (cash flow hedge). Other forward exchange
contracts against various foreign currencies are entered into to manage the foreign currency
exchange rate risk associated with certain firm commitments denominated in currencies other than
the functional currency of the operating unit (fair value hedge). In addition the Company will
enter into non-designated forward contracts against various foreign currencies to manage the
foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts
(non-designated hedge). Interest rate swaps are entered into to manage interest rate risk
associated with the Companys fixed and floating-rate borrowings.
The Company records all derivative financial instruments at their fair value in our consolidated
balance sheet. Except for certain non-designated hedges discussed below, all derivative financial
instruments we hold are designated as either cash flow or fair value hedges and are highly
effective in offsetting movements in the underlying risks. Such arrangements typically have terms
between two and 24 months, but may have longer terms depending on the underlying cash flows being
hedged, typically related to the projects in our backlog. We may also use interest rate contracts
to mitigate our exposure to changes in interest rates on anticipated long-term debt issuances.
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At September 30, 2009, the Company has determined that its financial assets of $150 million and
liabilities of $64 million (primarily currency related derivatives) are level 2 in the fair value
hierarchy. At September 30, 2009, the fair value of the Companys foreign currency forward
contracts totaled $86 million.
As of September 30, 2009, the Company did not have any interest rate swaps and our financial
instruments do not contain any credit-risk-related or other contingent features that could cause
accelerated payments when our financial instruments are in net liability positions. We do not use
derivative financial instruments for trading or speculative purposes.
Cash Flow Hedging Strategy
For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the
exposure to variability in expected future cash flows that is subject to a particular currency
risk), the effective portion of the gain or loss on the derivative instrument is reported as a
component of other comprehensive income and reclassified into earnings in the same line item
associated with the forecasted transaction and in the same period or periods during which the
hedged transaction affects earnings (e.g., in revenues when the hedged transactions are cash
flows associated with forecasted revenues). The remaining gain or loss on the derivative
instrument in excess of the cumulative change in the present value of future cash flows of the
hedged item, if any (i.e., the ineffective portion) or hedge components excluded from the
assessment of effectiveness, are recognized in the Consolidated Statements of Income during the
current period.
To protect against the volatility of forecasted foreign currency cash flows resulting from
forecasted sales and expenses, the Company has instituted a cash flow hedging program. The Company
hedges portions of its forecasted revenues and expenses denominated in nonfunctional currencies
with forward contracts. When the U.S. dollar strengthens against the foreign currencies, the
decrease in present value of future foreign currency revenue and costs is offset by gains in the
fair value of the forward contracts designated as hedges. Conversely, when the U.S. dollar
weakens, the increase in the present value of future foreign currency cash flows is offset by
losses in the fair value of the forward contracts.
As of September 30, 2009, the Company had the following outstanding foreign currency forward
contracts that were entered into to hedge nonfunctional currency cash flows from forecasted
revenues and costs:
Currency | |||||||||
Foreign Currency | Denomination | ||||||||
(in millions) | |||||||||
British Pound Sterling |
£ | 40 | |||||||
Danish Krone |
DKK | 201 | |||||||
Euro |
| 220 | |||||||
Norwegian Krone |
NOK | 6,896 | |||||||
U.S. Dollar |
$ | 137 | |||||||
Korean Won |
KRW | 5,170 |
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.
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As of September 30, 2009, the Company had the following outstanding foreign currency forward
contracts that were entered into to hedge nonfunctional currency fair values of firm commitments of
revenues and costs:
Currency | ||||
Foreign Currency | Denomination | |||
(in millions) | ||||
U.S. Dollar |
$ | 42 |
Non-designated Hedging Strategy
For derivative instruments that are non-designated, the gain or loss on the derivative instrument
subject to the hedged risk (i.e. nonfunctional currency monetary accounts) are recognized in the
same line item associated with the hedged item in current earnings.
The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary
accounts. The purpose of the Companys foreign currency hedging activities is to protect the
Company from risk that the eventual U.S. dollar-equivalent cash flows from the nonfunctional
currency monetary accounts will be adversely affected by changes in the exchange rates.
As of September 30, 2009, the Company had the following outstanding foreign currency forward
contracts that hedge the fair value of nonfunctional currency monetary accounts:
Currency | ||||||||
Foreign Currency | Denomination | |||||||
(in millions) | ||||||||
British Pound Sterling |
£ | 7 | ||||||
Danish Krone |
DKK | 180 | ||||||
Euro |
| 121 | ||||||
Norwegian Krone |
NOK | 4,590 | ||||||
Swedish Krone |
SEK | 5 | ||||||
U.S. Dollar |
$ | 571 | ||||||
Korean Won |
KRW | 496 |
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As of September 30, 2009, the Company has the following fair values of its derivative instruments
and their balance sheet classifications (in millions):
NATIONAL OILWELL VARCO, INC.
Fair Values of Derivative Instruments
(In millions)
Fair Values of Derivative Instruments
(In millions)
September 30, 2009 | ||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||
Location | Value | Location | Value | |||||||||
Derivatives designated as hedging
instruments under ASC Topic 815 |
||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 73 | Accrued liabilities | $ | 22 | ||||||
Foreign exchange contracts |
Other Assets | 30 | Other Liabilities | 2 | ||||||||
Total derivatives designated as hedging
instruments under ASC Topic 815 |
$ | 103 | $ | 24 | ||||||||
Derivatives not designated as hedging
instruments under ASC Topic 815 |
||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 43 | Accrued liabilities | $ | 39 | ||||||
Foreign exchange contracts |
Other Assets | 4 | Other Liabilities | 1 | ||||||||
Total derivatives not designated as hedging
instruments under ASC Topic 815 |
$ | 47 | $ | 40 | ||||||||
Total derivatives |
$ | 150 | $ | 64 | ||||||||
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The Effect of Derivative Instruments on the Consolidated Statement of Income
Periods Ended September 30, 2009
($ in millions)
Periods Ended September 30, 2009
($ 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) | |||||||||||||||||||||||
September 30, 2009 | September 30, 2009 | September 30, 2009 | ||||||||||||||||||||||||||
Three Months | Nine Months | Three Months | Nine Months | Three Months | Nine Months | |||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||
Revenue | 8 | 18 | ||||||||||||||||||||||||||
Foreign exchange contracts |
88 | 162 | Cost of revenue | (7 | ) | (51 | ) | Other income(expense), net | (3 | ) | (27 | ) | ||||||||||||||||
Total |
88 | 162 | 1 | (33 | ) | (3 | ) | (27 | ) | |||||||||||||||||||
Derivatives in ASC Topic 815 | Location of Gain (Loss) | Amount of Gain (Loss) | ASC Topic 815 | Location of Gain (Loss) | Recognized in Income on | |||||||||||||||||
Fair Value | Recognized in Income | Recognized in Income on | Fair Value Hedge | Recognized in Income on | Related Hedged | |||||||||||||||||
Hedging Relationships | on Derivative | Derivative | Relationships | Related Hedged Item | Items | |||||||||||||||||
September 30, 2009 | September 30, 2009 | |||||||||||||||||||||
Three Months | Nine Months | Three Months | Nine Months | |||||||||||||||||||
Ended | Ended | Ended | Ended | |||||||||||||||||||
Foreign exchange contracts |
Revenue | (3 | ) | (5 | ) | Firm commitments | Revenue | 3 | 5 | |||||||||||||
Foreign exchange contracts |
Cost of revenue | 2 | 1 | Firm commitments | Cost of revenue | (2 | ) | (1 | ) | |||||||||||||
Total |
(1 | ) | (4 | ) | 1 | 4 | ||||||||||||||||
Derivatives Not Designated as | Location of Gain (Loss) | Amount of Gain (Loss) | ||||||||||||||||||||
Hedging Instruments under | Recognized in Income | Recognized in Income on | ||||||||||||||||||||
ASC Topic 815 | on Derivative | Derivative (a) | ||||||||||||||||||||
Foreign exchange contracts |
Other income (expense), net | 10 | (14 | ) | ||||||||||||||||||
Total |
10 | (14 | ) | |||||||||||||||||||
(a) | The Company expects that $(34) million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow. | |
(b) | The amount of gain (loss) recognized in income represents $(3) million and $(27) million related to the ineffective portion of the hedging relationships for the three and nine months ended September 30, 2009, respectively, and $(1) million and $2 million related to the amount excluded from the assessment of the hedge effectiveness for the three and nine months ended September 30, 2009. |
We assess the functional currencies of our operating units to ensure that the appropriate
currencies are utilized in accordance with the guidance of SFAS No. 52, Foreign Currency
Translation, which was primarily codified into ASC Topic 830. Effective January 1, 2008, we changed
the functional currency of our Rig Technology unit in Norway from the Norwegian krone to the U.S.
dollar to more appropriately reflect the primary economic environment in which they operate. This
change was precipitated by significant changes in the economic facts and circumstances, including
the increased order rate for large drilling platforms and components technology, the use of our
Norway unit as our preferred project manager of these projects, increasing revenue and cost base in
U.S. dollars, and the implementation of an international cash pool denominated in U.S. dollars. As
a Norwegian krone functional unit, Norway was subject to increasing foreign currency exchange risk
as a result of these changes in its economic environment and was dependent upon significant hedging
transactions to offset its non-functional currency positions.
At December 31, 2007, our Norway operations had foreign currency forward contracts with notional
amounts aggregating $2,551 million with a fair value of $91 million to mitigate foreign currency
exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the
functional currency, the Company terminated these hedges. The related net gain position of
$109 million associated with the terminated hedges was deferred and is being recognized into
earnings in the future period(s) the forecasted transactions affect earnings, of which $15 million
remains to be recognized into earnings at September 30, 2009. The Company has, subsequent to
January 1, 2008, entered into new hedges to cover the exposures as a result of the change to U.S.
dollar functional. At September 30, 2009, our Norway operations had derivatives with
$2,431 million in notional value with a fair value asset of $82 million.
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14. 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, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Numerator: |
||||||||||||||||
Net income attributable to Company |
$ | 385 | $ | 548 | $ | 1,075 | $ | 1,367 | ||||||||
Denominator: |
||||||||||||||||
Basicweighted average common shares outstanding |
416 | 416 | 416 | 391 | ||||||||||||
Dilutive effect of employee stock options and other unvested
stock awards |
2 | 2 | 1 | 2 | ||||||||||||
Diluted outstanding shares |
418 | 418 | 417 | 393 | ||||||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 0.93 | $ | 1.32 | $ | 2.58 | $ | 3.49 | ||||||||
Diluted |
$ | 0.92 | $ | 1.31 | $ | 2.58 | $ | 3.48 | ||||||||
In addition, the Company had stock options outstanding that were anti-dilutive totaling 4 million
and 6 million shares for the three and nine months ended September 30, 2009, respectively, and 1
million shares for both the three and nine months ended September 30, 2008, respectively.
15. Recently Issued Accounting Standards
In February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position
(FSP) SFAS 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2), which defers the
effective date of SFAS No. 157, Fair Value Measurements (SFAS 157), as it related to
non-financial assets and non-financial liabilities, to fiscal years beginning after November 15,
2008 and interim periods within those fiscal years. Both standards mentioned above were primarily
codified into ASC Topic 820, Fair Value Measurements and Disclosures (ASC Topic 820). The
Company, as of January 1, 2009, adopted the provisions of this statement and included the
appropriate disclosures surrounding non-financial assets and liabilities, as applicable.
In December 2007, the FASB issued SFAS No. 141R, Business Combinations (SFAS 141R), which was
primarily codified into ASC Topic 850, Business Combinations (ASC Topic 850). ASC Topic 850
provides revised guidance on how acquirers recognize and measure the consideration transferred,
identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired
in a business combination. ASC Topic 850 also expands required disclosures surrounding the nature
and financial effects of business combinations. ASC Topic 850 is effective, on a prospective basis,
for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC
Topic 850. The Company expects that this new standard will impact certain aspects of its
accounting for business combinations on a prospective basis, including the determination of fair
values assigned to certain purchased assets and liabilities.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial
Statements (SFAS 160), which was primarily codified into ASC Topic 810, Consolidations (ASC
Topic 810). ASC Topic 810 establishes requirements for ownership interests in subsidiaries held by
parties other than the Company (previously called minority interests) be clearly identified,
presented, and disclosed in the consolidated statement of financial position within equity, but
separate from the parents equity. All changes in the parents ownership interests are required to
be accounted for consistently as equity transactions and any noncontrolling equity investments in
deconsolidated subsidiaries must be measured initially at fair value. ASC Topic 810 is effective,
on a prospective basis, for fiscal years beginning after December 15, 2008. However, presentation
and disclosure requirements must be retrospectively applied to comparative financial statements. On
January 1, 2009, the Company adopted ASC Topic 810, and reclassified noncontrolling interests in
the amounts of $109 million and $96 million from the mezzanine section to equity in the September
30, 2009 and December 31, 2008 balance sheets, respectively.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement No. 133 (SFAS 161), which was primarily codified
into ASC Topic 815, Derivatives and
Hedging (ASC Topic 815). ASC Topic 815 amends and expands the disclosure requirements for
derivative instruments and hedging activities, with the intent to provide users of financial
statements with an enhanced understanding of how and why an
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entity uses derivative instruments, how
derivative instruments and related hedged items are accounted for, and how derivative instruments
and related hedged items affect an entitys financial statements. ASC Topic 815 is effective for
fiscal years and interim periods beginning after November 15, 2008. On January 1, 2009, the Company
adopted ASC Topic 815. See Note 11. Derivative Financial Instruments, in the notes to the
consolidated financial statements.
In April 2008, the FASB issued FASB Staff Position (FSP) SFAS 142-3, Determination of the Useful
Life of Intangible Assets (FSP SFAS 142-3), which was primarily codified into ASC Topic 350,
Intangibles Goodwill and Other (ASC Topic 350). ASC Topic 350 amends the factors that should
be considered in developing renewal or extension assumptions used to determine the useful life of a
recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets.
The objective of this ASC is to improve the consistency between the useful life of a recognized
intangible asset under Statement No. 142 and the period of expected cash flows used to measure the
fair value of the asset under SFAS 141R and other U.S. GAAP principles. ASC Topic 350 is effective
for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC
Topic 350. There was no significant impact to the Companys consolidated financial statements from
the adoption of ASC Topic 350.
In April 2009 the FASB issued FSP 141R-1, Accounting for Assets Acquired and Liabilities Assumed
in a Business Combination That Arise from Contingencies (FSP 141R-1), which was primarily
codified into ASC Topic 850, Business Combinations (ASC Topic 850). ASC Topic 850 amends the
provisions in SFAS 141R for the initial recognition and measurement, subsequent measurement and
accounting, and disclosures for assets and liabilities arising from contingencies in business
combinations. The ASC eliminates the distinction between contractual and non-contractual
contingencies, including the initial recognition and measurement criteria in SFAS 141R and instead
carries forward most of the provisions in SFAS 141 for acquired contingencies. ASC Topic 850 is
effective for contingent assets and contingent liabilities acquired in business combinations for
which the acquisition date is on or after the beginning of the first annual reporting period
beginning on or after December 15, 2008. The Company expects ASC Topic 850 will have a future
impact on its consolidated financial statements, but the nature and magnitude of the specific
effects will depend upon the nature, term and size of the acquired contingencies.
In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments (FSP SFAS 107-1), which was primarily codified into ASC Topic 825,
Financial Instruments (ASC Topic 825). ASC Topic 825 extends the disclosure requirements
regarding the fair value of financial instruments under SFAS No. 107, Disclosures about Fair Value
of Financial Instruments (SFAS No. 107), to interim financial statements of publicly traded
companies. ASC Topic 825 is effective for interim reporting periods ending after June 15, 2009,
with early adoption permitted for periods ending after March 15, 2009. Early adoption of this ASC
is permitted only if the entity also elects to early adopt FSP SFAS 157-4 and FSP SFAS 115-2. On
June 1, 2009, the Company adopted ASC Topic 825. There was no significant impact to the Companys
consolidated financial statements from the adoption of ASC Topic 825.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS 165), which was primarily
codified into ASC Topic 855, Subsequent Events (ASC Topic 855). ASC Topic 855 requires the
disclosure of the date through which an entity has evaluated subsequent events and the basis for
that date. ASC Topic 855 is effective for fiscal years and interim periods ending after June 15,
2009. On June 1, 2009, the Company adopted ASC Topic 855. There was no significant impact to the
Companys consolidated financial statements from the adoption of ASC Topic 855.
In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the
Hierarchy of Generally Accepted Accounting Principles (SFAS 168), which amends SFAS 162, The
Hierarchy of Generally Accepted Accounting Principles. Both of these standards were primarily
codified into ASC Topic 105, Generally Accepted Accounting Standards (ASC Topic 105). The ASC
will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal
securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date,
ASC Topic 105 will supersede all then-existing non-SEC accounting and reporting standards. All
other non-grandfathered non-SEC accounting literature not included in the ASC will become
non-authoritative. ASC Topic 105 is effective for financial statements issued for interim and
annual periods ending after September 15, 2009.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Introduction
National Oilwell Varco, Inc. (the Company) is a worldwide leader in the design, manufacture and
sale of equipment and components used in oil and gas drilling and production, the provision of
oilfield services, and supply chain integration services to the upstream oil and gas industry. The
following describes our business segments:
Rig Technology
Our Rig Technology segment designs, manufactures, sells and services complete systems for the
drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line
of highly-engineered equipment that automates complex well construction and management operations,
such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly
systems; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well
workover rigs; wireline winches; wireline trucks; and cranes. Demand for Rig Technology products is
primarily dependent on capital spending plans by drilling contractors, oilfield service companies,
and oil and gas companies, and secondarily on the overall level of oilfield drilling activity,
which drives demand for spare parts for the segments large installed base of equipment. We have
made strategic acquisitions and other investments during the past several years in an effort to
expand our product offering and our global manufacturing capabilities, including adding additional
operations in the United States, Canada, Norway, the United Kingdom, China, Belarus, India, Turkey,
the Netherlands, and Singapore.
Petroleum Services & Supplies
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used
to drill, complete, remediate and workover oil and gas wells and service pipelines, flowlines and
other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and
equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer
pumps, solids control systems, drilling motors, drilling fluids, drill bits, reamers and other
downhole tools, and mud pump consumables. Demand for these services and supplies is determined
principally by the level of oilfield drilling and workover activity by drilling contractors, major
and independent oil and gas companies, and national oil companies. Oilfield tubular services
include the provision of inspection and internal coating services and equipment for drill pipe,
line pipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe
and advanced composite pipe for application in highly corrosive environments. The segment sells its
tubular goods and services to oil and gas companies; drilling contractors; pipe distributors,
processors and manufacturers; and pipeline operators. This segment has benefited from several
strategic acquisitions and other investments completed during the past few years, including adding
additional operations in the United States, Canada, the United Kingdom, 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.
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Critical Accounting Estimates
In our annual report on Form 10-K for the year ended December 31, 2008, we identified our most
critical accounting policies. In preparing the financial statements, we make assumptions, estimates
and judgments that affect the amounts reported. We periodically evaluate our estimates and
judgments that are most critical in nature which are related to revenue recognition under long-term
construction contracts; allowance for doubtful accounts; inventory reserves; impairments of
long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and
other indefinite-lived intangible assets and income taxes. Our estimates are based on historical
experience and on our future expectations that we believe are reasonable. The combination of these
factors forms the basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Actual results are likely to differ from our
current estimates and those differences may be material.
Goodwill and Other Indefinite Lived Intangible Assets
The Company has approximately $5.5 billion of goodwill and $0.6 billion of other intangible assets
with indefinite lives on its consolidated balance sheet as of September 30, 2009. The Company tests
goodwill and other indefinite-lived intangible assets for impairment at least annually or more
frequently whenever events or circumstances occur indicating that goodwill or other
indefinite-lived intangible assets might be impaired. The annual impairment test is performed
during the fourth quarter of each year. Based on its analysis, the Company did not report any
impairment of goodwill and other indefinite-lived intangible assets for the year ended December 31,
2008. As described below, the Company concluded that an indicator of impairment did occur in the
second quarter of 2009 and updated its impairment testing at June 30, 2009. Based on its updated
analysis, the Company concluded that it did not incur an impairment of goodwill for the period
ending June 30, 2009. However, based on the Companys indefinite-lived intangible asset impairment
analysis performed during the second quarter of 2009, the Company concluded that it did incur an
impairment charge to certain indefinite-lived intangible assets of $147 million at June 30, 2009.
The $147 million impairment charge is included in the Companys consolidated income statement for
the nine months ended September 30, 2009.
During the second quarter of 2009, the worldwide average rig count was 2,009 rigs, down 41% from
the fourth quarter 2008 average of 3,395 and down 25% from the first quarter 2009 average of 2,681.
The second quarter 2009 average rig count represented the lowest quarterly average in the past six
years. In addition, the Companys updated forecast was behind the Companys previous forecast
completed at the beginning of 2009. While operating profit for the first quarter of 2009 was in
line with the Companys first quarter 2009 operating profit forecast, the Companys consolidated
operating profit for the second quarter of 2009 was below its second quarter 2009 forecast. As a
result of the substantial decline in the worldwide rig count, and the decline in actual/forecasted
results compared to the original 2009 forecast, the Company concluded that events or circumstances
had occurred indicating that goodwill and other indefinite-lived intangible assets might be
impaired as described under ASC Topic 350.
Therefore, the Company performed its interim impairment test of goodwill for all its reporting
units at the end of the second quarter of 2009. The implied fair value of goodwill is determined by
deducting the fair value of a reporting units identifiable assets and liabilities from the fair
value of that reporting unit as a whole. Fair value of the reporting units is determined in
accordance with ASC Topic 820 using significant unobservable inputs, or level 3 in the fair value
hierarchy. These inputs are based on internal management estimates, forecasts and judgments, using
a combination of three methods: discounted cash flow, comparable companies, and representative
transactions. While the Company primarily uses the discounted cash flow method to assess fair
value, the Company uses the comparable companies and representative transaction methods to validate
the discounted cash flow analysis and further support managements expectations, where possible.
The discounted cash flow is based on managements short-term and long-term forecast of operating
performance for each reporting unit. The two main assumptions used in measuring goodwill
impairment, which bear the risk of change and could impact the Companys goodwill impairment
analysis, include the cash flow from operations from each of the Companys individual business
units and the weighted average cost of capital. The starting point for each of the reporting units
cash flow from operations is the detailed annual plan or updated forecast. The detailed planning
and forecasting process takes into consideration a multitude of factors including worldwide rig
activity, inflationary forces, pricing strategies, customer analysis, operational issues,
competitor analysis, capital spending requirements, working capital needs, customer needs to
replace aging equipment, increased complexity of drilling, new technology, and existing backlog
among other items which impact the individual reporting unit projections. Cash flows beyond the
specific operating plans were estimated using a terminal value calculation, which incorporated
historical and forecasted financial cyclical trends for each reporting unit and considered
long-term earnings growth rates. The financial and credit market volatility directly impacts our
fair value measurement through our weighted average cost of capital that we use to determine our
discount rate. During times of volatility, significant judgment must be applied to determine
whether credit changes are a short-term or long-term trend.
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Projections for the remainder of 2009 also reflected declines compared to the original 2009 annual
forecast. The Company updated its 2009 operating forecast, long-term forecast, and discounted cash
flows based on this information. The goodwill impairment analysis that we performed during the
second quarter of 2009 did not result in goodwill impairment as of June 30, 2009.
The Company performed a sensitivity analysis on the projected results and goodwill impairment
analysis assuming revenue for each individual reporting unit decreased an additional 20% from the
current projections for each of the remainder of 2009, 2010, and 2011, while holding all
other factors constant, and no goodwill impairment was identified for any of the reporting units.
Additionally, if the Company were to increase its discount rate 100 basis points, while keeping all
other assumptions constant, there would be no impairments in any of the reporting units. While the
Company does not believe that these events (20% drop in additional revenue for the next three years
or 100 basis point increases in weighted average costs of capital) or changes are likely to occur,
it is reasonably possible these events could transpire if market conditions worsen and if the
market fails to recover in 2010 and/or 2011. Any significant changes to these assumptions and
factors could have a material impact on the Companys goodwill impairment analysis. Inherent in
our projections are key assumptions relative to how long the current downward cycle might last.
While we believe these assumptions are reasonable and appropriate, we will continue to monitor
these, and update our impairment analysis if the cycle downturn continues for longer than expected.
Other indefinite-lived intangible assets, representing trade names management intends to use
indefinitely, were valued using significant unobservable inputs (level 3) and are tested for
impairment using the Relief from Royalty Method, a form of the Income Approach. An impairment is
measured and recognized based on the amount the book value of the indefinite-lived intangible
assets exceeds its estimated fair value as of the date of the impairment test. Included in the
impairment test are assumptions, for each trade name, regarding the related revenue streams
attributable to the trade names which are determined consistent with the forecasting process
described above, the royalty rate, and the discount rate applied. Based on the Companys
indefinite-lived intangible asset impairment analysis performed during the second quarter of 2009,
the Company incurred an impairment charge of $147 million in the Petroleum Services & Supplies
segment related to a partial impairment of the Companys Grant Prideco trade name. The impairment
charge was primarily the result of the substantial decline in worldwide rig counts through June
2009, declines in current forecasts in rig activity for the remainder of 2009, 2010, and 2011
compared to rig count forecast at the beginning of 2009 and a current decline in the revenue
forecast for the drill pipe business unit for the remainder of 2009, 2010, and 2011.
The Company performed a sensitivity analysis on the projected results and indefinite-lived
intangible asset impairment assuming revenue for each individual trade name decreased an additional
20% from the current projections for each of the remainder of 2009, 2010, and 2011, while
holding all other factors constant, and a pre-tax non-cash impairment charge of approximately
$79 million would be incurred under those assumptions. If the discount rate applied to the fair
value calculation increased by 100 basis points, and all other assumptions remained constant, a
pre-tax, non-cash impairment charge of approximately $36 million would be incurred under those
assumptions.
The Company will continue to closely monitor indicators of impairment, which could include, but are
not limited to, further declines in worldwide rig activity, further declines in commodity prices or
futures, or further significant economic declines. If such further deterioration of indicators
occurs, and the Company believes that these negative trends are likely to persist for a prolonged
period of time, then the Companys expected future earnings and cash flows from operations would be
adversely impacted. This may result in impairment to either or both goodwill and indefinite-lived
intangible assets, and such impairment may be material.
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EXECUTIVE SUMMARY
National Oilwell Varco generated earnings of $385 million or $0.92 per fully diluted share in its
third quarter ended September 30, 2009, on revenues of $3,087 million. Compared to the third
quarter of 2008 revenue declined 15 percent and net income attributable to the Company declined 30
percent. Compared to the second quarter of 2009 revenue increased three percent and net income
attributable to the Company increased 75 percent, due in large part to the non-recurrence of $203
million in pre-tax asset impairment, transaction, and voluntary retirement charges and a higher
income tax rate recognized in the second quarter of 2009, in addition to higher third quarter sales
and margins.
Operating profit was $601 million or 19.5 percent of sales for the third quarter. Excluding $11
million of transaction and restructuring charges, third quarter operating profit was $612 million
or 19.8 percent of sales, compared to $589 million or 19.6 percent of sales in the second quarter
of 2009 (excluding transaction and impairment charges), and $790 million or 21.9 percent of sales
in the third quarter of 2008. Operating profit leverage or flow-through (the change in operating
profit divided by the change in revenue period-to-period) was up 38 percent from the second quarter
of 2009 to the third quarter of 2009, and down 38 percent from the third quarter of 2008 to the
third quarter of 2009, excluding transaction, restructuring and impairment charges from all
periods.
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 have responded vigorously, but credit and financial markets
have not yet fully recovered, and a credit-driven worldwide economic recession deepened during the
second quarter. Asset and commodity prices, including oil and gas prices, have declined sharply.
After rising steadily for six years to peak at around $140 per barrel earlier in 2008, oil prices
collapsed back to average $42.91 per barrel during the first quarter of 2009, but have been
recovering steadily to average $68.20 during the third quarter of 2009. Higher oil and gas prices
over the past several years led to high levels of exploration and development drilling in many oil
and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas
prices and tightening credit availability.
The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the
level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a
low of 887 in June 2009. Rig count has increased slightly since, to 1,048 in October 2009, and
averaged 974 rigs during the third quarter of 2009. Many oil and gas operators reliant on external
financing to fund their drilling programs have significantly curtailed their drilling activity,
which appears to have had the greatest impact on gas drilling across North America. Most
international activity is driven by oil exploration and production by national oil companies, which
has historically been less susceptible to short-term commodity price swings, but the international
rig count has exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108
to 986 in September 2009. During the third quarter of 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, while the Companys Rig Technology segment was less
impacted owing to its high level of backlog.
Recent downturns follow 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.
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The industry responded by launching many new rig construction projects since 2005, to retool the
existing fleet of jackup rigs (according to Offshore Data Services, 73 percent of the existing 445
jackup rigs are more than 25 years old); to replace older mechanical and DC electric land rigs with
improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown
technology; and to build out additional deepwater floating drilling rigs, including
semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit
unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency,
safety, and capability, and that many will effectively replace a portion of the existing fleet, and
that declining dayrates may accelerate the retirement of older rigs. As a result of these trends
the Companys Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion
at March 31, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit
crisis and slowing drilling activity, orders have declined below amounts flowing out of backlog as
revenue, causing the backlog to decline to $7.3 billion by September 30, 2009.
Land rigs comprised 11 percent and equipment destined for offshore operations comprised
89 percent of the total backlog as of September 30, 2009. Equipment destined for international
markets totaled 93 percent of the backlog. The Company believes that its existing contracts for
rig equipment are very strong in that they carry significant down payment and progress billing
terms favorable to the ultimate completion of these projects, and generally do not allow customers
to cancel projects for convenience. During the third quarter of 2009 the Company removed $72
million in discontinued orders on cancelled projects and project change orders requested by
customers. We do not expect the credit crisis or softer market to result in additional material
cancelation of contracts or abandonment of major projects; however, there can be no assurance that
such discontinuance of projects will not occur. The Company had approximately $334 million of
projects in its September 30, 2009 backlog that it considers at risk.
Segment Performance
Rig
Technology generated $2,000 million in revenue and $577 million in operating profit in the
third quarter of 2009, producing a record operating margin for the
segment of 28.9 percent. The
segment generated 52 percent operating leverage or
flow-through on four percent higher sales from
the second quarter of 2009 to the third quarter of 2009. Compared to the prior year third quarter
operating leverage or
flow-through was 105 percent on four percent sales growth. Revenue out of backlog of $1,599 million increased 12 percent sequentially and increased 17 percent compared to the third quarter of last year. Execution of the backlog orders was very strong, which led to higher margin performance for the Rig Technology segment in the third quarter due to excellent cost control, deflation in certain inputs, greater experience building and commissioning rigs which enables better efficiencies, and somewhat better FX movements. As a result our estimated costs to complete projects have declined steadily through 2009. As of September 30, 2009 the scheduled outflow of revenue from backlog is expected to be approximately $1.3 billion in the fourth quarter of 2009, $4.7 billion in 2010, and $1.3 billion for 2011. From 2005 through the current quarter, the segment has delivered a total of 66 newly built offshore rigs. Aftermarket spare parts and services revenue was essentially flat in the third quarter as compared to the second quarter, but sales of smaller capital items which do not qualify for the backlog declined sharply. Demand for offshore rigs and equipment is strongest in Brazil, owing to significant drilling equipment needs to develop new ultradeepwater discoveries, and the segment also continues to pursue a variety of new offshore rig, intervention vessel, FPSO and platform upgrade opportunities in other markets. However, tight credit markets and fewer committed term contracts for rigs by oil and gas companies as compared to market conditions in 2006-2008 are adversely affecting new orders, which totaled only $333 million in the third quarter. Demand for land rig and well stimulation equipment has also been very slow, except for the Middle East and certain Latin American markets. In particular demand for equipment in North America remains soft, although the Companys first new Drake rigs delivered into the Marcellus shale play are performing well, and the Company believes acceptance of new technology land rigs continues to make steady progress.
flow-through was 105 percent on four percent sales growth. Revenue out of backlog of $1,599 million increased 12 percent sequentially and increased 17 percent compared to the third quarter of last year. Execution of the backlog orders was very strong, which led to higher margin performance for the Rig Technology segment in the third quarter due to excellent cost control, deflation in certain inputs, greater experience building and commissioning rigs which enables better efficiencies, and somewhat better FX movements. As a result our estimated costs to complete projects have declined steadily through 2009. As of September 30, 2009 the scheduled outflow of revenue from backlog is expected to be approximately $1.3 billion in the fourth quarter of 2009, $4.7 billion in 2010, and $1.3 billion for 2011. From 2005 through the current quarter, the segment has delivered a total of 66 newly built offshore rigs. Aftermarket spare parts and services revenue was essentially flat in the third quarter as compared to the second quarter, but sales of smaller capital items which do not qualify for the backlog declined sharply. Demand for offshore rigs and equipment is strongest in Brazil, owing to significant drilling equipment needs to develop new ultradeepwater discoveries, and the segment also continues to pursue a variety of new offshore rig, intervention vessel, FPSO and platform upgrade opportunities in other markets. However, tight credit markets and fewer committed term contracts for rigs by oil and gas companies as compared to market conditions in 2006-2008 are adversely affecting new orders, which totaled only $333 million in the third quarter. Demand for land rig and well stimulation equipment has also been very slow, except for the Middle East and certain Latin American markets. In particular demand for equipment in North America remains soft, although the Companys first new Drake rigs delivered into the Marcellus shale play are performing well, and the Company believes acceptance of new technology land rigs continues to make steady progress.
The Petroleum Services & Supplies segment generated revenues of $882 million and operating profit
of $82 million or 9.3 percent of sales in the third quarter of 2009 (excluding transaction and
restructuring charges). Revenues declined three percent from the second quarter of 2009 and 33
percent from the third quarter of 2008. Almost all product lines within Petroleum Services &
Supplies posted low single-digit percent sales declines in the third quarter as compared to the
second quarter, as customer spending remained subdued. Decremental operating leverage was 32
percent from the second quarter of 2009 and 57 percent from the third quarter of 2008, reflective
of sharp pricing declines. Prices are down 30 percent or more year-over-year for many of the items
the segment sells, although discounts vary widely depending upon product and region. The business
continues to face very challenging market conditions with lower levels of drilling despite the
recent modest improvement in North American rig count. North American sales accounted for
approximately 42 percent of the segments total revenue during the third quarter of 2009.
Consumable products sales remain under pressure as customers cannibalize idle stocks and equipment
from stacked rigs, rather than place orders with the Company, as they reduced operating and capital
expenditures in view of lower activity. International markets have held up better, with pricing
down 5 to 20 percent as the rig count declined one percent sequentially. Sales of bits and
downhole tools improved in North America, but international demand for these fell in the third
quarter in Saudi Arabia and Europe, driving sequentially lower results.
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Drill pipe revenues were roughly flat with the second quarter but margins improved due to more
favorable mix of premium pipe for new offshore rigs and lower steel
costs. Drill pipe backlog and
sales are expected to continue to decline due to the current oversupply, which is not likely to
turn around before late 2010. Lower drill pipe demand also reduced
drill pipe coating and inspection
services at high decremental margins. Wellsite Services and coiled tubing posted slightly lower
margins on lower solids control equipment and string sales, and increased discounting.
The
Distribution Services segment generated total sales of $306 million for the third quarter of 2009,
unchanged from the second quarter and down 39 percent from the third quarter of 2008. Operating
profit was $7 million in the third quarter, down $3 million from the second quarter of 2009, and
operating margins were 2.3 percent, down 100 basis points from the second quarter of 2009. The
sequential decline in profitability arose from lower pricing, a decrease in supplier rebates on
falling annual sales volumes, and lower margins on industrial products and artificial lift.
Compared to the third quarter of 2008 decremental third quarter
leverage was 19 percent on a 39
percent sales decline. Domestic sales were essentially unchanged sequentially, but Canada revenues
increased as the region emerged from seasonal breakup, at excellent incremental profitability.
Total North American revenue mix grew slightly overall sequentially to 71 percent and international
sales declined sequentially and accounted for 29 percent of the segments third quarter mix.
Pricing pressures appear to be stabilizing across North America, but many customers are bidding out
much more of their work, which enabled the segment to win some incremental maintenance, repair and
operating supplies contracts during the quarter. Unconventional shale plays in the Marcellus,
Haynesville and Bakken are some of the most active North American markets, and the group continues
to expand its presence in these areas, as well as expand in Russia.
Outlook
The recent credit market downturn, global recession, and lower commodity prices have presented
challenges to our business, and consequently we remain cautious in our outlook, but we believe we
are seeing signs of stabilization in many of our markets. Order levels for new drilling rigs have
been slower to materialize in 2009 than we have expected, and while we do not foresee a significant
turnaround in the fourth quarter, we believe 2010 should produce better results. Stronger 2010
orders assume that recently issued tenders for new rigs, including up to 28 new offshore floaters
to be built in Brazil, translate into orders during the coming year; that rig dayrates generally
hold up well; that commodity prices remain high; and that broad economic conditions do not
deteriorate further. North American land gas drilling activity, particularly by independent gas
producers reliant on external financing, has fallen sharply since 2008 and although gas prices have
recently improved, we do not know when this sector will recover. Meaningfully lower gas
production, due to the industry downturn, should bring supply and demand back into balance at some
point. Our outlook for international markets, which are more driven by national oil company
activity, are historically less volatile and expected to continue to see comparatively better
market conditions.
Our outlook for the Companys Petroleum Services & Supplies segment and Distribution Services
segment remains guarded. We expect revenues for Petroleum Services & Supplies to fall again
slightly, and revenues for Distribution Services to rise slightly in the fourth quarter of 2009,
and margins for both to remain approximately stable, as cost reduction initiatives offset continued
pricing pressure. The Rig Technology segment is expected to be less affected by the downturn due
to the strength of its backlog, but is likely to nevertheless see lower fourth quarter revenues and
margins as revenues out of backlog decline sequentially, partly offset by non-backlog revenue
gains.
The Company believes it is well positioned to manage through this downturn, 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 well into the coming 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.
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Operating Environment Overview
The Companys results are dependent on, among other things, the level of worldwide oil and gas
drilling, well remediation activity, the prices of crude oil and natural gas, capital spending by
other oilfield service companies and drilling contractors, pipeline maintenance activity, and
worldwide oil and gas inventory levels. Key industry indicators for
the third quarter of 2009 and
2008, and the second quarter of 2009 include the following:
% | % | |||||||||||||||||||
3Q09 v | 3Q09 v | |||||||||||||||||||
3Q09* | 3Q08* | 2Q09* | 3Q08 | 2Q09 | ||||||||||||||||
Active Drilling Rigs: |
||||||||||||||||||||
U.S. |
974 | 1,978 | 936 | (50.8 | %) | 4.1 | % | |||||||||||||
Canada |
187 | 432 | 90 | (56.7 | %) | 107.8 | % | |||||||||||||
International |
969 | 1,095 | 983 | (11.5 | %) | (1.4 | %) | |||||||||||||
Worldwide |
2,130 | 3,505 | 2,009 | (39.2 | %) | 6.0 | % | |||||||||||||
West Texas Intermediate
Crude Prices (per
barrel) |
$ | 68.20 | $ | 118.40 | $ | 59.44 | (42.4 | %) | 14.7 | % | ||||||||||
Natural Gas Prices
($/mmbtu) |
$ | 3.17 | $ | 9.03 | $ | 3.71 | (64.9 | %) | (14.6 | %) |
* | 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, 2009 on a quarterly basis:
![(GRAPH)](https://www.sec.gov/Archives/edgar/data/0001021860/000095012309058999/h67776h6777601.gif)
Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude and
Natural Gas Prices: Department of Energy, Energy Information Administration (www.eia.doe.gov).
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The worldwide and U.S. quarterly average rig count decreased 39% (from 3,505 to 2,130) and 51%
(from 1,978 to 974), respectively, in the third quarter of 2009 compared to the third quarter of
2008. The average per barrel price of West Texas Intermediate Crude decreased 42% (from $118.40
per barrel to $68.20 per barrel) and natural gas prices decreased 65% (from $9.03 per mmbtu to
$3.17 per mmbtu) in the third quarter of 2009 compared to the third quarter of 2008.
U.S. rig activity at October 23, 2009 was 1,048 rigs compared to the third quarter average of 974
rigs. The price for West Texas Intermediate Crude was at $80.50 per barrel as of October 23, 2009,
increasing 18% from the third quarter 2009 average.
Results of Operations
Operating results by segment are as follows (in millions). The 2008 actual results include Grant
Prideco operations from the acquisition date of April 21, 2008:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 2,000 | $ | 1,926 | $ | 6,116 | $ | 5,440 | ||||||||
Petroleum Services & Supplies |
882 | 1,310 | 2,809 | 3,264 | ||||||||||||
Distribution Services |
306 | 498 | 1,019 | 1,289 | ||||||||||||
Elimination |
(101 | ) | (123 | ) | (366 | ) | (372 | ) | ||||||||
Total Revenue |
$ | 3,087 | $ | 3,611 | $ | 9,578 | $ | 9,621 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology (a) |
$ | 577 | $ | 501 | $ | 1,717 | $ | 1,413 | ||||||||
Petroleum Services & Supplies (b) (c) |
82 | 302 | 195 | 718 | ||||||||||||
Distribution Services |
7 | 43 | 42 | 87 | ||||||||||||
Unallocated expenses and
eliminations (d) |
(54 | ) | (56 | ) | (228 | ) | (152 | ) | ||||||||
Transaction and restructuring costs |
(11 | ) | | (19 | ) | (16 | ) | |||||||||
Total Operating Profit |
$ | 601 | $ | 790 | $ | 1,707 | $ | 2,050 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology (a) |
28.9 | % | 26.0 | % | 28.1 | % | 26.0 | % | ||||||||
Petroleum Services & Supplies (b) (c) |
9.3 | % | 23.0 | % | 6.9 | % | 22.0 | % | ||||||||
Distribution Services |
2.3 | % | 8.8 | % | 4.1 | % | 6.8 | % | ||||||||
Total Operating Profit % |
19.5 | % | 21.9 | % | 17.8 | % | 21.3 | % |
(a) | Under purchase accounting related to 2009 acquisitions, a fair value step up adjustment of $4 million was made to inventory and is being charged to Cost of revenue as the applicable inventory is sold. Cost of revenue includes $2 million and $4 million of these inventory charges for the three and nine months ended September 30, 2009, respectively. | |
(b) | The Company recorded a $147 million impairment charge to other indefinite-lived intangible assets during the nine months ended September 30, 2009. | |
Under purchase accounting related to 2009 acquisitions, a fair value step up adjustment of $4 million was made to inventory and is being charged to Cost of revenue as the applicable inventory is sold. Cost of revenue includes $4 million of these inventory charges for both the three and nine months ended September 30, 2009. | ||
(c) | Under purchase accounting related to the 2008 Grant Prideco acquisition, a fair value step up adjustment of $89 million was made to inventory and is being charged to Cost of revenue as the applicable inventory is sold. Cost of revenue includes $28 million and $74 million of these inventory charges for the three and nine months ended September 30, 2008. | |
(e) | Included in the nine months ended September 30, 2009 is a $46 million charge, recorded in the second quarter of 2009, related to its Voluntary Early Retirement Program. |
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Rig Technology
Three Months Ended September 30, 2009 and 2008. Rig Technology revenue in the third quarter of
2009 was $2,000 million, an increase of $74 million compared to the same period in 2008. Backlog
was $7.3 billion, down 37.8% from the same period last year. Revenue out of backlog increased
17.3%, offset by a 28.9% decrease in non-backlog revenue from the prior year period reflecting a
continued decrease in capital spending by North American land drillers and pressure pumpers.
Operating profit from Rig Technology was $577 million for the third quarter ended September 30,
2009, an increase of $76 million (15.2%) over the same period of 2008. Operating profit percentage
increased to 28.9%, up from 26.0% for the same prior year period
primarily due to revising cost estimates on large rig projects as a
result of favorable pricing from vendors.
Nine Months Ended September 30, 2009 and 2008. Revenue for the first nine months of 2009 was $6,116
million, an increase of $676 million (12.4%) compared to the same period in 2008. Revenue out of
backlog increased 23.2% offset by a 13.2% decrease in non-backlog revenue from the prior year
period, largely due to lower spare parts and small capital equipment sales.
Operating profit for the first nine months of 2009 was $1,717 million, an increase of $304 million
(21.5%) over the same period of 2008. Operating profit percentage increased to 28.1%, up from
26.0% for the same prior year period primarily driven by lower commodity prices and improved
manufacturing efficiencies.
Petroleum Services & Supplies
Three Months Ended September 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was
$882 million for the third quarter of 2009 compared to $1,310 million for the third quarter of
2008, a decrease of $428 million (32.7%). The decrease was primarily attributable to the decline
in North American rig count activity and weaker than usual Canadian winter drilling activity
rebound, with average rig utilization at 25% for the third quarter of 2009.
Operating profit from Petroleum Services & Supplies was $82 million for the third quarter of 2009
compared to $302 million for the same period in 2008, a decrease of $220 million (72.8%), and
operating profit percentage decreased to 9.3% down from 23.0% in the same period of 2008.
Decremental operating profit is a result of the dramatic decline in drilling activity beginning in
late third quarter 2008. North American rig count has decreased 52% since September 2008, and 50%
since December 2008.
Nine Months Ended September 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was
$2,809 million for the first nine months of 2009 compared to $3,264 million for the first nine
months of 2008, a decrease of $455 million (13.9%). The decrease was primarily attributable to a
43% decline in North American average rig count activity during the first nine months of 2009 over
the comparable 2008 period, partially offset by contributions from Grant Prideco which was acquired
on April 21, 2008.
Operating profit from Petroleum Services & Supplies was $195 million for the first nine months of
2009 compared to $718 million for the same period in 2008, a decrease of $523 million (72.8%).
Operating profit percentage decreased to 6.9% down from 22.0% in the same prior year period. The
primary reason for the decrease is due to a $147 million impairment charge on the carrying value of
a trade name associated with this segment in the second quarter of 2009. (See Note 4 to the
consolidated financial statements). In addition, the decrease was largely due to reduced North
American rig count activity combined with strong price competition; however, this was partly offset
by lower inflationary costs, particularly steel, labor and fuel. The decrease in operating profit
was also partially offset by contributions from Grant Prideco which was acquired on April 21, 2008.
Distribution Services
Three Months Ended September 30, 2009 and 2008. Revenue from Distribution Services was $306
million, a decrease of $192 million (38.6%) during the third quarter of 2009 over the comparable
2008 period. The number of drilling rigs actively searching for oil and gas is a key metric for
this business segment. North America sales declined 47% as a result of the 50% decline in the
average North American rig count for the third quarter of 2009 compared to the third quarter of
2008.
Operating profit of $7 million for the third quarter of 2009 decreased $36 million over the
comparable period in 2008. Operating profit percentage decreased to 2.3%, from 8.8% for the same
prior year period as a result of reduced North American drilling activity.
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Nine Months Ended September 30, 2009 and 2008. Revenue from Distribution Services was $1,019
million, a decrease of $270 million (20.9%) during the first nine months of 2009 over the
comparable 2008 period. The decrease in revenue is mainly concentrated in the North American region
as average drilling activity declined 43% for the first nine months of 2009 over the comparable
2008 period. However, international revenues increased 17% over the same period in 2008 due to
increased US exports and further development of the new RigStore business that provides innovative
supply chain solutions to install, staff and manage supply stores on offshore drilling rigs.
Operating profit of $42 million in the first nine months of 2009 decreased $45 million over the
comparable period in 2008. Operating profit percentage decreased to 4.1%, from 6.8% for the same
prior year period as a result of strong price competition and volume reductions as North American
rig activity continues to decline.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $54 million and $228 for the three and nine months ended
September 30, 2009, respectively, compared to $56 million and $152 million for the same periods in
2008. The decrease for the three months comparison is primarily due to lower administration costs
resulting from the voluntary retirement program adopted in the second quarter of 2009. The
increase for the nine months comparison is a result of the charge taken related to the voluntary
retirement program adopted in the second quarter of 2009.
Transaction and restructuring costs
Transaction costs were $11 million and $19 million for the three and nine months ending September
30, 2009, respectively. The transaction costs related primarily to restructuring costs and costs associated with
recent acquisitions.
Interest and financial costs
Interest and financial costs were $14 million and $40 million for the three and nine months ended
September 30, 2009, respectively, compared to $19 million and $53 million for the same periods in 2008. The
primary reasons for the decrease in interest and financial costs were a direct result of the
repayment of borrowings on the Companys credit facility used to purchase Grant Prideco, the
repayment of the Companys 7.5% Senior Notes and the repayment of a portion of the Companys 6.125%
Senior Notes. These repayments occurred during 2008 causing lower debt levels in 2009.
Other income (expense), net
Other income (expense), net was expense, net of $13 million and $87 million for the three and nine
months ended September 30, 2009 compared to income, net of $15 million and $14 million for the same
periods in 2008. The increase in other expense was mainly due to foreign exchange losses in 2009
as a result of unfavorable exchange rate movements in 2009, primarily related to the weakening of
the U.S. dollar.
Provision for income taxes
The
effective tax rate for the three and nine months ended September 30, 2009 was 33.2% and 33.7%,
respectively, compared to 32.3% and 33.9% for the same periods in 2008. The nine months 2009 tax
rate includes $21 million of additional tax provision recognized in the second quarter 2009 on
prior year income in Norway. These additional taxes resulted from foreign currency gains on
dollar-denominated accounts that were realized for Norwegian tax purposes. The Company expects its
income tax rate to be in the 32% to 33% range for the remainder of the year.
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Liquidity and Capital Resources
Overview
At September 30, 2009, the Company had cash and cash equivalents of $3,192 million, and total debt
of $884 million. At December 31, 2008, cash and cash equivalents were $1,543 million and total debt
was $874 million. A 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. The Companys outstanding
debt at September 30, 2009 consisted of $200 million of 5.65% Senior Notes due 2012, $200 million
of 7.25% Senior Notes due 2011, $150 million of 6.5% Senior Notes due 2011, $150 million of 5.5%
Senior Notes due 2012, $151 million of 6.125% Senior Notes due 2015, and other debt of $33 million.
The Company had $2,234 million of additional outstanding letters of credit at September 30, 2009,
primarily in Norway, that are essentially under various bilateral committed letter of credit
facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior
Notes contain reporting covenants and the credit facility contains a financial covenant regarding
maximum debt to capitalization. We were in compliance with all covenants at September 30, 2009.
There were no borrowings against the Companys unsecured credit facilities, and there were $589
million in outstanding letters of credit issued under such facilities, resulting in $1,411 million
of funds available under the Companys unsecured revolving credit facilities at September 30, 2009.
Operating Activities
For the first nine months of 2009, cash provided by operating activities increased $263 million to
$1,969 million compared to cash provided by operating activities of $1,706 million in the same
period of 2008. Before changes in operating assets and liabilities, net of acquisitions, cash was
provided by operations primarily through net income of $1,082 million plus non-cash charges of
$511 million and dividends from unconsolidated affiliates of $86 million less $45 million in equity
income from the Companys unconsolidated affiliate. Net changes in operating assets and
liabilities, net of acquisitions, contributed another $335 million in cash provided by operating
activities, a $306 million increase from the same period in 2008.
Investing Activities
For the first nine months of 2009, cash used in investing activities was $319 million compared to
cash used in investing of $2,339 million for the same period of 2008. The primary reason for the
decrease in cash used in investing activities for the first nine months of 2009 related to a
decrease in size of business acquisitions, net of cash acquired, to approximately $392 million
compared to $2,988 million used in the same period of 2008 which included the purchase of the
business and operating assets of Grant Prideco, offset by the approximately $801 million received
related to the disposition of certain Grant Prideco tubular businesses. In addition, the Company
used $186 million for capital expenditures in the first nine months of 2009, compared to $264
million for the same period in 2008.
Financing Activities
For the first nine months of 2009, cash used in financing activities was $25 million compared to
cash provided by financing activities of $568 million for the same period of 2008. The cash used in
financing activities for the first nine months of 2009 related to $35 million cash payments on debt
primarily acquired in the second quarter 2009 acquisitions, offset by cash proceeds from borrowings
in the amount of $7 million and exercised stock options in the amount of $3 million. The
borrowings and payments of debt in the first nine months of 2008 primarily relates to the financing
of the Grant Prideco acquisition. For the first nine months of 2009, the Company used its cash on
hand to fund its acquisitions.
The effect of the change in exchange rates on cash flows was a positive $24 million and a negative
$12 million for the nine months ended September 30, 2009 and 2008, respectively.
The Companys cash balance as of September 30, 2009 was $3,192 million. 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 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
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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 February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position
(FSP) SFAS 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2), which defers the
effective date of SFAS No. 157, Fair Value Measurements (SFAS 157), as it related to
non-financial assets and non-financial liabilities, to fiscal years beginning after November 15,
2008 and interim periods within those fiscal years. Both standards mentioned above were primarily
codified into ASC Topic 820, Fair Value Measurements and Disclosures (ASC Topic 820). The
Company, as of January 1, 2009, adopted the provisions of this statement and included the
appropriate disclosures surrounding non-financial assets and liabilities, as applicable.
In December 2007, the FASB issued SFAS No. 141R, Business Combinations (SFAS 141R), which was
primarily codified into ASC Topic 850, Business Combinations (ASC Topic 850). ASC Topic 850
provides revised guidance on how acquirers recognize and measure the consideration transferred,
identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired
in a business combination. ASC Topic 850 also expands required disclosures surrounding the nature
and financial effects of business combinations. ASC Topic 850 is effective, on a prospective basis,
for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC
Topic 850. The Company expects that this new standard will impact certain aspects of its
accounting for business combinations on a prospective basis, including the determination of fair
values assigned to certain purchased assets and liabilities.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial
Statements (SFAS 160), which was primarily codified into ASC Topic 810, Consolidations (ASC
Topic 810). ASC Topic 810 establishes requirements for ownership interests in subsidiaries held by
parties other than the Company (previously called minority interests) be clearly identified,
presented, and disclosed in the consolidated statement of financial position within equity, but
separate from the parents equity. All changes in the parents ownership interests are required to
be accounted for consistently as equity transactions and any noncontrolling equity investments in
deconsolidated subsidiaries must be measured initially at fair value. ASC Topic 810 is effective,
on a prospective basis, for fiscal years beginning after December 15, 2008. However, presentation
and disclosure requirements must be retrospectively applied to comparative financial statements. On
January 1, 2009, the Company adopted ASC Topic 810, and reclassified noncontrolling interests in
the amounts of $109 million and $96 million from the mezzanine section to equity in the September
30, 2009 and December 31, 2008 balance sheets, respectively.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement No. 133 (SFAS 161), which was primarily codified
into ASC Topic 815, Derivatives and Hedging (ASC Topic 815). ASC Topic 815 amends and expands
the disclosure requirements for derivative instruments and hedging activities, with the intent to
provide users of financial statements with an enhanced understanding of how and why an entity uses
derivative instruments, how derivative instruments and related hedged items are accounted for, and
how derivative instruments and related hedged items affect an entitys financial statements. ASC
Topic 815 is effective for fiscal years and interim periods beginning after November 15, 2008. On
January 1, 2009, the Company adopted ASC Topic 815. See Note 11. Derivative Financial
Instruments, in the notes to the consolidated financial statements.
In April 2008, the FASB issued FASB Staff Position (FSP) SFAS 142-3, Determination of the Useful
Life of Intangible Assets (FSP SFAS 142-3), which was primarily codified into ASC Topic 350,
Intangibles Goodwill and Other (ASC Topic 350). ASC Topic 350 amends the factors that should
be considered in developing renewal or extension assumptions used to determine the useful life of a
recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets.
The objective of this ASC is to improve the consistency between the useful life of a recognized
intangible asset under Statement No. 142 and the period of expected cash flows used to measure the
fair value of the asset under SFAS 141R and other U.S. GAAP principles. ASC Topic 350 is effective
for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC
Topic 350. There was no significant impact to the Companys consolidated financial statements from
the adoption of ASC Topic 350.
In April 2009 the FASB issued FSP 141R-1, Accounting for Assets Acquired and Liabilities Assumed
in a Business Combination That Arise from Contingencies (FSP 141R-1), which was primarily
codified into ASC Topic 850, Business Combinations (ASC Topic 850). ASC Topic 850 amends the
provisions in SFAS 141R for the initial recognition and measurement, subsequent measurement and
accounting, and disclosures for assets and liabilities arising from contingencies in business
combinations. The ASC eliminates the distinction between contractual and non-contractual
contingencies, including the initial recognition and measurement criteria in SFAS 141R and instead
carries forward most of the provisions in SFAS 141 for acquired contingencies. ASC Topic 850 is
effective for contingent assets and contingent liabilities acquired in business
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combinations for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. The Company expects ASC Topic 850 will
have a future impact on its consolidated financial statements, but the nature and magnitude of the
specific effects will depend upon the nature, term and size of the acquired contingencies.
In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments (FSP SFAS 107-1), which was primarily codified into ASC Topic 825,
Financial Instruments (ASC Topic 825). ASC Topic 825 extends the disclosure requirements
regarding the fair value of financial instruments under SFAS No. 107, Disclosures about Fair Value
of Financial Instruments (SFAS No. 107), to interim financial statements of publicly traded
companies. ASC Topic 825 is effective for interim reporting periods ending after June 15, 2009,
with early adoption permitted for periods ending after March 15, 2009. Early adoption of this ASC
is permitted only if the entity also elects to early adopt FSP SFAS 157-4 and FSP SFAS 115-2. On
June 1, 2009, the Company adopted ASC Topic 825. There was no significant impact to the Companys
consolidated financial statements from the adoption of ASC Topic 825.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS 165), which was primarily
codified into ASC Topic 855, Subsequent Events (ASC Topic 855). ASC Topic 855 requires the
disclosure of the date through which an entity has evaluated subsequent events and the basis for
that date. ASC Topic 855 is effective for fiscal years and interim periods ending after June 15,
2009. On June 1, 2009, the Company adopted ASC Topic 855. There was no significant impact to the
Companys consolidated financial statements from the adoption of ASC Topic 855.
In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the
Hierarchy of Generally Accepted Accounting Principles (SFAS 168), which amends SFAS 162, The
Hierarchy of Generally Accepted Accounting Principles. Both of these standards were primarily
codified into ASC Topic 105, Generally Accepted Accounting Standards (ASC Topic 105). The ASC
will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal
securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date,
ASC Topic 105 will supersede all then-existing non-SEC accounting and reporting standards. All
other non-grandfathered non-SEC accounting literature not included in the ASC will become
non-authoritative. ASC Topic 105 is effective for financial statements issued for interim and
annual periods ending after September 15, 2009.
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, 2008,
which address additional factors that could cause our actual results to differ from those set forth
in the forward-looking statements. Given these uncertainties, current or prospective investors are
cautioned not to place undue reliance on any such forward-looking statements. We undertake no
obligation to update any such factors or forward-looking statements to reflect future events or
developments.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to changes in foreign currency exchange rates and interest rates. Additional
information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these
operations are exposed to changes in foreign currency exchange rates, although such fluctuations
generally do not affect income since their functional currency is typically the local currency.
These operations also have net assets and liabilities not denominated in the functional currency,
which exposes us to changes in foreign currency exchange rates that do impact income. We recorded a
foreign exchange loss in our income statement of approximately $62 million in the first nine months
of 2009, compared to a $30 million foreign currency gain in the same period of the prior year.
The gain/losses are primarily due to exchange rate fluctuations related to monetary asset balances
denominated in currencies other than the functional currency and adjustments to our hedged
positions as a result of the current economic environment. Strengthening of currencies against
the U.S. dollar may create losses in future periods to the extent we maintain net assets and
liabilities not denominated in the functional currency of the countries using the local currency as
their functional currency.
Some of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes
in foreign currency exchange rates impact our earnings to the extent that costs associated with
those U.S. dollar revenues are denominated in the local currency. Similarly some of our revenues
are denominated in foreign currencies, but have associated U.S. dollar costs, which also gives rise
to foreign currency exchange rate exposure. In order to mitigate that risk, we may utilize foreign
currency forward contracts to better match the currency of our revenues and associated costs. We do
not use foreign currency forward contracts for trading or speculative purposes.
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The following table details the Companys foreign currency exchange risk grouped by functional
currency and their expected maturity periods as of September 30, 2009 (in millions, except contract
rates):
As of September 30, 2009 | December 31, | |||||||||||||||||||
Functional Currency | 2009 | 2010 | 2011 | Total | 2008 | |||||||||||||||
CAD Buy USD/Sell CAD: |
||||||||||||||||||||
Notional amount to buy (in Canadian dollars) |
329 | 6 | | 335 | 527 | |||||||||||||||
Average CAD to USD contract rate |
1.1189 | 1.0966 | | 1.1185 | 1.1843 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
(9 | ) | | | (9 | ) | 14 | |||||||||||||
Sell USD/Buy CAD: |
||||||||||||||||||||
Notional amount to sell (in Canadian dollars) |
33 | 70 | | 103 | 241 | |||||||||||||||
Average CAD to USD contract rate |
1.0710 | 1.1109 | | 1.0977 | 1.1196 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
| 2 | | 2 | (18 | ) | ||||||||||||||
EUR Buy USD/Sell EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
89 | | | 89 | 11 | |||||||||||||||
Average USD to EUR contract rate |
1.4103 | | | 1.4103 | 1.4397 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
(4 | ) | | | (4 | ) | | |||||||||||||
Sell USD/Buy EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
37 | 67 | 1 | 105 | 245 | |||||||||||||||
Average USD to EUR contract rate |
1.3282 | 1.3633 | 1.4324 | 1.3515 | 1.3986 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
5 | 6 | | 11 | 1 | |||||||||||||||
GBP Buy USD/Sell GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds
Sterling) |
49 | | | 49 | | |||||||||||||||
Average USD to GBP contract rate |
1.6400 | | | 1.6400 | | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
2 | | | 2 | | |||||||||||||||
Sell USD/Buy GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds
Sterling) |
5 | 2 | | 7 | 34 | |||||||||||||||
Average USD to GBP contract rate |
1.5522 | 1.5313 | | 1.5458 | 1.5647 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
| | | | (4 | ) |
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Table of Contents
As of September 30, 2009 | December 31, | |||||||||||||||||||
Functional Currency | 2009 | 2010 | 2011 | Total | 2008 | |||||||||||||||
USD Buy DKK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
38 | 15 | | 53 | 47 | |||||||||||||||
Average DKK to USD contract rate |
5.2868 | 5.3982 | | 5.3197 | 5.4968 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
1 | 1 | | 2 | 2 | |||||||||||||||
Buy EUR/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
105 | 319 | 7 | 431 | 749 | |||||||||||||||
Average USD to EUR contract rate |
1.3108 | 1.4601 | 1.4033 | 1.4197 | 1.3791 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
12 | | | 12 | 14 | |||||||||||||||
Buy GBP/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
67 | 5 | | 72 | 108 | |||||||||||||||
Average USD to GBP contract rate |
1.5974 | 1.6282 | | 1.5995 | 1.5623 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
| | | | (8 | ) | ||||||||||||||
Buy NOK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
520 | 583 | 229 | 1,332 | 1,325 | |||||||||||||||
Average NOK to USD contract rate |
6.1156 | 6.4007 | 6.3896 | 6.2875 | 6.5338 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
24 | 50 | 17 | 91 | (101 | ) | ||||||||||||||
Sell DKK/Buy USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
19 | | | 19 | | |||||||||||||||
Average DKK to USD contract rate |
5.2541 | | | 5.2541 | | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
(1 | ) | | | (1 | ) | | |||||||||||||
Sell EUR/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
39 | 8 | 3 | 50 | 76 | |||||||||||||||
Average USD to EUR contract rate |
1.3838 | 1.3516 | 1.2715 | 1.3701 | 1.3777 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
(2 | ) | (1 | ) | (1 | ) | (4 | ) | (2 | ) | ||||||||||
Sell NOK/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
413 | 100 | | 513 | 589 | |||||||||||||||
Average NOK to USD contract rate |
6.0471 | 6.0440 | | 6.0470 | 5.8647 | |||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
(14 | ) | (3 | ) | | (17 | ) | 104 | ||||||||||||
Other Currencies |
||||||||||||||||||||
Fair Value at September 30, 2009 in U.S.
dollars |
| | 1 | 1 | | |||||||||||||||
Total Fair Value |
14 | 55 | 17 | 86 | 2 | |||||||||||||||
The Company had other financial market risk sensitive instruments denominated in foreign currencies
totaling $132 million as of September 30, 2009 excluding trade receivables and payables, which
approximate fair value. These market risk sensitive instruments consisted of cash balances and
overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable
foreign currency exchange rates on these other financial market risk sensitive instruments could
affect net income by $9 million.
The counterparties to forward contracts are major financial institutions. The credit ratings and
concentration of risk of these financial institutions are monitored on a continuing basis. In the
event that the counterparties fail to meet the terms of a foreign currency contract, our exposure
is limited to the foreign currency rate differential.
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Table of Contents
Interest Rate Risk
At September 30, 2009 our long term borrowings consisted of $150 million in 6.5% Senior Notes, $200
million in 7.25% Senior Notes, $200 million in 5.65% Senior Notes, $150 million in 5.5% Senior
Notes and $151 million in 6.125% Senior Notes. We occasionally have borrowings under our other
credit facilities, 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 facilities, 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 6 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.
37
Table of Contents
PART II OTHER INFORMATION
Item 6. Exhibits
Reference is hereby made to the Exhibit Index commencing on page 39.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: November 6, 2009 | By: /s/ Clay C. Williams | |||
Clay C. Williams | ||||
Executive Vice President and Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer) | ||||
38
Table of Contents
INDEX TO EXHIBITS
(a) Exhibits
2.1
|
Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 between National-Oilwell, Inc. and Varco International, Inc. (4). | |
2.2
|
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (8). | |
3.1
|
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1). | |
3.2
|
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (9). | |
10.1
|
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2). | |
10.2
|
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2). | |
10.3
|
Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3). | |
10.4
|
National Oilwell Varco Long-Term Incentive Plan (5)*. | |
10.5
|
Form of Employee Stock Option Agreement (Exhibit 10.1) (6). | |
10.6
|
Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (6). | |
10.7
|
Form of Performance-Based Restricted Stock (18 Month) Agreement (Exhibit 10.1) (7). | |
10.8
|
Form of Performance-Based Restricted Stock (36 Month) Agreement (Exhibit 10.2) (7). | |
10.9
|
Five-Year Credit Agreement, dated as of April 21, 2008, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacities as Administrative Agent, Co-Lead Arranger and Joint Book Runner, DnB Nor Bank ASA, as Co-Lead Arranger and Joint Book Runner, and Fortis Capital Corp., The Bank of Nova Scotia and The Bank of Tokyo Mitsubishi UFJ, Ltd., as Co-Documentation Agents. (Exhibit 10.1) (10). | |
10.10
|
First Amendment to Employment Agreement dated as of December 22, 2008 between Merrill A. Miller, Jr. and National Oilwell Varco (Exhibit 10.1) (11). | |
10.11
|
Second Amendment to Executive Agreement, dated as of December 22, 2008, of Clay Williams and National Oilwell Varco (Exhibit 10.2) (11). | |
10.12
|
First Amendment to Employment Agreement dated as of December 22, 2008 between Mark A. Reese and National Oilwell Varco (Exhibit 10.3) (11). | |
10.13
|
First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco (Exhibit 10.4) (11). | |
10.14
|
Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco (Exhibit 10.5) (11). | |
10.15
|
First Amendment to National Oilwell Varco Long-Term Incentive Plan (12)*. | |
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 |
39
Table of Contents
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 interim period ended September 30, 2009 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. (13). |
* | Compensatory plan or arrangement for management or others | |
(1) | Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 11, 2000. | |
(2) | Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002. | |
(3) | Filed as an Exhibit to Varco International, Inc.s Quarterly Report on Form 10-Q filed on May 6, 2004. | |
(4) | Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004. | |
(5) | Filed as Annex D to our Amendment No. 1 to Registration Statement on Form S-4 filed on January 31, 2005. | |
(6) | Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006. | |
(7) | Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007. | |
(8) | Filed as Annex A to our Registration Statement on Form S-4 filed on January 28, 2008. | |
(9) | Filed as an Exhibit to our Current Report on Form 8-K filed on February 21, 2008. | |
(10) | Filed as an Exhibit to our Current Report on Form 8-K filed on April 22, 2008. | |
(11) | Filed as an Exhibit to our Current Report on Form 8-K filed on December 23, 2008. | |
(12) | Filed as Appendix I to our Proxy Statement filed on April 1, 2009. | |
(13) | 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.
40