NOV Inc. - Quarter Report: 2009 June (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 JUNE 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 of incorporation or organization) |
(I.R.S. Employer Identification No.) |
7909 Parkwood Circle Drive
Houston, Texas
77036-6565
Houston, Texas
77036-6565
(Address of principal executive offices)
(713) 346-7500
(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 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 August 3, 2009 the registrant had 418,199,258 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)
June 30, | December 31, | |||||||
2009 | 2008 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 2,286 | $ | 1,543 | ||||
Receivables, net |
2,603 | 3,136 | ||||||
Inventories, net |
3,825 | 3,806 | ||||||
Costs in excess of billings |
590 | 618 | ||||||
Deferred income taxes |
215 | 271 | ||||||
Prepaid and other current assets |
391 | 283 | ||||||
Total current assets |
9,910 | 9,657 | ||||||
Property, plant and equipment, net |
1,758 | 1,677 | ||||||
Deferred income taxes |
195 | 126 | ||||||
Goodwill |
5,466 | 5,225 | ||||||
Intangibles, net |
4,134 | 4,300 | ||||||
Investment in unconsolidated affiliate |
387 | 421 | ||||||
Other assets |
89 | 73 | ||||||
Total assets |
$ | 21,939 | $ | 21,479 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 760 | $ | 852 | ||||
Accrued liabilities |
2,082 | 2,376 | ||||||
Billings in excess of costs |
2,081 | 2,161 | ||||||
Current portion of long-term debt and short-term borrowings |
8 | 4 | ||||||
Accrued income taxes |
236 | 230 | ||||||
Total current liabilities |
5,167 | 5,623 | ||||||
Long-term debt |
873 | 870 | ||||||
Deferred income taxes |
2,150 | 2,134 | ||||||
Other liabilities |
144 | 128 | ||||||
Total liabilities |
8,334 | 8,755 | ||||||
Commitments and contingencies |
||||||||
Stockholders equity: |
||||||||
Common stock par value $.01; 418,192,372 and 417,350,924 shares issued
and outstanding at June 30, 2009 and December 31, 2008 |
4 | 4 | ||||||
Additional paid-in capital |
8,027 | 7,989 | ||||||
Accumulated other comprehensive loss |
| (161 | ) | |||||
Retained earnings |
5,486 | 4,796 | ||||||
Total Company stockholders equity |
13,517 | 12,628 | ||||||
Noncontrolling interests |
88 | 96 | ||||||
Total stockholders equity |
13,605 | 12,724 | ||||||
Total liabilities and stockholders equity |
$ | 21,939 | $ | 21,479 | ||||
See notes to unaudited consolidated financial statements.
2
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(In millions, except per share data)
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(In millions, except per share data)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenue |
$ | 3,010 | $ | 3,325 | $ | 6,491 | $ | 6,010 | ||||||||
Cost of revenue |
2,135 | 2,344 | 4,577 | 4,232 | ||||||||||||
Gross profit |
875 | 981 | 1,914 | 1,778 | ||||||||||||
Selling, general and administrative |
334 | 274 | 653 | 502 | ||||||||||||
Intangible asset impairment |
147 | | 147 | | ||||||||||||
Transaction costs |
8 | 16 | 8 | 16 | ||||||||||||
Operating profit |
386 | 691 | 1,106 | 1,260 | ||||||||||||
Interest and financial costs |
(13 | ) | (24 | ) | (26 | ) | (34 | ) | ||||||||
Interest income |
2 | 10 | 4 | 26 | ||||||||||||
Equity income in unconsolidated affiliate |
16 | 17 | 44 | 17 | ||||||||||||
Other income (expense), net |
(38 | ) | (14 | ) | (74 | ) | (1 | ) | ||||||||
Income before income taxes |
353 | 680 | 1,054 | 1,268 | ||||||||||||
Provision for income taxes |
131 | 255 | 359 | 443 | ||||||||||||
Net income |
222 | 425 | 695 | 825 | ||||||||||||
Net income attributable to noncontrolling interests |
2 | 4 | 5 | 6 | ||||||||||||
Net income attributable to Company |
$ | 220 | $ | 421 | $ | 690 | $ | 819 | ||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 0.53 | $ | 1.05 | $ | 1.66 | $ | 2.16 | ||||||||
Diluted |
$ | 0.53 | $ | 1.04 | $ | 1.65 | $ | 2.15 | ||||||||
Weighted average shares outstanding: |
||||||||||||||||
Basic |
416 | 402 | 416 | 379 | ||||||||||||
Diluted |
418 | 404 | 417 | 381 | ||||||||||||
See notes to unaudited consolidated financial statements.
3
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In millions)
Six Months Ended | ||||||||
June 30, | ||||||||
2009 | 2008 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 695 | $ | 825 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
238 | 168 | ||||||
Excess tax benefit from exercise of stock options |
| (36 | ) | |||||
Equity income in unconsolidated affiliate |
(44 | ) | (17 | ) | ||||
Dividend from unconsolidated affiliate |
86 | | ||||||
Intangible asset impairment |
147 | | ||||||
Other |
(5 | ) | 43 | |||||
Change in operating assets and liabilities, net of acquisitions: |
||||||||
Receivables |
590 | (507 | ) | |||||
Inventories |
75 | (297 | ) | |||||
Costs in excess of billings |
28 | 38 | ||||||
Prepaid and other current assets |
(108 | ) | 74 | |||||
Accounts payable |
(152 | ) | 22 | |||||
Billings in excess of costs |
(80 | ) | 556 | |||||
Other assets/liabilities, net |
(185 | ) | 375 | |||||
Net cash provided by operating activities |
1,285 | 1,244 | ||||||
Cash flows from investing activities: |
||||||||
Purchases of property, plant and equipment |
(143 | ) | (160 | ) | ||||
Business acquisitions, net of cash acquired |
(389 | ) | (2,945 | ) | ||||
Business divestitures, net of cash disposed |
| 784 | ||||||
Dividend from unconsolidated affiliate |
8 | 113 | ||||||
Other, net |
| (1 | ) | |||||
Net cash used in investing activities |
(524 | ) | (2,209 | ) | ||||
Cash flows from financing activities: |
||||||||
Borrowings against lines of credit and other debt |
| 2,577 | ||||||
Payments against lines of credit and other debt |
(34 | ) | (1,928 | ) | ||||
Proceeds from exercise of stock options |
1 | 77 | ||||||
Excess tax benefit from exercise of stock options |
| 36 | ||||||
Net cash provided by (used in) financing activities |
(33 | ) | 762 | |||||
Effect of exchange rates on cash |
15 | 13 | ||||||
Increase in cash equivalents |
743 | (190 | ) | |||||
Cash and cash equivalents, beginning of period |
1,543 | 1,842 | ||||||
Cash and cash equivalents, end of period |
$ | 2,286 | $ | 1,652 | ||||
Supplemental disclosures of cash flow information: |
||||||||
Cash payments during the period for: |
||||||||
Interest |
$ | 27 | $ | 30 | ||||
Income taxes |
$ | 409 | $ | 376 |
See notes to unaudited consolidated financial statements.
4
Table of Contents
NATIONAL OILWELL VARCO, INC.
Notes to Consolidated Financial Statements (Unaudited)
Notes to Consolidated Financial Statements (Unaudited)
1. Basis of Presentation
The preparation of financial statements in conformity with generally accepted accounting principles
(GAAP) in the United States requires management to make estimates and assumptions that affect
reported and contingent amounts of assets and liabilities as of the date of the financial
statements and reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
The accompanying unaudited consolidated financial statements of National Oilwell Varco, Inc. (the
Company) present information in accordance with GAAP in the United States for interim financial
information and the instructions to Form 10-Q and applicable rules of Regulation S-X. They do not
include all information or footnotes required by GAAP in the United States for complete
consolidated financial statements and should be read in conjunction with our 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 six months ended June 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 August 7, 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 | ||
5
Table of Contents
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 six month periods ended June 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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Total revenues |
$ | 3,010 | $ | 3,444 | $ | 6,491 | $ | 6,613 | ||||||||
Net income attributable to Company |
$ | 220 | $ | 446 | $ | 690 | $ | 898 | ||||||||
Basic net income attributable to Company per share |
$ | 0.53 | $ | 1.08 | $ | 1.66 | $ | 2.17 | ||||||||
Diluted net income attributable to Company per
share |
$ | 0.53 | $ | 1.07 | $ | 1.65 | $ | 2.16 | ||||||||
6
Table of Contents
Other Acquisitions
In the three and six months ended June 30, 2009, the Company completed five acquisitions for an
aggregate purchase price of $389 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 following table summarizes the preliminary purchase price allocation of the assets acquired and
liabilities assumed at the date of acquisition of the 2009 acquisitions (in millions):
Total | ||||
Current assets, net of cash acquired |
$ | 213 | ||
Property, plant and equipment |
57 | |||
Intangible assets |
85 | |||
Goodwill |
198 | |||
Total assets acquired |
553 | |||
Current liabilities |
113 | |||
Long-term debt |
42 | |||
Other liabilities |
9 | |||
Total liabilities |
164 | |||
Cash consideration, net of cash acquired |
$ | 389 | ||
3. 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.
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 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.
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.
7
Table of Contents
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 next three years (2009, 2010, and 2011).
4. Inventories, net
Inventories consist of (in millions):
June 30, | December 31, | |||||||
2009 | 2008 | |||||||
Raw materials and supplies |
$ | 782 | $ | 739 | ||||
Work in process |
1,507 | 1,326 | ||||||
Finished goods and purchased
products |
1,536 | 1,741 | ||||||
Total |
$ | 3,825 | $ | 3,806 | ||||
5. Accrued Liabilities
Accrued liabilities consist of (in millions):
June 30, | December 31, | |||||||
2009 | 2008 | |||||||
Compensation |
$ | 185 | $ | 258 | ||||
Customer prepayments and
billings |
547 | 912 | ||||||
Warranty |
162 | 114 | ||||||
Interest |
12 | 11 | ||||||
Taxes (non income) |
57 | 76 | ||||||
Insurance |
56 | 50 | ||||||
Accrued purchase orders |
743 | 688 | ||||||
Fair value of derivatives |
83 | 59 | ||||||
Other |
237 | 208 | ||||||
Total |
$ | 2,082 | $ | 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. 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 |
75 | |||
Amounts incurred |
(29 | ) | ||
Foreign currency translation |
2 | |||
Balance, June 30, 2009 |
$ | 162 | ||
8
Table of Contents
6. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
June 30, | December 31, | |||||||
2009 | 2008 | |||||||
Costs incurred on uncompleted contracts |
$ | 5,734 | $ | 4,776 | ||||
Estimated earnings |
2,987 | 2,277 | ||||||
8,721 | 7,053 | |||||||
Less: Billings to date |
10,212 | 8,596 | ||||||
$ | (1,491 | ) | $ | (1,543 | ) | |||
Costs and estimated earnings in excess of
billings on
uncompleted contracts |
$ | 590 | $ | 618 | ||||
Billings in excess of costs and estimated
earnings on
uncompleted contracts |
(2,081 | ) | (2,161 | ) | ||||
$ | (1,491 | ) | $ | (1,543 | ) | |||
7. Comprehensive Income
The components of comprehensive income are as follows (in millions):
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Net income |
$ | 222 | $ | 425 | $ | 695 | $ | 825 | ||||||||
Currency translation adjustments, net of tax |
112 | 11 | 57 | 38 | ||||||||||||
Changes in derivative financial instruments, net
of tax |
83 | | 105 | 21 | ||||||||||||
Changes in defined benefit plans, net of tax |
(1 | ) | 1 | (1 | ) | | ||||||||||
Comprehensive income |
416 | 437 | 856 | 884 | ||||||||||||
Comprehensive income attributable to
noncontrolling interest |
2 | 4 | 5 | 6 | ||||||||||||
Comprehensive income attributable to Company |
$ | 414 | $ | 433 | $ | 851 | $ | 878 | ||||||||
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. For the three months ended June
30, 2009, a majority of these local currencies strengthened against the U.S. dollar resulting in a
net increase to Other Comprehensive Income of $112 million (net of tax of $60 million) upon the
translation of their financial statements from their local currency to the U.S. dollar.
The effect of changes in the exchange rates for 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 currency rates for open derivatives and
the outflow of accumulated Other Comprehensive Income on previously matured derivatives. The
accumulated effects of these scenarios have caused an increase in Other Comprehensive Income of $83
million (net of tax of $30 million) for the three months ended
June 30, 2009.
9
Table of Contents
8. 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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 1,917 | $ | 1,911 | $ | 4,116 | $ | 3,514 | ||||||||
Petroleum Services & Supplies |
913 | 1,124 | 1,927 | 1,954 | ||||||||||||
Distribution Services |
305 | 425 | 713 | 791 | ||||||||||||
Elimination |
(125 | ) | (135 | ) | (265 | ) | (249 | ) | ||||||||
Total Revenue |
$ | 3,010 | $ | 3,325 | $ | 6,491 | $ | 6,010 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology (a) |
$ | 534 | $ | 506 | $ | 1,140 | $ | 912 | ||||||||
Petroleum
Services & Supplies (b)(c) |
(51 | ) | 221 | 113 | 416 | |||||||||||
Distribution Services |
10 | 25 | 35 | 44 | ||||||||||||
Unallocated expenses and
eliminations (d) |
(99 | ) | (45 | ) | (174 | ) | (96 | ) | ||||||||
Transaction costs |
(8 | ) | (16 | ) | (8 | ) | (16 | ) | ||||||||
Total Operating Profit |
$ | 386 | $ | 691 | $ | 1,106 | $ | 1,260 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology (a) |
27.9 | % | 26.5 | % | 27.7 | % | 26.0 | % | ||||||||
Petroleum
Services & Supplies (b)(c) |
(5.6 | %) | 19.7 | % | 5.9 | % | 21.3 | % | ||||||||
Distribution Services |
3.3 | % | 5.8 | % | 4.9 | % | 5.5 | % | ||||||||
Total Operating Profit % |
12.8 | % | 20.8 | % | 17.0 | % | 21.0 | % |
(a) | Under purchase accounting related to 2009 acquisitions, a fair value step up adjustment of $5 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 of these inventory charges for both the three and six months ended June 30, 2009. | |
(b) | The Company recorded a $147 million impairment charge to other indefinite-lived intangible assets during the three and six months ended June 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 $46 million of these inventory charges for the three and six months ended June 30, 2008. | |
(d) | The Company recorded a $46 million charge related to its Voluntary Early Retirement Program for the three and six months ended June 30, 2009. |
The Company had revenues of 15.6% of total revenue from one of its customers
for the six months ended June 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. There were no customers
that represented 10% or greater of total revenue for the six months ended June 30, 2008.
10
Table of Contents
9. Debt
Debt consists of (in millions):
June 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 |
23 | 14 | ||||||
Total debt |
881 | 874 | ||||||
Less current portion |
8 | 4 | ||||||
Long-term debt |
$ | 873 | $ | 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 June 30, 2009, there were no borrowings against these facilities, and there were $636 million in
outstanding letters of credit issued under these facilities, resulting in $1,364 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 $2,414 million of additional outstanding letters of credit at June 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 June 30, 2009.
Other
Other debt includes approximately $5 million in promissory notes due to former owners of businesses
acquired.
11
Table of Contents
10. Tax
The effective tax rate for the three and six months ended June 30, 2009 was 37.3% and 34.1%,
respectively, compared to 37.5% and 34.9% for the same periods in 2008.
The second quarter 2009 tax rate, which was higher than periods preceding this
quarter, was primarily affected by $21 million of additional tax provisions recognized in the period 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 return to the 32% to 33% range for the remainder of the year.
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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Federal income tax at U.S. federal
statutory rate |
$ | 124 | $ | 238 | $ | 369 | $ | 444 | ||||||||
Foreign income tax rate differential |
(26 | ) | (23 | ) | (58 | ) | (43 | ) | ||||||||
State income tax, net of federal benefit |
2 | 11 | 8 | 17 | ||||||||||||
Foreign dividends, net of foreign tax
credits |
6 | 33 | 7 | 35 | ||||||||||||
Benefit of U.S. Manufacturing Deduction |
(3 | ) | (3 | ) | (7 | ) | (5 | ) | ||||||||
Nondeductible expenses |
4 | 2 | 12 | 5 | ||||||||||||
Prior year tax on revaluation gains in Norway |
21 | | 21 | | ||||||||||||
Other |
3 | (3 | ) | 7 | (10 | ) | ||||||||||
Provision for income taxes |
$ | 131 | $ | 255 | $ | 359 | $ | 443 | ||||||||
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). FIN 48 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 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, 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 for tax positions of prior years |
3 | |||
Settlements |
(11 | ) | ||
Balance at June 30, 2009 |
$ | 53 | ||
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 2003 and outside the U.S. for tax years ending
after 2001.
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.
11. 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 quarter, the Company with approval from shareholders increased the
number of shares authorized under the Plan from 15 million to 26 million. As of June 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 $31 million for the three and six
months ended June 30, 2009, respectively, and $16 million and $29 million for the three and six
months ended June 30, 2008, respectively. The total income tax benefit recognized in the
Consolidated Statements of Income for all stock-based
12
Table of Contents
compensation arrangements under the Plan was
$7 million and $12 million for the three and six months
ended June 30, 2009, respectively, and $7 million and $11 million for the three and six months ended
June 30, 2008, respectively.
During the six months ended June 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.
12. 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 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.
In accordance with SFAS 133 the Company records all derivative financial instruments at their fair
value in our consolidated balance sheet. Except for certain non-designated hedges discussed below,
all derivative financial instruments we hold are designated as either cash flow or fair value
hedges and are highly effective in offsetting movements in the underlying risks. Such arrangements
typically have terms between two and 24 months, but may have longer terms depending on the
underlying cash flows being hedged, typically related to the projects in our backlog. We may also
use interest rate contracts to mitigate our exposure to changes in interest rates on anticipated
long-term debt issuances.
At June 30, 2009, the Company has
determined that its financial assets of $114 million and liabilities of $95 million (primarily
currency related derivatives) are level 2 in the fair value hierarchy. At June 30, 2009, the fair
value of the Companys foreign currency forward contracts totaled $16 million.
As of June 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
13
Table of Contents
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 June 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 |
£ | 47 | ||
Danish Krone |
DKK | 197 | ||
Euro |
| 279 | ||
Norwegian Krone |
NOK | 7,717 | ||
U.S. Dollar |
$ | 181 |
Fair Value Hedging Strategy
For derivative instruments that are designated and qualify as a fair value hedge (i.e., hedging the
exposure to changes in the fair value of an asset or a liability or an identified portion thereof
that is subject to a particular risk), the gain or loss on the derivative instrument as well as the
offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the
same line item associated with the hedged item in current earnings (e.g., in revenue when the
hedged item is a contracted sale).
The Company enters into forward exchange contracts to hedge certain firm commitments of revenue and
costs that are denominated in currencies other than the functional currency of the operating unit.
The purpose of the Companys foreign currency hedging activities is to protect the Company from
risk that the eventual U.S. dollar-equivalent cash flows from the sale of products to customers
will be adversely affected by changes in the exchange rates.
As of June 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) | ||||
Korean Won |
KRW | 1,917 | ||
U.S. Dollar |
$ | 64 |
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.
14
Table of Contents
As of June 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
|
£ | 2 | ||
Danish Krone |
DKK | 15 | ||
Euro
|
| 150 | ||
Norwegian Krone | NOK | 2,280 | ||
Swedish Krone |
SEK | 5 | ||
U.S. Dollar
|
$ | 67 |
As of June 30, 2009, the Company has the following fair values of its derivative instruments and
their balance sheet classifications (in millions):
June 30, 2009 | ||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||
Location | Value | Location | Value | |||||||||
Derivatives designated as hedging
instruments under SFAS 133 |
||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 63 | Accrued liabilities | $ | 37 | ||||||
Foreign exchange contracts |
Other Assets | 11 | Other Liabilities | 11 | ||||||||
Total derivatives designated as
hedging
instruments under SFAS 133 |
$ | 74 | $ | 48 | ||||||||
Derivatives not designated as
hedging
instruments under SFAS 133 |
||||||||||||
Foreign exchange contracts |
Prepaid and other current assets | $ | 34 | Accrued liabilities | $ | 46 | ||||||
Foreign exchange contracts |
Other Assets | 3 | Other Liabilities | 1 | ||||||||
Total derivatives not designated as
hedging instruments under SFAS 133 |
$ | 37 | $ | 47 | ||||||||
Total derivatives |
$ | 111 | $ | 95 | ||||||||
15
Table of Contents
The Effect of Derivative Instruments on the Consolidated Statement of Income
Periods Ended June 30, 2009
($ in millions)
Periods Ended June 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 SFAS 133 | 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) | |||||||||||||||||||||||||||
June 30, 2009 | June 30, 2009 | June 30, 2009 | ||||||||||||||||||||||||||||||
Three Months Ended |
Six Months Ended |
Three Months Ended |
Six Months Ended |
Three Months Ended |
Six Months Ended |
|||||||||||||||||||||||||||
Foreign exchange contracts |
70 | 74 | Revenue | 11 | 10 | Other income (expense), net |
(18 | ) | (24 | ) | ||||||||||||||||||||||
Foreign exchange contracts |
| | Cost of revenue | (16 | ) | (44 | ) | |||||||||||||||||||||||||
Total |
70 | 74 | (5 | ) | (34 | ) | (18 | ) | (24 | ) | ||||||||||||||||||||||
Derivatives in SFAS 133 | Location of Gain (Loss) | Amount of Gain (Loss) | SFAS 133 | 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 | |||||||||||||||||||||||
June 30, 2009 | June 30, 2009 | |||||||||||||||||||||||||||
Three Months Ended |
Six Months Ended |
Three Months Ended |
Six Months Ended |
|||||||||||||||||||||||||
Foreign exchange contracts |
Revenue | 4 | (2 | ) | Firm commitments | Revenue | (4 | ) | 2 | |||||||||||||||||||
Foreign exchange contracts |
Cost of revenue | | (1 | ) | Firm commitments | Cost of revenue | | 1 | ||||||||||||||||||||
Total |
4 | (3 | ) | (4 | ) | 3 | ||||||||||||||||||||||
Derivatives Not Designated as | Location of Gain (Loss) | Amount of Gain (Loss) | ||||||||||
Hedging Instruments under | Recognized in Income | Recognized in Income on | ||||||||||
SFAS 133 | on Derivative | Derivative (a) | ||||||||||
Foreign exchange contracts |
Other income (expense), net | 46 | 26 | |||||||||
Total |
46 | 26 | ||||||||||
(a) | The Company expects that $(38) 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 $(18) million and $(27) million related to the ineffective portion of the hedging relationships for the three and six months ended June 30, 2009, respectively, and nil and $3 million related to the amount excluded from the assessment of the hedge effectiveness for the three and six months ended June 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. 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 $23 million
remains to be recognized into earnings at June 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 June 30, 2009, our Norway operations had derivatives with $2,709 million in
notional value with a fair value asset of $33 million.
16
Table of Contents
13. 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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Numerator: |
||||||||||||||||
Net income attributable to Company |
$ | 220 | $ | 421 | $ | 690 | $ | 819 | ||||||||
Denominator: |
||||||||||||||||
Basicweighted average common shares outstanding |
416 | 402 | 416 | 379 | ||||||||||||
Dilutive effect of employee stock options and other
unvested
stock awards |
2 | 2 | 1 | 2 | ||||||||||||
Diluted outstanding shares |
418 | 404 | 417 | 381 | ||||||||||||
Net income attributable to Company per share: |
||||||||||||||||
Basic |
$ | 0.53 | $ | 1.05 | $ | 1.66 | $ | 2.16 | ||||||||
Diluted |
$ | 0.53 | $ | 1.04 | $ | 1.65 | $ | 2.15 | ||||||||
In addition, the Company had stock options outstanding that were anti-dilutive totaling 4 million
and 10 million shares for the three and six months ended
June 30, 2009, respectively, and 1 million
shares for both the three and six months ended June 30, 2008, respectively.
14. 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. 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). SFAS 141R
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. SFAS 141R also expands required disclosures surrounding the nature and
financial effects of business combinations. SFAS 141R is effective, on a prospective basis, for
fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted SFAS 141R.
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). SFAS 160 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. SFAS 160 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.
17
Table of Contents
On January 1, 2009, the Company adopted SFAS 160, and
reclassified noncontrolling interests in the amounts of $88 million and $96 million from the
mezzanine section to equity in the June 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). SFAS 161 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. SFAS
161 is effective for fiscal years and interim periods beginning after November 15, 2008. On January
1, 2009, the Company adopted SFAS 161. 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). FSP SFAS 142-3 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 FSP 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. FSP SFAS 142-3 is effective
for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted FSP
SFAS 142-3. There was no significant impact to the Companys consolidated financial statements
from the adoption of FSP SFAS 142-3.
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). FSP 141R-1 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 FSP 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. FSP 141R-1 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 FSP 141R-1 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). FSP SFAS 107-1 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. FSP SFAS 107-1 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 FSP
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 FSP SFAS 107-1. There was no significant impact to the Companys
consolidated financial statements from the adoption of FSP SFAS 107-1.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS 165). SFAS 165 requires the
disclosure of the date through which an entity has evaluated subsequent events and the basis for
that date. SFAS 165 is effective for fiscal years and interim periods ending after June 15, 2009.
On June 1, 2009, the Company adopted SFAS 165. There was no significant impact to the Companys
consolidated financial statements from the adoption of SFAS 165.
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. SFAS 168 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, SFAS 168 will supersede all
then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC
accounting literature not included in SFAS 168 will become non-authoritative. SFAS 168 is
effective for financial statements issued for interim and annual periods ending after September 15,
2009. The Company is currently assessing the impact SFAS 168 will have on its financial
statements, but does not expect a significant impact from adoption of the pronouncement.
18
Table of Contents
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.
19
Table of Contents
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 June 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 quarter and six months ended June 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 SFAS 142.
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 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.
20
Table of Contents
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 next three years (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 next three years (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 next three years (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.
21
Table of Contents
EXECUTIVE SUMMARY
National Oilwell Varco generated earnings of $220 million or $0.53 per fully diluted share in its
second quarter ended June 30, 2009, on revenues of $3,010 million. Compared to the second quarter
of 2008, revenue declined nine percent and net income attributable to the Company declined 48
percent, and compared to the first quarter of 2009, revenue declined 14 percent and net income
attributable to the Company declined 53 percent. These declines were due to lower market activity,
the effect of asset impairment, transaction, and voluntary retirement charges, and a higher income
tax rate recognized in the second quarter of 2009 that did not occur in the prior periods.
During the
second quarter of 2009, the Company recognized a $147 million pre-tax, or $0.23 per share
after-tax, impairment charge on its carrying value of an intangible trade name acquired in its
Grant Prideco acquisition. During the second quarter the Company retested all its carrying values
for goodwill and intangible assets, which was performed due to deterioration seen in the rig count
and performance of certain of its business units compared to forecasts. Additionally, the Company
recognized $56 million in pre-tax charges ($0.09 per share after-tax) related to acquisitions made
in the quarter, and the results of a voluntary retirement program offered to its long-tenured
employees. Legal, due diligence and other costs associated with acquisitions that were previously
capitalized under GAAP are now expensed under FAS141R. The Companys voluntary retirement program
charge was $46 million, consisting of separation and accrued medical benefits and options vesting
charges, and is expected to result in annual savings of approximately $33 million per year. Second
quarter 2009 net income was also affected by an income tax rate of 37 percent, higher than periods
preceding this quarter, due to $21 million of additional tax
provisions recognized in the period 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 effective income
tax rate to return to the 32 percent to 33 percent range for the remainder of the year.
Operating profit was $386 million or 12.8 percent of sales for the second quarter. Excluding the
impairment, transaction, and voluntary retirement charges, second quarter operating profit was $589
million or 19.6 percent of sales, compared to $720 million or 20.7 percent of sales in the first
quarter of 2009, and $778 million or 22.6 percent of sales in the second quarter of 2008 (excluding
transaction charges and including a full quarter contribution from the Grant Prideco acquisition in
the second quarter of 2008).
Grant Prideco Acquisition
On April 21, 2008 the Company completed its acquisition of Grant Prideco, Inc. for a combination of
approximately $3.0 billion in cash and the issuance of 56.9 million shares of National Oilwell
Varco common stock. The Grant Prideco merger further strengthened National Oilwell Varcos
position as manufacturer to the oilfield. Its drill bits and reamers have been integrated into the
Companys offering of drilling motors, non-magnetic drill collars, jars and shock tools, to
complement its comprehensive package of bottomhole assembly tools used to drill complex wellpaths.
Additionally, Grant Pridecos drillpipe products are purchased and consumed by the Companys
existing drilling contractor customer base. The Company believes that consumption of drillpipe per
foot of hole drilled, or per rig running, has been increasing due to the rising complexity of
wellpath designs. Overall the acquisition better positioned National Oilwell Varco to capitalize
on continued application of horizontal, directional and extended-reach drilling, through both
drillpipe and drill bit product sales. Integration of the business has proceeded well. The
Company is introducing new drillpipe tracking products, and expanding OEM drillpipe repair and
maintenance offerings through its worldwide network of pipe service operations. The Company is
also consolidating a number of bit and downhole tool sales facilities worldwide, and leveraging
combined manufacturing and marketing capabilities.
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 $43 per barrel range during the first quarter of 2009. Higher oil and
gas prices over the past several years have led to high levels of exploration and development
drilling in many oil and gas basins around the globe, but this slowed sharply with falling oil and
gas prices. 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 has decreased to 943 rigs as of July 24, 2009. Many oil and gas operators reliant on external
financing to fund their drilling programs are curtailing their drilling activity. So far this
22
Table of Contents
appears to be having 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 is showing some modest declines nonetheless, falling from its September 2008 peak of 1,108 to
967 in June 2009. During the second 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.
The industry responded by launching many new rig construction projects since 2005, to retool the
existing fleet of jackup rigs (according to ODS, 74 percent of the existing 446 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 $8.7 billion by June 30, 2009.
The land rig backlog comprised 12 percent and equipment destined for offshore operations comprised
88 percent of the total backlog as of June 30, 2009. Equipment destined for international markets
totaled 92 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 second quarter of 2009, the Company removed $108
million in orders on which its customers had defaulted, and booked a gain of $16 million related to
down payments and progress billings it had received. 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 $320 million of projects in its June 30, 2009 backlog that it considers
at risk.
Segment Performance
Rig Technology generated $1,917 million in revenue and
$536 million in operating profit in the
second quarter of 2009, yielding a record operating margin for the segment of 28.0 percent
(excluding transaction and voluntary retirement charges). The segment generated 25
percent operating leverage or flowthrough (the decrease in operating profit divided by the decrease
in revenue) on 13 percent lower revenue from the first quarter of 2009, and posted $30 million
higher operating profit on $7 million higher revenues when compared to the second quarter of 2008.
Revenue out of backlog of $1,434 million declined 15 percent sequentially and increased seven
percent compared to the second quarter of last year. As of June 30, 2009 the scheduled outflow of
revenue from backlog is expected to be in the range of $2.5 billion for the remainder of 2009, $4.7
billion in 2010, and $1.5 billion for 2011. From 2005 through the current quarter, the segment has
delivered a total of 59 newly built offshore rig packages. Aftermarket spare parts and services revenue,
and sales of smaller capital items which do not qualify for the backlog, declined five percent from
the first quarter of 2009. Demand for rigs and equipment is strongest in Brazil, the Middle East, Mexico,
and the North Sea (for platform cranes and winches). Additionally, we are seeing rising interest
for equipment for Iraq and China, and completed a workover rig sale into Russia during the second
quarter. Generally, demand for equipment in North America is very
slow; although the Companys
first new Drake rig delivered into the Marcellus shale play is performing well.
23
Table of Contents
The Petroleum Services & Supplies segment generated revenues of $913 million and operating profit
of $96 million or 10.5 percent of sales in the second quarter of 2009 (excluding impairment,
transaction, and voluntary retirement charges). Revenues declined 10 percent from the first
quarter of 2009 and 27 percent from the second quarter of 2008 (on a combined adjusted basis for a
full quarter contribution from Grant Prideco). Decremental operating
leverage was 67 percent from
the first quarter of 2009 and 60 percent from the second quarter of 2008. Excluding the impact of
acquisitions made during the second quarter revenues fell 13 percent sequentially, and decremental
operating leverage was 55 percent. The business faced very challenging market conditions and lower
pricing in the second quarter, particularly in North America, where U.S. rig counts fell 29 percent
and Canadian rig counts fell 73 percent from the first quarter
of 2009. Pricing fell as much as 30 percent
to 40 percent across some product lines, although the discounts varied widely depending upon
product and region. Consumable products sales were down sharply as drilling contractors
cannibalized idle equipment from stacked rigs, rather than place orders with the Company, as they
reduced operating and capital expenditures in view of lower rig dayrates. International markets
held up better, with pricing down 5 to 20 percent as the rig count declined four percent
sequentially. Nevertheless, the group posted 9 percent sequential international sales gains, half
of which was due to acquisitions. Sales and rentals of downhole tools and bits, composite pipe,
and coiled tubing saw large double-digit percent declines, while other products were down only
modestly from the first quarter to the second. Virtually all products and services posted
sequential drops in North America, which declined to less than half of the groups mix during the
second quarter in the aggregate. Drillpipe sales were roughly flat sequentially, but margins
improved on a better mix of premium high-torque pipe and lower costs.
Distribution Services segment revenues were $305 million during the second quarter of 2009, a
decrease of 25 percent from the first quarter of 2009 and a decrease of 28 percent from the second
quarter of 2008. Sequential decremental operating leverage was 15 percent, and year-over-year
operating leverage was 13 percent on the revenue declines, higher than the segment has typically
experienced due to pricing pressure accompanying the volume declines. Pricing for the groups
North American operation declined two to three percent from the first quarter. The group has
successfully increased its international presence to about a third of its sales over the past few
years, but it still remains dependent on North America for a majority of its business. The softer
year-over-year and sequential results are a result of the considerably softer market conditions
seen in North America during the second quarter of 2009, which declined 31 percent in sales from
the first quarter of 2009. Nevertheless diligent attention to costs and efficiency enabled the
group to post 3.3 percent operating margins in the second quarter, excluding voluntary retirement
charges. The group continues to expand store coverage of emerging Marcellus, Haynesville, and
South Texas Eagle Ford shale plays, while also expanding its presence in Brazil, Mexico, and
Central Asia.
Outlook
The serious credit market crisis, global recession, and lower commodity prices are presenting
challenging prospects to our business. Consequently we remain cautious in our outlook for the
remainder of 2009, and believe we will see orders for new rigs fall in 2009 (although we are
nevertheless optimistic that drilling contractors will place orders for new build floating rigs
during the year for the Brazilian deepwater market). Drilling activity, particularly by
independent gas producers reliant on external financing, has fallen sharply and we do not know when
it will recover.
Our outlook for the Companys Petroleum Services & Supplies segment and Distribution Services
segment remains guarded. We expect revenues for Petroleum Services & Supplies to fall slightly,
and revenues for Distribution Services to rise slightly in the third quarter of 2009, and margins
for both to remain approximately stable, as cost reduction initiatives offset continued pricing
pressure. We do not foresee a meaningful recovery in gas drilling in North America this year, but
believe the likelihood for such a recovery rises in 2010 and 2011 as gas production is expected to
begin to decline and/or recent lower demand is expected to recover. Our outlook for international markets, which are more driven by national oil
company activity, are historically less volatile and expected to see better market conditions. The
Rig Technology segment is expected to be less affected by the downturn due to the strength of its
backlog.
The Company believes it is nevertheless well positioned to manage through this uncertain period,
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
downturn. 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.
24
Table of Contents
Operating Environment Overview
The Companys results are dependent on, among other things, the level of worldwide oil and gas drilling, well remediation activity, the prices of crude oil and natural gas, capital spending by other oilfield service companies and drilling contractors, pipeline maintenance activity, and worldwide oil and gas inventory levels. Key industry indicators for the second quarter of 2009 and 2008, and the first quarter of 2009 include the following:
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 second quarter of 2009 and 2008, and the first quarter of 2009 include the following:
% | % | |||||||||||||||||||
2Q09 v | 2Q09 v | |||||||||||||||||||
2Q09* | 2Q08* | 1Q09* | 2Q08 | 1Q09 | ||||||||||||||||
Active Drilling Rigs: |
||||||||||||||||||||
U.S. |
936 | 1,864 | 1,326 | (49.8 | %) | (29.4 | %) | |||||||||||||
Canada |
90 | 169 | 329 | (46.7 | %) | (72.6 | %) | |||||||||||||
International |
983 | 1,084 | 1,026 | (9.3 | %) | (4.2 | %) | |||||||||||||
Worldwide |
2,009 | 3,117 | 2,681 | (35.5 | %) | (25.1 | %) | |||||||||||||
West Texas Intermediate Crude Prices (per barrel) |
$ | 59.44 | $ | 124.05 | $ | 42.91 | (52.1 | %) | 38.5 | % | ||||||||||
Natural Gas Prices ($/mmbtu) |
$ | 3.71 | $ | 11.38 | $ | 4.57 | (67.4 | %) | (18.8 | %) |
* | Averages for the quarters indicated. See sources below. |
The following table details the U.S., Canadian, and international rig activity and West Texas
Intermediate Oil prices for the past nine quarters ended June 30, 2009 on a quarterly basis:
![(BAR GRAPH)](https://www.sec.gov/Archives/edgar/data/0001021860/000095012309032328/h67433h6743301.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).
25
Table of Contents
The worldwide and U.S. quarterly average rig count decreased 36% (from 3,117 to 2,009) and 50%
(from 1,864 to 936), respectively, in the second quarter of 2009 compared to the second quarter of
2008. The average per barrel price of West Texas Intermediate Crude decreased 52% (from $124.05
per barrel to $59.44 per barrel) and natural gas prices decreased 67% (from $11.38 per mmbtu to
$3.71 per mmbtu) in the second quarter of 2009 compared to the second quarter of 2008.
U.S. rig activity at July 24, 2009 was 943 rigs compared to the second quarter average of 936 rigs.
The price for West Texas Intermediate Crude was at $66.96 per barrel as of July 24, 2009,
increasing 13% from the second 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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 1,917 | $ | 1,911 | $ | 4,116 | $ | 3,514 | ||||||||
Petroleum Services & Supplies |
913 | 1,124 | 1,927 | 1,954 | ||||||||||||
Distribution Services |
305 | 425 | 713 | 791 | ||||||||||||
Elimination |
(125 | ) | (135 | ) | (265 | ) | (249 | ) | ||||||||
Total Revenue |
$ | 3,010 | $ | 3,325 | $ | 6,491 | $ | 6,010 | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology (a) |
$ | 534 | $ | 506 | $ | 1,140 | $ | 912 | ||||||||
Petroleum
Services & Supplies (b)(c) |
(51 | ) | 221 | 113 | 416 | |||||||||||
Distribution Services |
10 | 25 | 35 | 44 | ||||||||||||
Unallocated expenses and
eliminations (d) |
(99 | ) | (45 | ) | (174 | ) | (96 | ) | ||||||||
Transaction costs |
(8 | ) | (16 | ) | (8 | ) | (16 | ) | ||||||||
Total Operating Profit |
$ | 386 | $ | 691 | $ | 1,106 | $ | 1,260 | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology (a) |
27.9 | % | 26.5 | % | 27.7 | % | 26.0 | % | ||||||||
Petroleum
Services & Supplies (b)(c) |
(5.6 | %) | 19.7 | % | 5.9 | % | 21.3 | % | ||||||||
Distribution Services |
3.3 | % | 5.8 | % | 4.9 | % | 5.5 | % | ||||||||
Total Operating Profit % |
12.8 | % | 20.8 | % | 17.0 | % | 21.0 | % |
(a) | Under purchase accounting related to 2009 acquisitions, a fair value step up adjustment of $5 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 of these inventory charges for both the three and six months ended June 30, 2009. | |
(b) | The Company recorded a $147 million impairment charge to other indefinite-lived intangible assets during the three and six months ended June 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 $46 million of these inventory charges for the three and six months ended June 30, 2008. | |
(d) | The Company recorded a $46 million charge related to its Voluntary Early Retirement Program for the three and six months ended June 30, 2009. |
Rig Technology
Three Months Ended June 30, 2009 and 2008. Rig Technology revenue in the second quarter of 2009
was $1,917 million, an increase of $6 million compared to the same period in 2008. Backlog was
$8.7 billion, down 19.5% from the same period last
year. Revenue out of backlog increased 7.2%, offset by a 15.6% 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 $534 million for the second quarter ended June 30, 2009,
an increase of $28 million (5.5%) over the same period of 2008. Operating profit percentage
increased to 27.9%, up from 26.5% for the same prior year period primarily driven by a $16 million
gain from a payment received on cancelled rig package.
26
Table of Contents
Six Months Ended June 30, 2009 and 2008. Revenue for the first half of 2009 was $4,116 million, an
increase of $602 million (17.1%) compared to the same period in 2008. Revenue out of backlog
increased 26.4% offset by a 4.8% 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 six months of 2009 was $1,140 million, an increase of $228 million
(25.0%) over the same period of 2008. Operating profit percentage increased to 27.7%, 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 June 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was $913
million for the second quarter of 2009 compared to $1,124 million for the second quarter of 2008, a
decrease of $211 million (18.8%). The decrease was primarily attributable to continued decline in
North American rig count activity as well as an unusually severe Canada seasonal break-up with
average rig utilization at 11% for the second quarter of 2009.
Operating (loss) profit from Petroleum Services & Supplies was $(51) million for the second quarter
of 2009 compared to $221 million for the same period in 2008, a decrease of $272 million (123.1%),
and operating profit percentage decreased to (5.6%) down from 19.7% in the same period of 2008.
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. (See Note 3. for further detail). In
addition, 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 58% since September
2008, and 52% since December 2008.
Six Months Ended June 30, 2009 and 2008. Revenue from Petroleum Services & Supplies was $1,927
million for the first six months of 2009 compared to $1,954 million for the first six months of
2008, a decrease of $27 million (1.4%). The decrease was primarily attributable to a 38% decline
in North American average rig count activity during the first half 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 $113 million for the first half of 2009
compared to $416 million for the same period in 2008, a decrease of $303 million (72.8%). Operating
profit percentage decreased to 5.9% down from 21.3% 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. (See Note 3. for further detail). 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 June 30, 2009 and 2008. Revenue from Distribution Services was $305 million, a
decrease of $120 million (28.2%) during the second 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. U.S. sales declined 45%, less than average North American rig count decline of 50% for the
second quarter of 2009 over the comparable period in 2008.
Operating profit of $10 million in the second quarter of 2009 decreased
$15 million from the second
quarter of 2008. Operating profit percentage decreased to 3.3%, from 5.8% for the same prior year
period as a result of reduced North American drilling activity.
Six Months Ended June 30, 2009 and 2008. Revenue from Distribution Services was $713 million, a
decrease of $78 million (9.9%) during the first half of 2009 over the comparable 2008 period. The
decrease in revenue is mainly concentrated in the North American region as average drilling
activity declined 38% for the first half of 2009 over the comparable 2008 period. However,
international revenues increased 25% over the same period in 2008 as a result of improved strategic
alliances with drilling contractors and the success of the RigStore initiative that provides
innovative supply chain solutions to install, staff and manage supply stores on offshore drilling
rigs.
Operating profit of $35 million in the first six months of 2009 decreased $9 million over the first
six months of 2008. Operating profit percentage decreased to 4.9%, from 5.5% for the same prior
year period as a result of strong price competition and volume declines as North American rig
activity continues to decline.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $99 million and $174 for the three and six months ended
June 30, 2009, respectively, compared to $45 million and $96 million for the same periods in 2008.
This increase is primarily due to greater
27
Table of Contents
intercompany profit elimination related to sales between
the segments. In addition, voluntary retirement costs were $46 million for the three and six months
ending June 30, 2009 and were comprised of $39 million in severance and $7 million in stock based
compensation.
Transaction costs
Transaction costs were $8 million for both the three and six months ending June 30, 2009. The
transaction costs related to restructuring and other costs due to recent acquisitions. Transaction
costs of $16 million for the three and six months ended June 30, 2008 were comprised of
$6 million for accelerated vesting of stock-based compensation, $4 million for bridge loan
fees, and $6 million related to transaction costs for the disposition of certain tubular businesses
of Grant Prideco in May 2008.
Interest and financial costs
Interest and financial costs were $13 million and $26 million for the three and six months ended
June 30, 2009, compared to $24 million and $34 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 $38 million and $74 million for the three and six
months ended June 30, 2009 compared to expense, net of $14 million and $1 million for the same
periods in 2008. This is mainly due to an increase in foreign exchange charges and a decrease in
interest income for the three and six months ending June 30, 2009.
Provision for income taxes
The effective tax rate for the three and six months ended June 30, 2009 was 37.3% and 34.1%,
respectively, compared to 37.5% and 34.9% for the same periods in 2008.
The second quarter 2009 tax rate, which was higher than periods preceding this quarter, was primarily affected by
$21 million of additional tax provisions recognized in the period 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 return to the 32% to 33% range for the remainder of the year.
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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Federal income tax at U.S. federal
statutory rate |
$ | 124 | $ | 238 | $ | 369 | $ | 444 | ||||||||
Foreign income tax rate differential |
(26 | ) | (23 | ) | (58 | ) | (43 | ) | ||||||||
State income tax, net of federal benefit |
2 | 11 | 8 | 17 | ||||||||||||
Foreign dividends, net of foreign tax
credits |
6 | 33 | 7 | 35 | ||||||||||||
Benefit of U.S. Manufacturing Deduction |
(3 | ) | (3 | ) | (7 | ) | (5 | ) | ||||||||
Nondeductible expenses |
4 | 2 | 12 | 5 | ||||||||||||
Prior year tax on revaluation gains in Norway |
21 | | 21 | | ||||||||||||
Other |
3 | (3 | ) | 7 | (10 | ) | ||||||||||
Provision for income taxes |
$ | 131 | $ | 255 | $ | 359 | $ | 443 | ||||||||
28
Table of Contents
Liquidity and Capital Resources
Overview
At June 30, 2009, the Company had cash and cash equivalents of $2,286 million, and total debt of
$881 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 June 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 $30 million.
The Company had $2,414 million of additional outstanding letters of credit at June 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 June 30, 2009.
There were no borrowings against the Companys unsecured credit facilities, and there were $636
million in outstanding letters of credit issued under such facilities, resulting in $1,364 million
of funds available under the Companys unsecured revolving credit facilities at June 30, 2009.
Operating Activities
For the first six months of 2009, cash provided by operating activities increased $41 million to
$1,285 million compared to cash provided by operating activities of $1,244 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 $695 million plus non-cash charges of
$385 million and dividends from unconsolidated affiliates of $86 million less $44 million in equity
income from the Companys unconsolidated affiliate. Net changes in operating assets and
liabilities, net of acquisitions, contributed another $168 million in cash provided by operating
activities, a $93 million decrease from the same period in 2008. The decrease is primarily due to
lower receivables, inventory and accounts payable.
Investing Activities
For the first six months of 2009, cash used in investing activities was $524 million compared to
cash used in investing of $2,209 million for the same period of 2008. The primary reason for the
decrease in cash used in investing activities for the first six months of 2009 related to a
decrease in size of business acquisitions, net of cash acquired, to approximately $389 million
compared to $2,945 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 $784 million received
related to the disposition of certain Grant Prideco tubular businesses. In addition, the Company
decreased its capital expenditures for the first six months of 2009
by $17 million, received
$19 million less in dividends from its unconsolidated affiliate compared to the same period in
2008 and included $86 million of the dividends from
unconsolidated affiliate received in 2009 in operating activities.
Financing Activities
For the first six months of 2009, cash used in financing activities was $33 million compared to
cash provided by financing activities of $762 million for the same period of 2008. The cash used in
financing activities for the first six months of 2009 related to $34 million cash payments on debt
primarily acquired in the second quarter 2009 acquisitions, offset by cash proceeds from exercised stock options in the amount of $1 million. The borrowings
and payments of debt in the first six months of 2008 primarily relates to the financing of the
Grand Prideco acquisition. For the first six 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 $15 million and $13 million
for the six months ended June 30, 2009 and 2008, respectively.
The Companys cash balance as of June 30, 2009 was $2,286 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 also believe any significant increases in capital
expenditures caused by any need to increase manufacturing capacity can be funded from operations or
through debt financing.
29
Table of Contents
We intend to pursue additional acquisition candidates, but the timing, size or success of any
acquisition effort and the related potential capital commitments cannot be predicted. We expect to
fund future cash acquisitions primarily with cash flow from operations and borrowings, including
the unborrowed portion of the credit facility or new debt issuances, but may also issue additional
equity either directly or in connection with acquisitions. There can be no assurance that
additional financing for acquisitions will be available at terms acceptable to us.
Recently Issued Accounting Standards
In 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.
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). SFAS 141R
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. SFAS 141R also expands required disclosures surrounding the nature and
financial effects of business combinations. SFAS 141R is effective, on a prospective basis, for
fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted SFAS 141R.
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). SFAS 160 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. SFAS 160 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 SFAS 160, and reclassified noncontrolling
interests in the amounts of $88 million and $96 million from the mezzanine section to equity in the
June 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). SFAS 161 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. SFAS
161 is effective for fiscal years and interim periods beginning after November 15, 2008. On January
1, 2009, the Company adopted SFAS 161. 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). FSP SFAS 142-3 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 FSP 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. FSP SFAS 142-3 is effective
for fiscal years beginning after December 15, 2008. On January 1, 2009, the Company adopted FSP
SFAS 142-3. There was no significant impact to the Companys consolidated financial statements
from the adoption of FSP SFAS 142-3.
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). FSP 141R-1 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 FSP 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. FSP 141R-1 is
effective for contingent assets and contingent liabilities
30
Table of Contents
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 FSP
141R-1 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). FSP SFAS 107-1 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. FSP SFAS 107-1 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 FSP
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 FSP SFAS 107-1. There was no significant impact to the Companys
consolidated financial statements from the adoption of FSP SFAS 107-1.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS 165). SFAS 165 requires the
disclosure of the date through which an entity has evaluated subsequent events and the basis for
that date. SFAS 165 is effective for fiscal years and interim periods ending after June 15, 2009.
On June 1, 2009, the Company adopted SFAS 165. There was no significant impact to the Companys
consolidated financial statements from the adoption of SFAS 165.
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. SFAS 168 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, SFAS 168 will supersede all
then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC
accounting literature not included in SFAS 168 will become non-authoritative. SFAS 168 is
effective for financial statements issued for interim and annual periods ending after September 15,
2009. The Company is currently assessing the impact SFAS 168 will have on its financial
statements, but does not expect a significant impact from adoption of the pronouncement.
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.
31
Table of Contents
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to changes in foreign currency exchange rates and interest rates. Additional
information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these
operations are exposed to changes in foreign currency exchange rates, although such fluctuations
generally do not affect income since their functional currency is typically the local currency.
These operations also have net assets and liabilities not denominated in the functional currency,
which exposes us to changes in foreign currency exchange rates that do impact income. We recorded a
foreign exchange loss in our income statement of approximately
$56 million in the first six
months of 2009, compared to a $7 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.
The following table details the Companys foreign currency exchange risk grouped by functional
currency and their expected maturity periods as of June 30, 2009 (in millions, except contract
rates):
As of June 30, 2009 | December 31, | |||||||||||||||||||
Functional Currency | 2009 | 2010 | 2011 | Total | 2008 | |||||||||||||||
CAD Buy USD/Sell CAD: |
||||||||||||||||||||
Notional amount to buy (in Canadian dollars) |
323 | | | 323 | 527 | |||||||||||||||
Average CAD to USD contract rate |
1.2034 | | | 1.2034 | 1.1843 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
(11 | ) | | | (11 | ) | 14 | |||||||||||||
Sell USD/Buy CAD: |
||||||||||||||||||||
Notional amount to sell (in Canadian dollars) |
71 | 52 | | 123 | 241 | |||||||||||||||
Average CAD to USD contract rate |
1.0700 | 1.0961 | | 1.0809 | 1.1196 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
(5 | ) | (2 | ) | | (7 | ) | (18 | ) | |||||||||||
EUR Buy USD/Sell EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
66 | | | 66 | 11 | |||||||||||||||
Average USD to EUR contract rate |
1.3570 | | | 1.3570 | 1.4397 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
(3 | ) | | | (3 | ) | | |||||||||||||
Sell USD/Buy EUR: |
||||||||||||||||||||
Notional amount to buy (in euros) |
81 | 50 | 1 | 132 | 245 | |||||||||||||||
Average USD to EUR contract rate |
1.3846 | 1.3317 | 1.4431 | 1.3647 | 1.3986 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
2 | 4 | | 6 | 1 | |||||||||||||||
GBP Buy USD/Sell GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds Sterling) |
43 | | | 43 | | |||||||||||||||
Average USD to GBP contract rate |
1.5026 | | | 1.5026 | | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
(6 | ) | | | (6 | ) | |
32
Table of Contents
As of June 30, 2009 | December 31, | |||||||||||||||||||
Functional Currency | 2009 | 2010 | 2011 | Total | 2008 | |||||||||||||||
Sell USD/Buy GBP: |
||||||||||||||||||||
Notional amount to buy (in British Pounds Sterling) |
10 | 2 | | 12 | 34 | |||||||||||||||
Average USD to GBP contract rate |
1.5289 | 1.5313 | | 1.5293 | 1.5647 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
1 | | | 1 | (4 | ) | ||||||||||||||
USD Buy DKK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
35 | 10 | | 45 | 47 | |||||||||||||||
Average DKK to USD contract rate |
5.6200 | 5.4569 | | 5.5853 | 5.4968 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
2 | | | 2 | 2 | |||||||||||||||
Buy EUR/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
656 | 15 | 7 | 678 | 749 | |||||||||||||||
Average USD to EUR contract rate |
1.3578 | 1.3454 | 1.4033 | 1.3580 | 1.3791 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
23 | 1 | | 24 | 14 | |||||||||||||||
Buy GBP/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
84 | | | 84 | 108 | |||||||||||||||
Average USD to GBP contract rate |
1.4879 | | | 1.4879 | 1.5623 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
9 | | | 9 | (8 | ) | ||||||||||||||
Buy NOK/Sell USD: |
||||||||||||||||||||
Notional amount to buy (in U.S. dollars) |
639 | 504 | 156 | 1,299 | 1,325 | |||||||||||||||
Average NOK to USD contract rate |
6.3095 | 6.4452 | 6.4598 | 6.3802 | 6.5338 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
(15 | ) | (4 | ) | | (19 | ) | (101 | ) | |||||||||||
Sell EUR/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
144 | 4 | 3 | 151 | 76 | |||||||||||||||
Average USD to EUR contract rate |
1.3704 | 1.2981 | 1.2715 | 1.3657 | 1.3777 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
(4 | ) | | | (4 | ) | (2 | ) | ||||||||||||
Sell NOK/Buy USD: |
||||||||||||||||||||
Notional amount to sell (in U.S. dollars) |
442 | 99 | | 541 | 589 | |||||||||||||||
Average NOK to USD contract rate |
6.1562 | 6.0427 | | 6.1358 | 5.8647 | |||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
21 | 7 | | 28 | 104 | |||||||||||||||
Other Currencies |
||||||||||||||||||||
Fair Value at June 30, 2009 in U.S. dollars |
(1 | ) | (1 | ) | (2 | ) | (4 | ) | | |||||||||||
Total Fair Value |
13 | 5 | (2 | ) | 16 | 2 | ||||||||||||||
The Company had other financial market risk sensitive instruments denominated in foreign currencies
totaling $71 million as of June 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 $5 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.
33
Table of Contents
Interest Rate Risk
At June 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.
34
Table of Contents
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
The annual meeting of stockholders was held on May 13, 2009. Stockholders elected three directors
nominated by the board of directors for terms expiring in 2012 by the following votes: Merrill A.
Miller, Jr. 320,898,593 votes for, 34,321,668 votes against and 469,422 votes abstaining; Greg L.
Armstrong 322,772,904 votes for, 32,447,165 votes against and 469,614 votes abstaining; and David
D. Harrison 322,747,027 votes for, 32,468,059 votes against and 474,599 votes abstaining. There
were no nominees to office other than the directors elected.
A proposal to ratify the appointment of Ernst & Young LLP as the Companys independent auditors for
the fiscal year ending December 31, 2009 was voted on by the stockholders as follows: 351,767,214
votes for, 3,152,700 votes against and 773,277 votes abstaining.
A proposal to approve an amendment to the National Oilwell Varco, Inc. Long-Term Incentive Plan was
voted on by the stockholders as follows: 262,482,635 votes for, 50,278,092 votes against and
533,197 votes abstaining.
Item 6. Exhibits
Reference is hereby made to the Exhibit Index commencing on page 36.
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: August 7, 2009 | By: /s/ Clay C. Williams | |||
Clay C. Williams | ||||
Executive Vice President and Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer) |
35
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)*. |
36
Table of Contents
31.1
|
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended | |
31.2
|
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended | |
32.1
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101 |
The following materials from our Quarterly Report on Form 10-Q for the interim period ended June 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.
37