form10-q.htm
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
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(Mark One)
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R
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the Quarterly Period Ended June 30, 2011
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OR
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£
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission File Number 1-13884
Cameron International Corporation
(Exact Name of Registrant as Specified in its Charter)
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Delaware
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76-0451843
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(State or Other Jurisdiction of
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(I.R.S. Employer
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Incorporation or Organization)
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Identification No.)
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1333 West Loop South, Suite 1700, Houston, Texas
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77027
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(Address of Principal Executive Offices)
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(Zip Code)
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713/513-3300
(Registrant’s Telephone Number, Including Area Code)
N/A
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
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 R No £
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 R No £
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.
Large accelerated filer R Accelerated filer £
Non-accelerated filer £ (Do not check if a smaller reporting company) 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 £ No R
Number of shares outstanding of issuer’s common stock as of July 21, 2011 was 245,071,076.
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3
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3
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3
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4
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5
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6
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18
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37
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38
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38
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38
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39
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39
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39
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39
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40
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40
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41
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PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
CAMERON INTERNATIONAL CORPORATION
CONSOLIDATED CONDENSED RESULTS OF OPERATIONS
(dollars and shares in millions, except per share data)
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Three Months Ended
June 30,
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Six Months Ended
June 30,
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2011
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2011
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(unaudited)
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REVENUES
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$ |
1,741.1 |
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$ |
1,452.7 |
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$ |
3,242.3 |
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$ |
2,799.4 |
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COSTS AND EXPENSES
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Cost of sales (exclusive of depreciation and amortization shown separately below)
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1,213.4 |
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984.7 |
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2,271.2 |
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1,898.8 |
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Selling and administrative expenses
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250.5 |
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205.0 |
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480.3 |
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401.7 |
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Depreciation and amortization
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47.6 |
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52.9 |
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92.4 |
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101.0 |
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Interest, net
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22.1 |
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19.4 |
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42.2 |
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36.4 |
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Other costs (see Note 3)
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20.1 |
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18.4 |
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29.0 |
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28.7 |
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Total costs and expenses
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1,553.7 |
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1,280.4 |
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2,915.1 |
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2,466.6 |
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Income before income taxes
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187.4 |
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172.3 |
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327.2 |
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332.8 |
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Income tax provision
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(39.4 |
) |
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(43.1 |
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(69.6 |
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(83.2 |
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Net income
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$ |
148.0 |
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$ |
129.2 |
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$ |
257.6 |
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$ |
249.6 |
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Earnings per common share:
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Basic
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$ |
0.60 |
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$ |
0.53 |
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$ |
1.05 |
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$ |
1.02 |
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Diluted
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$ |
0.59 |
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$ |
0.52 |
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$ |
1.03 |
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$ |
1.01 |
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Shares used in computing earnings per common share:
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Basic
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245.0 |
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242.9 |
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244.8 |
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243.6 |
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Diluted
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249.9 |
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246.4 |
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251.1 |
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247.7 |
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The accompanying notes are an integral part of these statements.
CAMERON INTERNATIONAL CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS
(dollars in millions, except shares and per share data)
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June 30,
2011
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December 31,
2010
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(unaudited)
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ASSETS
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Cash and cash equivalents
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$ |
2,043.1 |
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$ |
1,832.5 |
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Receivables, net
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1,287.8 |
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1,056.1 |
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Inventories, net
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2,108.0 |
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1,779.3 |
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Other
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268.5 |
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265.0 |
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Total current assets
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5,707.4 |
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4,932.9 |
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Plant and equipment, net
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1,342.4 |
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1,247.8 |
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Goodwill
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1,531.3 |
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1,475.8 |
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Other assets
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345.9 |
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348.6 |
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TOTAL ASSETS
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$ |
8,927.0 |
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$ |
8,005.1 |
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LIABILITIES AND STOCKHOLDERS’ EQUITY
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Current portion of long-term debt
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$ |
431.0 |
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$ |
519.9 |
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Accounts payable and accrued liabilities
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1,928.4 |
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2,016.0 |
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Accrued income taxes
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23.8 |
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38.0 |
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Total current liabilities
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2,383.2 |
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2,573.9 |
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Long-term debt
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1,523.6 |
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772.9 |
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Deferred income taxes
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85.5 |
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95.7 |
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Other long-term liabilities
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193.2 |
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170.2 |
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Total liabilities
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4,185.5 |
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3,612.7 |
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Stockholders’ Equity:
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Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares
issued at June 30, 2011 and December 31, 2010
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2.6 |
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2.6 |
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Capital in excess of par value
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2,215.2 |
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2,259.3 |
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Retained earnings
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3,105.9 |
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2,848.3 |
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Accumulated other elements of comprehensive income (loss)
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77.9 |
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(27.1 |
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Less: Treasury stock, 18,045,968 shares at June 30, 2011
(19,197,642 shares at December 31, 2010)
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(660.1 |
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(690.7 |
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Total stockholders’ equity
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4,741.5 |
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4,392.4 |
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TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
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$ |
8,927.0 |
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$ |
8,005.1 |
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The accompanying notes are an integral part of these statements.
CAMERON INTERNATIONAL CORPORATION
(dollars in millions)
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Three Months Ended
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Six Months Ended
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June 30,
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June 30,
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2011
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2010
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2011
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2010
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(unaudited)
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Cash flows from operating activities:
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Net income
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148.0
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129.2
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257.6
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249.6
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Adjustments to reconcile net income to net cash provided by (used for) operating activities:
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Depreciation
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37.6
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37.6
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72.2
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71.4
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Amortization
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10.0
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15.3
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20.2
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29.6
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Non-cash stock compensation expense
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9.4
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6.4
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17.5
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18.5
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Deferred income taxes and tax benefit of employee stock compensation plan transactions
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(31.8
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)
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12.9
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(13.0
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)
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7.5
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Changes in assets and liabilities, net of translation, acquisitions and non-cash items:
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Receivables
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(169.5
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)
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(39.8
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)
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(201.2
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)
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20.1
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Inventories
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(111.5
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)
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(21.9
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)
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(285.0
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)
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(65.9
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)
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Accounts payable and accrued liabilities
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115.9
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(139.8
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)
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(133.4
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)
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(367.5
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)
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Other assets and liabilities, net
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93.3
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(39.6
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)
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39.8
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(118.7
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)
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Net cash provided by (used for) operating activities
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101.4
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(39.7
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)
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(225.3
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)
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(155.4
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)
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Cash flows from investing activities:
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Capital expenditures
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(72.4
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)
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(38.2
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)
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(134.3
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)
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(68.1
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)
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Acquisitions, net of cash acquired
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(14.9
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)
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(13.0
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)
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(42.5
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)
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(40.9
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)
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Proceeds from sale of plant and equipment
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3.2
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4.7
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9.9
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7.6
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Net cash used for investing activities
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(84.1
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)
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(46.5
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)
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(166.9
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)
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(101.4
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)
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Cash flows from financing activities:
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Short-term loan borrowings (repayments), net
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33.5
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(2.1
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)
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31.5
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(18.7
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)
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Issuance of senior debt
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747.8
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|
–
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747.8
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–
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Debt issuance costs
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(4.7
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)
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–
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(4.7
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)
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–
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Redemption of convertible debentures
|
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|
(181.2
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)
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|
–
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(181.2
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)
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|
–
|
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Premium for purchased call options
|
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|
(21.9
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)
|
|
|
–
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(21.9
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)
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–
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Purchase of treasury stock
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|
–
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(84.1
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)
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–
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|
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(123.9
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)
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Proceeds from stock option exercises, net of tax payments from stock compensation plan transactions
|
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|
0.9
|
|
|
|
(5.7
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) |
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16.6
|
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(12.2
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)
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Excess tax benefits from employee stock compensation plan transactions
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|
0.1
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|
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|
1.5
|
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|
4.8
|
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|
5.4
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Principal payments on capital leases
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|
(2.0
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)
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(1.7
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)
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(3.8
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)
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(3.3
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)
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|
Net cash provided by (used for) financing activities
|
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|
572.5
|
|
|
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(92.1
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)
|
|
|
589.1
|
|
|
|
(152.7
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)
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|
Effect of translation on cash
|
|
|
3.7
|
|
|
|
(12.2
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)
|
|
|
13.7
|
|
|
|
(23.0
|
)
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
593.5
|
|
|
|
(190.5
|
)
|
|
|
210.6
|
|
|
|
(432.5
|
)
|
|
Cash and cash equivalents, beginning of period
|
|
|
1,449.6
|
|
|
|
1,619.0
|
|
|
|
1,832.5
|
|
|
|
1,861.0
|
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|
Cash and cash equivalents, end of period
|
|
|
2,043.1
|
|
|
|
1,428.5
|
|
|
|
2,043.1
|
|
|
|
1,428.5
|
|
The accompanying notes are an integral part of these statements.
CAMERON INTERNATIONAL CORPORATION
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
Unaudited
Note 1: Basis of Presentation
The accompanying Unaudited Consolidated Condensed Financial Statements of Cameron International Corporation (the Company) have been prepared in accordance with Rule 10-01 of Regulation S-X and do not include all the information and footnotes required by generally accepted accounting principles for complete financial statements. Those adjustments, consisting of normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the financial information for the interim periods, have been made. The results of operations for such interim periods are not necessarily indicative of the results of operations for a full year. The Unaudited Consolidated Condensed Financial Statements should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto filed by the Company on Form 10-K for the year ended December 31, 2010.
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include, but are not limited to, estimates of total contract profit or loss on certain long-term production contracts, estimated losses on accounts receivable, estimated realizable value on excess and obsolete inventory, contingencies, including tax contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to pension accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill for impairment, estimated proceeds from assets held for sale and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ materially from these estimates.
During the third quarter of 2010, the Company restructured its business segments, moving its Process Systems division from the Drilling & Production Systems (DPS) segment to a newly formed business segment, Process & Compression Systems (PCS), in order to enhance the Company’s processing solutions for customers involved in the exploration, production, storage and transmission of crude oil and natural gas. PCS also includes the businesses that were previously part of the Compression Systems segment. All financial data included in this Quarterly Report on Form 10-Q relating to DPS and PCS have been retrospectively revised based on the new segment structure of the Company. The Company’s other business segment is Valves & Measurement (V&M).
Certain other prior year amounts have also been reclassified to conform to the current year presentation.
Note 2: Acquisitions
During the first half of 2011, the Company acquired the stock of three businesses for a total cash purchase price, net of cash acquired, of $42.5 million. Vescon Equipamentos Industriais Ltda. was acquired to strengthen the Company’s surface product offerings in the Brazilian market and has been included in the DPS segment since the date of acquisition. The remaining interest in Scomi Energy Sdn Bhd., previously a Cameron joint venture company, was acquired in order to strengthen the Company’s process systems offerings in the Malaysian market. On June 20, 2011, TS-Technology AS, a Norwegian company, was acquired to enhance the Company’s water treatment technology offerings. The results of both the Scomi Energy Sdn Bhd and TS-Technology AS businesses have been included in the PCS segment since the dates of the respective acquisitions.
Preliminary goodwill recorded from these acquisitions was approximately $35.9 million, of which approximately $20.1 million is deductible for tax purposes. The Company is still awaiting significant information relating to the fair value of the assets and liabilities of the acquired businesses in order to finalize the purchase price allocations.
Note 3: Other Costs
Other costs for the three and six months ended June 30, 2011 and 2010 consisted of the following (in millions):
| |
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee severance
|
|
$ |
5.6 |
|
|
$ |
3.8 |
|
|
$ |
5.9 |
|
|
$ |
9.5 |
|
|
NATCO acquisition integration costs
|
|
|
– |
|
|
|
11.3 |
|
|
|
– |
|
|
|
12.9 |
|
|
BOP litigation costs
|
|
|
14.0 |
|
|
|
2.7 |
|
|
|
22.3 |
|
|
|
2.7 |
|
|
Acquisition, refinancing and other restructuring costs
|
|
|
0.5 |
|
|
|
0.6 |
|
|
|
0.8 |
|
|
|
3.6 |
|
| |
|
$ |
20.1 |
|
|
$ |
18.4 |
|
|
$ |
29.0 |
|
|
$ |
28.7 |
|
Note 4: Receivables
Receivables consisted of the following (in millions):
| |
|
June 30,
2011
|
|
|
December 31,
2010
|
|
|
Trade receivables
|
|
$ |
1,194.7 |
|
|
$ |
991.2 |
|
|
Other receivables
|
|
|
108.3 |
|
|
|
78.9 |
|
|
Allowance for doubtful accounts
|
|
|
(15.2 |
) |
|
|
(14.0 |
) |
|
Total receivables
|
|
$ |
1,287.8 |
|
|
$ |
1,056.1 |
|
Note 5: Inventories
Inventories consisted of the following (in millions):
| |
|
June 30,
2011
|
|
|
December 31,
2010
|
|
|
Raw materials
|
|
$ |
206.5 |
|
|
$ |
166.5 |
|
|
Work-in-process
|
|
|
743.8 |
|
|
|
575.9 |
|
|
Finished goods, including parts and subassemblies
|
|
|
1,316.4 |
|
|
|
1,190.5 |
|
|
Other
|
|
|
12.7 |
|
|
|
12.1 |
|
| |
|
|
2,279.4 |
|
|
|
1,945.0 |
|
|
Excess of current standard costs over LIFO costs
|
|
|
(97.1 |
) |
|
|
(97.7 |
) |
|
Allowances
|
|
|
(74.3 |
) |
|
|
(68.0 |
) |
|
Total inventories
|
|
$ |
2,108.0 |
|
|
$ |
1,779.3 |
|
Note 6: Plant and Equipment and Goodwill
Plant and equipment consisted of the following (in millions):
| |
|
June 30,
2011
|
|
|
December 31,
2010
|
|
|
Plant and equipment, at cost
|
|
$ |
2,465.3 |
|
|
$ |
2,285.9 |
|
|
Accumulated depreciation
|
|
|
(1,122.9 |
) |
|
|
(1,038.1 |
) |
|
Total plant and equipment
|
|
$ |
1,342.4 |
|
|
$ |
1,247.8 |
|
Changes in goodwill during the six months ended June 30, 2011 were as follows (in millions):
|
Balance at December 31, 2010
|
|
$ |
1,475.8 |
|
|
Current year acquisitions
|
|
|
35.9 |
|
|
Translation
|
|
|
19.6 |
|
|
Balance at June 30, 2011
|
|
$ |
1,531.3 |
|
Note 7: Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consisted of the following (in millions):
| |
|
June 30,
2011
|
|
|
December 31,
2010
|
|
|
Trade accounts payable and accruals
|
|
$ |
555.7 |
|
|
$ |
571.3 |
|
|
Salaries, wages and related fringe benefits
|
|
|
154.3 |
|
|
|
190.2 |
|
|
Advances from customers
|
|
|
801.1 |
|
|
|
863.3 |
|
|
Sales-related costs and provisions
|
|
|
76.7 |
|
|
|
90.2 |
|
|
Payroll and other taxes
|
|
|
58.6 |
|
|
|
67.4 |
|
|
Product warranty
|
|
|
45.5 |
|
|
|
45.7 |
|
|
Fair market value of derivatives
|
|
|
3.6 |
|
|
|
1.8 |
|
|
Other
|
|
|
232.9 |
|
|
|
186.1 |
|
|
Total accounts payable and accrued liabilities
|
|
$ |
1,928.4 |
|
|
$ |
2,016.0 |
|
Activity during the six months ended June 30, 2011 associated with the Company’s product warranty accruals was as follows (in millions):
|
Balance
December 31,
2010
|
|
|
Net
warranty
provisions
|
|
|
Charges
against
accrual
|
|
|
Translation
and other
|
|
|
Balance
June 30,
2011
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ |
45.7 |
|
|
$ |
10.0 |
|
|
$ |
(10.4 |
) |
|
$ |
0.2 |
|
|
$ |
45.5 |
|
Note 8: Debt
The Company’s debt obligations were as follows (in millions):
| |
|
June 30,
2011
|
|
|
December 31,
2010
|
|
|
Senior notes:
|
|
|
|
|
|
|
|
Floating rate notes due June 2, 2014
|
|
$ |
250.0 |
|
|
$ |
– |
|
|
6.375% notes due July 15, 2018
|
|
|
450.0 |
|
|
|
450.0 |
|
|
4.5% notes due June 1, 2021
|
|
|
250.0 |
|
|
|
– |
|
|
7.0% notes due July 15, 2038
|
|
|
300.0 |
|
|
|
300.0 |
|
|
5.95% notes due June 1, 2041
|
|
|
250.0 |
|
|
|
– |
|
|
Unamortized original issue discount
|
|
|
(4.0 |
) |
|
|
(1.8 |
) |
|
Convertible debentures:
|
|
|
|
|
|
|
|
|
|
2.5% notes due June 15, 2026
|
|
|
371.1 |
|
|
|
500.0 |
|
|
Unamortized discount
|
|
|
– |
|
|
|
(6.9 |
) |
|
Other debt
|
|
|
71.8 |
|
|
|
37.5 |
|
|
Obligations under capital leases
|
|
|
15.7 |
|
|
|
14.0 |
|
| |
|
|
1,954.6 |
|
|
|
1,292.8 |
|
|
Current maturities
|
|
|
(431.0 |
) |
|
|
(519.9 |
) |
|
Long-term maturities
|
|
$ |
1,523.6 |
|
|
$ |
772.9 |
|
Senior Notes
Effective June 2, 2011, the Company completed the public offering of $750.0 million in aggregate principal amount of senior unsecured notes as follows:
|
·
|
$250.0 million principal amount of Floating Rate Senior Notes due June 2, 2014, bearing interest based on the 3-month London Interbank Offered Rate (LIBOR) plus 0.93%, per annum. The interest rate is reset quarterly and interest payments are due on March 2, June 2, September 2 and December 2 of each year, beginning September 2, 2011;
|
|
·
|
$250.0 million principal amount of 4.5% Senior Notes due June 1, 2021; and
|
|
·
|
$250.0 million principal amount of 5.95% Senior Notes due June 1, 2041.
|
Interest on the 4.5% and 5.95% Senior Notes is payable on June 1 and December 1 of each year, beginning December 1, 2011. The 4.5% and 5.95% Senior Notes were sold at 99.151% and 99.972% of principal amount, respectively, and can both be redeemed in whole or in part by the Company prior to maturity in accordance with the terms of the respective Supplemental Indentures. The Floating Rate Senior Notes are not redeemable by the Company prior to maturity. All of the Company's senior notes rank equally with the Company's other existing unsecured and unsubordinated debt.
The proceeds from the debt offering are intended for the purchase or redemption of the Company’s 2.5% Convertible Debentures (see below) and for general corporate purposes.
Convertible Debentures
In June 2011, the Company notified holders of its 2.5% Convertible Debentures that it was exercising its right to redeem for cash all of the outstanding debentures on July 6, 2011 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest. Holders of $295.5 million principal amount of debentures notified the Company they were instead electing to convert their debentures under the terms of the debenture agreement. The Company has elected to settle the entire conversion amount (principal plus the conversion value in excess of principal) in cash for those electing conversion. The remaining $204.5 million principal amount of debentures were either purchased by the Company on the open market or redeemed for cash during June and July 2011.
As of June 30, 2011, the Company had retired $128.9 million principal amount of its outstanding 2.5% Convertible Debentures. The total cash paid for these notes was $181.2 million. Approximately $50.8 million of the cash payment represented conversion value in excess of principal which has been recorded in capital in excess of par value. The remaining $371.1 million principal amount of notes will be settled in cash during the third quarter of 2011.
In order to hedge a portion of the conversion value for the 2.5% Convertible Debentures, the Company entered into an agreement with a third party financial intermediary in the second quarter of 2011 to purchase 5.0 million call options on its common stock at an average strike price of $47.69 per share. The total premium paid for these options was $21.9 million. See Note 14 of the Notes to Consolidated Condensed Financial Statements for further information.
Multicurrency Revolving Letter of Credit and Credit Facilities
On June 6, 2011, the Company entered into a Second Amendment to its Credit Agreement dated April 14, 2008 (the Amended Credit Agreement). This amendment increased the Company’s multicurrency borrowing capacity from $585.0 million to $835.0 million and extended the maturity date to June 6, 2016. Similar to the original Credit Agreement, the Company may borrow funds at LIBOR plus a spread, which varies based on the Company’s current debt rating, and, if aggregate outstanding credit exposure exceeds one-half of the total facility amount, an additional fee will be incurred. The entire $835.0 million committed facility is available to the Company through April 14, 2013, with $730.0 million available thereafter through June 6, 2016. At June 30, 2011, the Company had issued letters of credit totaling $25.4 million under this Amended Credit Agreement with the remaining amount of $809.6 million available for future use.
The Company also has a three-year $250.0 million committed multi-currency revolving letter of credit facility with a third party bank. At June 30, 2011, the Company had issued letters of credit totaling $45.3 million under this revolving credit facility, leaving a remaining amount of $204.7 million available for future use.
Note 9: Income Taxes
The Company’s effective tax rates for the six months ended June 30, 2011 and 2010 were 21.3% and 25.0%, respectively. The tax provision for the first half of 2011 is lower than the comparable period in 2010, primarily due to (i) realization of certain tax benefits totaling $16.0 million associated with tax planning strategies put in place in prior years and (ii) the recognition of certain historical tax benefits totaling $8.8 million as prior uncertainty regarding those benefits has been resolved during the first half of 2011.
Note 10: Business Segments
The Company’s operations are organized into three separate business segments – DPS, V&M and PCS. Summary financial data by segment follows (in millions):
| |
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DPS(1)
|
|
$ |
1,002.7 |
|
|
$ |
836.4 |
|
|
$ |
1,868.3 |
|
|
$ |
1,656.1 |
|
|
V&M
|
|
|
426.5 |
|
|
|
325.3 |
|
|
|
766.4 |
|
|
|
624.4 |
|
|
PCS(1)
|
|
|
311.9 |
|
|
|
291.0 |
|
|
|
607.6 |
|
|
|
518.9 |
|
| |
|
$ |
1,741.1 |
|
|
$ |
1,452.7 |
|
|
$ |
3,242.3 |
|
|
$ |
2,799.4 |
|
|
Income (loss) before income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DPS(1)
|
|
$ |
161.4 |
|
|
$ |
145.4 |
|
|
$ |
277.6 |
|
|
$ |
302.0 |
|
|
V&M
|
|
|
75.5 |
|
|
|
45.3 |
|
|
|
130.7 |
|
|
|
94.3 |
|
|
PCS(1)
|
|
|
34.0 |
|
|
|
39.5 |
|
|
|
64.5 |
|
|
|
54.9 |
|
|
Corporate & other
|
|
|
(83.5 |
) |
|
|
(57.9 |
) |
|
|
(145.6 |
) |
|
|
(118.4 |
) |
| |
|
$ |
187.4 |
|
|
$ |
172.3 |
|
|
$ |
327.2 |
|
|
$ |
332.8 |
|
|
(1)
|
Prior year amounts have been retrospectively revised to reflect the change in segments described in Note 1 of the Notes to Consolidated Condensed Financial Statements.
|
Corporate & other includes expenses associated with the Company’s Corporate office, all of the Company’s interest income and interest expense, certain litigation expense managed by the Company’s General Counsel, foreign currency gains and losses from certain intercompany lending activities managed by the Company’s centralized Treasury function, all of the Company’s restructuring expense and acquisition-related costs and all stock compensation expense.
Note 11: Earnings Per Share
The calculation of basic and diluted earnings per share for each period presented was as follows (dollars and shares in millions, except per share amounts):
| |
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
148.0 |
|
|
$ |
129.2 |
|
|
$ |
257.6 |
|
|
$ |
249.6 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares outstanding (basic)
|
|
|
245.0 |
|
|
|
242.9 |
|
|
|
244.8 |
|
|
|
243.6 |
|
|
Common stock equivalents
|
|
|
1.9 |
|
|
|
2.2 |
|
|
|
2.2 |
|
|
|
2.4 |
|
|
Incremental shares from assumed conversion of convertible debentures
|
|
|
3.0 |
|
|
|
1.3 |
|
|
|
4.1 |
|
|
|
1.7 |
|
|
Diluted shares
|
|
|
249.9 |
|
|
|
246.4 |
|
|
|
251.1 |
|
|
|
247.7 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
$ |
0.60 |
|
|
$ |
0.53 |
|
|
$ |
1.05 |
|
|
$ |
1.02 |
|
|
Diluted earnings per share
|
|
$ |
0.59 |
|
|
$ |
0.52 |
|
|
$ |
1.03 |
|
|
$ |
1.01 |
|
The Company’s 2.5% Convertible Debentures were included in the calculation of diluted earnings per share for the three- and six-months ended June 30, 2011 and 2010 since the average market price of the Company’s common stock exceeded the conversion value of the debentures during those periods.
No treasury shares were acquired during the three- and six-months ended June 30, 2011. During the three- and six-month periods ended June 30, 2010, the Company acquired 2,176,705 and 3,176,705 treasury shares at an average cost of $37.59 and $39.05, respectively. A total of 65,741 and 1,151,674 treasury shares were issued during the three- and six-months ended June 30, 2011, respectively in satisfaction of stock option exercises and vesting of restricted stock units.
Note 12: Comprehensive Income
The amounts of comprehensive income for the three and six months ended June 30, 2011 and 2010 were as follows (in millions):
| |
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per Consolidated Condensed Results of Operations
|
|
$ |
148.0 |
|
|
$ |
129.2 |
|
|
$ |
257.6 |
|
|
$ |
249.6 |
|
|
Foreign currency translation gain (loss)
|
|
|
26.0 |
|
|
|
(92.9 |
) |
|
|
96.3 |
|
|
|
(148.4 |
) |
|
Amortization of net prior service credits related to the Company’s pension and postretirement benefit plans, net of tax
|
|
|
(0.2 |
) |
|
|
(0.1 |
) |
|
|
(0.3 |
) |
|
|
(0.3 |
) |
|
Amortization of net actuarial losses related to the Company’s pension and postretirement benefit plans, net of tax
|
|
|
1.4 |
|
|
|
0.8 |
|
|
|
2.8 |
|
|
|
1.7 |
|
|
Change in fair value of derivatives accounted for as cash flow hedges, net of tax
|
|
|
1.6 |
|
|
|
(1.0 |
) |
|
|
6.2 |
|
|
|
(3.4 |
) |
|
Comprehensive income
|
|
$ |
176.8 |
|
|
$ |
36.0 |
|
|
$ |
362.6 |
|
|
$ |
99.2 |
|
The components of accumulated other elements of comprehensive income (loss) at June 30, 2011 and December 31, 2010 were as follows (in millions):
| |
|
June 31,
2011
|
|
|
December 31,
2010
|
|
|
Accumulated foreign currency translation gain
|
|
$ |
127.8 |
|
|
$ |
31.5 |
|
|
Prior service credits, net, related to the Company’s pension and postretirement benefit plans, net of tax
|
|
|
4.0 |
|
|
|
4.3 |
|
|
Actuarial losses, net, related to the Company’s pension and postretirement benefit plans, net of tax
|
|
|
(53.0 |
) |
|
|
(55.8 |
) |
|
Change in fair value of derivatives accounted for as cash flow hedges, net of tax
|
|
|
(0.9 |
) |
|
|
(7.1 |
) |
|
Accumulated other elements of comprehensive income (loss)
|
|
$ |
77.9 |
|
|
$ |
(27.1 |
) |
Note 13: Contingencies
The Company is subject to a number of contingencies, including litigation, tax contingencies and environmental matters.
Deepwater Horizon Matter
A blowout preventer (“BOP”) originally manufactured by the Company and delivered in 2001, and for which the Company was one of the suppliers of spare parts and repair services, was deployed by the drilling rig Deepwater Horizon when the rig experienced a tragic explosion and fire on April 20, 2010, resulting in bodily injuries and loss of life, loss of the rig, and an unprecedented discharge of hydrocarbons into the Gulf of Mexico.
While the Company did not operate the BOP, nor did it have anyone on the rig at the time of the incident, claims for personal injury, wrongful death and property damage arising from the Deepwater Horizon incident have been asserted against the Company and others. Additionally, claims for pollution and for economic damages, including business interruption and loss of revenue, have been, and may continue to be asserted against all parties associated with this incident, including the Company, BP p.l.c. and certain of its subsidiaries, the operator of Mississippi Canyon Block 252 upon which the Macondo well was being drilled, Transocean Ltd. and certain of its affiliates, the rig owner and operator, as well as other equipment and service companies, including Halliburton. The Company has been named as one of multiple defendants in over 350 suits filed and presently pending in a variety of Federal and State courts, a number of which have been filed as class actions or multi-plaintiff actions. Other defendants, including BP, Transocean and Halliburton have asserted cross-claims against us as we have asserted such claims against them. Most of these suits pending in Federal courts have been consolidated into a single proceeding before a single Federal judge under the rules governing multi-district litigation. The consolidated case is styled In Re: Oil Spill by the Oil Rig “Deepwater Horizon” in the Gulf of Mexico on April 20, 2010, MDL Docket No. 2179. There are also a small number of cases pending in state courts. The States of Alabama and Louisiana have brought a claim for destruction of and/or harm to natural resources against those associated with this incident, including Cameron, in State of Alabama, ex. rel. Troy King, Attorney General vs. Transocean Ltd., et. al., Cause No. 2:10cv00691, U.S. Dist. Ct., M.D. Ala., and State of Louisiana vs. BP Exploration & Production, Inc., et. al, MDL No. 2179, as have a number of other local governmental entities and 3 Mexican states. It is possible other such claims may be asserted against the Company by the United States Government (USG) and by other Gulf and/or East Coast States, whose Attorneys General have notified the Company to preserve documents in the event of a claim, and possibly by other parties. The USG has brought suit against BP and certain other parties associated with this incident for recovery under statutes such as the Oil Pollution Act of 1990 (OPA) and the Clean Water Act, which suit has been made part of the MDL proceedings. While the Company was not named as a defendant in this suit by the USG, BP brought a third-party complaint for contribution under OPA against several parties associated with this incident which were not named by the USG, including the Company. A shareholder derivative suit, Berzner vs. Erikson, et al., Cause No. 2010-71817 in the 190th District Court of Harris County, Texas, has been filed against the Company’s directors in connection with this incident and its aftermath alleging the Company’s directors failed to exercise their fiduciary duties regarding the safety and efficacy of its products. This incident and its causes have been investigated by a joint investigation team of the U.S. Coast Guard and the Bureau of Ocean Energy Management (the “JIT”), which has named Cameron a party-in-interest, the Departments of the Interior and Justice, the U.S. Chemical Safety and Hazard Investigation Board, and by various other governmental entities, including Congressional Committees. An investigation conducted by the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling has been completed. The Department of Justice, in addition to its involvement in the civil litigation, formed a task force to conduct criminal investigations into possible criminal charges stemming from this incident and its aftermath.
The Federal Court overseeing the multi-district litigation has ruled that it will begin trying liability issues arising out of the Deepwater Horizon Matter in February 2012, and has issued a number of orders to effectuate this scheduling.
Based on the facts known to date, the Company is of the opinion that there was no defect in or failure of the BOP that caused or contributed to the explosion. The reasons as to why the efforts to shut-in the well after the explosion were unsuccessful are not yet known and are the subject of continuing investigation and discovery in the MDL proceedings. A report on the results of a forensic examination of the BOP by Det Norske Veritas commissioned by the JIT as part of its investigation was made public in March 2011. This report cited what it considered to be the inability of the BOP to shear the off-center drill pipe as a contributing factor to the BOP’s blind shear rams being unable to close and seal the well. The JIT recently announced that it would release its final report in the "near future" but after the JIT's previously scheduled July 27, 2011 release date.
The extent of the environmental impact, and the ultimate costs and damages that will ultimately be determined attributable to this incident and its aftermath are not yet known and therefore cannot be reasonably estimated. As a result, we are unable to make any reasonable determination of what liability, if any, the Company could be found to have with respect to any of these claims or whether the Company will be found to have any liability, directly or by way of contribution, under any environmental laws or regulations or otherwise. BP has been designated as the Responsible Party for the pollution emanating from the Macondo well under OPA, and has accepted such designation. Cameron has not been named a Responsible Party.
The applicable contracts between Cameron and Transocean entities provide for customary industry “knock-for-knock” indemnification by which each party agreed to bear the risk of, and hold the other harmless with respect to, all claims for personal injury, to include wrongful death, and property loss or damage of its own, its employees and those of its contractors. Settlements in a number of personal injury and wrongful death cases have been reached between Transocean and the claimants, and the settlement agreements have included a complete release of Cameron. In addition, the contracts provide that in the event Transocean is entitled to indemnity under any contract with its customers or suppliers for pollution or other damages associated with a blowout or loss of well control, Transocean will provide Cameron with the benefit of such indemnity to the fullest extent possible. Transocean has publicly stated that it has a full pollution indemnity from BP, although BP has so far declined to acknowledge any obligation under the indemnity.
The Company has commercial general liability insurance, including completed products and sudden accidental pollution coverage, with limits of $500 million and a self retention of $3 million. Defense costs are not covered by the policy. Coverage includes claims for personal injury and wrongful death, as well as liability for pollution and loss of revenue/business interruption. The Company has notified its insurers of the claims being asserted against it. The insurers have responded with “reservation of rights” letters.
While the Company’s BOPs have a history of reliable performance when properly maintained and operated in accordance with product specifications, until the litigation referred to above progresses and until the investigations referred to above are completed, we are unable to determine the extent of the Company’s future involvement in the litigation and any liability resulting from this incident. If it is ultimately determined that the Company bears some responsibility, and therefore liability, for the costs and damages caused by this event, we will rely on our contractual indemnity rights and then, if and to the extent necessary and available, on our insurance coverage. If our contractual indemnities are determined to be inapplicable, or the indemnitors fail or are unable to fulfill their contractual indemnity obligations, and if the damages and costs ultimately determined to be the Company’s responsibility exceed our available insurance coverage, we could be liable for amounts that could have a material adverse impact on our financial condition, results of operations and cash flows.
Through June 30, 2011, the Company has incurred and expensed legal fees of $34.8 million. The Company has not accrued any amounts relating to this matter because we do not believe at the present time a loss is probable.
Other Litigation
In 2001, the Company discovered that contaminated underground water from a former manufacturing site in Houston (see discussion below under Environmental Matters) had migrated under an adjacent residential area. Pursuant to applicable state regulations, the Company notified the affected homeowners. Concerns over the impact on property values of the underground water contamination and its public disclosure led to a number of claims by homeowners. The Company has settled these claims, primarily as a result of the settlement of a class action lawsuit, and is obligated to reimburse 197 homeowners for any diminution in value of their property due to contamination concerns at the time of any sale.
Based upon 2009 testing results of monitoring wells on the southeastern border of the plume, the Company notified 33 homeowners whose property is adjacent to the class area that their property may be affected. The Company is taking remedial measures to prevent these properties from being affected.
The Company believes, based on its review of the facts and law, that any potential exposure from existing agreements as well as any possible new claims that may be filed with respect to this underground water contamination will not have a material adverse effect on its financial position or results of operations. The Company’s consolidated balance sheet included a liability of approximately $11.8 million for these matters as of June 30, 2011.
The Company has been named as a defendant in a number of multi-defendant, multi-plaintiff tort lawsuits since 1995. At June 30, 2011, the Company’s consolidated balance sheet included a liability of approximately $8.3 million for such cases. The Company believes, based on its review of the facts and law, that the potential exposure from these suits will not have a material adverse effect on its consolidated results of operations, financial condition or liquidity.
Regulatory Contingencies
In July 2007, the Company was one of a number of companies to receive a letter from the Criminal Division of the U.S. Department of Justice (DOJ) requesting information on activities undertaken on their behalf by a customs clearance broker. The DOJ inquired into whether certain of the services provided to the Company by the customs clearance broker may have involved violations of the U.S. Foreign Corrupt Practices Act (FCPA). The U.S. Securities and Exchange Commission (SEC) also conducted an informal inquiry into the same matter.
Following a review of the investigation conducted by the Company's special counsel and a number of follow-up meetings, both the DOJ and SEC have notified the Company they do not intend to pursue enforcement action against the Company with regard to this matter and their respective files have been closed.
Tax Contingencies
The Company has legal entities in over 40 countries. As a result, the Company is subject to various tax filing requirements in these countries. The Company prepares its tax filings in a manner which it believes is consistent with such filing requirements. However, some of the tax laws and regulations to which the Company is subject require interpretation and/or judgment. Although the Company believes the tax liabilities for periods ending on or before the balance sheet date have been adequately provided for in the financial statements, to the extent a taxing authority believes the Company has not prepared its tax filings in accordance with the authority’s interpretation of the tax laws and regulations, the Company could be exposed to additional taxes.
The Company is currently identified as a potentially responsible party (PRP) with respect to two sites designated for cleanup under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) or similar state laws. One of these sites is Osborne, Pennsylvania (a landfill into which a predecessor of the PCS operation in Grove City, Pennsylvania deposited waste), where remediation is complete and remaining costs relate to ongoing ground water treatment and monitoring. The other is believed to be a de minimis exposure. The Company is also engaged in site cleanup under the Voluntary Cleanup Plan of the Texas Commission on Environmental Quality at former manufacturing locations in Houston and Missouri City, Texas. Additionally, the Company has discontinued operations at a number of other sites which had been active for many years. The Company does not believe, based upon information currently available, that there are any material environmental liabilities existing at these locations. At June 30, 2011, the Company’s consolidated balance sheet included a noncurrent liability of approximately $5.8 million for environmental matters.
Note 14: Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, trade payables, derivative instruments and debt instruments. The book values of cash and cash equivalents, trade receivables, trade payables, derivative instruments and floating-rate debt instruments are considered to be representative of their respective fair values.
Cash and cash equivalents include highly liquid investments with a maturity of ninety days or less at the time of purchase. Cash equivalents consist primarily of money market securities, U.S. treasury bills, other U.S. agency notes, short-term commercial paper and corporate debt securities, all of which are considered Level 1 under the ASC’s fair value hierarchy. Total cash equivalents were approximately $1.68 billion and $1.38 billion at June 30, 2011 and December 31, 2010, respectively.
Fair value of the Company’s fixed rate debt (based on level 1 quoted market rates) was (in millions):
| |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate Senior Notes
|
|
$ |
1,250.0 |
|
|
$ |
1,369.5 |
|
|
$ |
750.0 |
|
|
$ |
828.6 |
|
|
2.5% Convertible Debentures
|
|
|
371.1 |
|
|
|
522.3 |
|
|
|
500.0 |
|
|
|
724.4 |
|
| |
|
$ |
1,621.1 |
|
|
$ |
1,891.8 |
|
|
$ |
1,250.0 |
|
|
$ |
1,553.0 |
|
As indicated in Note 8 of the Notes to Consolidated Financial Statements, during the second quarter of 2011, the Company entered into an agreement with a third party financial intermediary for the purchase of 5.0 million call options on its common stock at an average strike price of $47.69 per share. The total premium paid for these options was $21.9 million. If the individual options are “in-the-money” upon expiration at various dates during August 2011, the option value will be settled on a net-cash basis with the third party financial intermediary, otherwise, the options will be allowed to expire if they have no value to the Company at that time. Changes in the fair value of the call options are being recognized in other costs in the period in which the change occurs.
The fair value of the options are determined using a Black-Scholes-Merton option pricing formula consisting of current assumptions involving the Company’s stock price at June 30, 2011, the expected volatility of the Company’s stock through August 2011 and short-term risk-free interest rates. The change in the estimated fair value of the call options determined using these level 3 unobservable market inputs was as follows (in millions):
| |
|
Three Months Ended
June 30, 2011
|
|
|
Beginning balance
|
|
$ |
– |
|
|
Premium paid
|
|
|
21.9 |
|
|
Change in estimated fair value
|
|
|
1.6 |
|
|
Balance at June 30, 2011
|
|
$ |
23.5 |
|
In order to mitigate the effect of exchange rate changes, the Company will often attempt to structure sales contracts to provide for collections from customers in the currency in which the Company incurs its manufacturing costs. In certain instances, the Company will enter into forward foreign currency exchange contracts to hedge specific large anticipated receipts or disbursements in currencies for which the Company does not traditionally have fully offsetting local currency expenditures or receipts. The Company was party to a number of long-term foreign currency forward contracts at June 30, 2011, some of which extend through 2012. The purpose of the majority of these contracts was to hedge large anticipated non-functional currency cash flows on major subsea, drilling, valve or other equipment contracts involving the Company’s United States operations and its wholly-owned subsidiaries in Italy, Romania, Singapore and the United Kingdom. The Company determines the fair value of its outstanding foreign currency forward contracts based on quoted exchange rates for the respective currencies applicable to similar instruments. These quoted exchange rates are considered to be Level 2 observable market inputs. Information relating to the contracts, most of which have been accounted for as cash flow hedges as of June 30, 2011, follows:
Total gross volume bought (sold) by notional currency and maturity date on open derivative contracts at June 30, 2011 was as follows (in millions):
| |
|
Notional Amount - Swaps
|
|
|
Notional Amount - Buy
|
|
|
Notional Amount - Sell
|
|
| |
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
FX Forward Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional currency in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BRL
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(31.0 |
) |
|
|
– |
|
|
|
(31.0 |
) |
|
EUR
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
37.9 |
|
|
|
7.6 |
|
|
|
45.5 |
|
|
|
(32.4 |
) |
|
|
– |
|
|
|
(32.4 |
) |
|
GBP
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
2.2 |
|
|
|
34.0 |
|
|
|
36.2 |
|
|
|
(11.9 |
) |
|
|
– |
|
|
|
(11.9 |
) |
|
MYR
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
19.2 |
|
|
|
– |
|
|
|
19.2 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
NOK
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
90.0 |
|
|
|
90.0 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
RON
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
10.0 |
|
|
|
– |
|
|
|
10.0 |
|
|
|
(10.0 |
) |
|
|
– |
|
|
|
(10.0 |
) |
|
SGD
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
13.4 |
|
|
|
– |
|
|
|
13.4 |
|
|
|
(0.4 |
) |
|
|
– |
|
|
|
(0.4 |
) |
|
USD
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
9.5 |
|
|
|
0.3 |
|
|
|
9.8 |
|
|
|
(54.7 |
) |
|
|
(31.6 |
) |
|
|
(86.3 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FX Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EUR
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
69.6 |
|
|
|
– |
|
|
|
69.6 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USD
|
|
|
– |
|
|
|
800.0 |
|
|
|
800.0 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity call options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.0 |
|
|
|
– |
|
|
|
5.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair values of derivative financial instruments recorded in the Company’s Consolidated Condensed Balance Sheets at June 30, 2011 and December 31, 2010 were as follows:
| |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange contracts –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$ |
1.6 |
|
|
$ |
1.2 |
|
|
$ |
0.7 |
|
|
$ |
1.8 |
|
|
Non-current
|
|
|
0.1 |
|
|
|
0.1 |
|
|
|
– |
|
|
|
– |
|
|
Total derivatives designated as hedges
|
|
|
1.7 |
|
|
|
1.3 |
|
|
|
0.7 |
|
|
|
1.8 |
|
|
Derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange contracts –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
3.5 |
|
|
|
2.4 |
|
|
|
1.4 |
|
|
|
– |
|
|
Non-current
|
|
|
– |
|
|
|
1.3 |
|
|
|
– |
|
|
|
– |
|
|
Interest Rate Swaps –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
3.3 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
Non-current
|
|
|
– |
|
|
|
– |
|
|
|
4.8 |
|
|
|
– |
|
|
Equity call options –
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
23.5 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
Non-current
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
Total derivatives not designated as hedges
|
|
|
30.3 |
|
|
|
3.7 |
|
|
|
6.2 |
|
|
|
– |
|
|
Total derivatives
|
|
$ |
32.0 |
|
|
$ |
5.0 |
|
|
$ |
6.9 |
|
|
$ |
1.8 |
|
The effects of derivative financial instruments on the Company’s consolidated condensed financial statements for the three months ended June 30, 2011 and June 30, 2010 were as follows (in millions):
| |
|
Effective Portion
|
|
Ineffective Portion and Other
|
|
|
Derivatives in
Cash Flow
Hedging
Relationships
|
|
Amount of
Pre-Tax
Gain (Loss)
Recognized in
OCI on
Derivatives at
June 30,
|
|
Location of
Gain (Loss) Reclassified from Accumulated OCI into Income
|
|
Amount of
Gain (Loss)
Reclassified from
Accumulated OCI
into Income at
June 30,
|
|
Location of
Gain (Loss) Recognized in
Income on
Derivatives
|
|
Amount of
Gain (Loss)
Recognized in
Income on
Derivatives at
June 30,
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Foreign exchange contracts
|
|
$ |
0.4 |
|
|
$ |
(6.9) |
|
Revenues
|
|
$ |
0.2 |
|
|
$ |
(2.0) |
|
Cost of sales - ineffective portion
|
|
$ |
(0.1) |
|
|
$ |
(1.7) |
|
| |
|
|
|
|
|
|
|
|
Cost of sales
|
|
|
(0.8) |
|
|
|
(3.4) |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
−
|
|
|
|
−
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
0.4 |
|
|
$ |
(6.9) |
|
|
|
$ |
(0.6) |
|
|
$ |
(5.4) |
|
|
|
$ |
(0.1) |
|
|
$ |
(1.7) |
|
The effects of derivative financial instruments on the Company’s consolidated condensed financial statements for the six months ended June 30, 2011 and June 30, 2010 were as follows (in millions):
| |
|
Effective Portion
|
|
Ineffective Portion and Other
|
|
|
Derivatives in
Cash Flow
Hedging
Relationships
|
|
Amount of
Pre-Tax
Gain (Loss)
Recognized in
OCI on
Derivatives at
June 30,
|
|
Location of
Gain (Loss) Reclassified from Accumulated OCI into Income
|
|
Amount of
Gain (Loss)
Reclassified from
Accumulated OCI
into Income at
June 30,
|
|
Location of
Gain (Loss) Recognized in
Income on
Derivatives
|
|
Amount of
Gain (Loss)
Recognized in
Income on
Derivatives at
June 30,
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Foreign exchange contracts
|
|
$ |
2.9 |
|
|
$ |
(12.9) |
|
Revenues
|
|
$ |
1.8 |
|
|
$ |
(2.6) |
|
Cost of sales - ineffective portion
|
|
$ |
(0.3) |
|
|
$ |
(2.0) |
|
| |
|
|
|
|
|
|
|
|
Cost of sales
|
|
|
(6.5) |
|
|
|
(6.1) |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
(0.1) |
|
|
|
(0.1) |
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
2.9 |
|
|
$ |
(12.9) |
|
|
|
$ |
(4.8) |
|
|
$ |
(8.8) |
|
|
|
$ |
(0.3) |
|
|
$ |
(2.0) |
|
The amount of gain (loss) recognized on derivatives not designated as hedging instruments was (in millions):
| |
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
$ |
(1.3 |
) |
|
$ |
1.2 |
|
|
$ |
(0.8 |
) |
|
$ |
2.8 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, net
|
|
|
– |
|
|
|
2.0 |
|
|
|
(0.2 |
) |
|
|
6.1 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity call options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other costs
|
|
|
1.6 |
|
|
|
– |
|
|
|
1.6 |
|
|
|
– |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
0.3 |
|
|
$ |
3.2 |
|
|
$ |
0.6 |
|
|
$ |
8.9 |
|
In addition to the historical data contained herein, this document includes forward-looking statements regarding future market strength, customer spending and order levels, revenues and earnings of the Company, as well as expectations regarding equipment deliveries, margins, profitability, the ability to control and reduce raw material, overhead and operating costs, cash generated from operations, legal fees and costs associated with a number of lawsuits filed against the Company in connection with the Deepwater Horizon matter, capital expenditures and the use of existing cash balances and future anticipated cash flows made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company’s actual results may differ materially from those described in any forward-looking statements. Any such statements are based on current expectations of the Company’s performance and are subject to a variety of factors, some of which are not under the control of the Company, which can affect the Company’s results of operations, liquidity or financial condition. Such factors may include overall demand for, and pricing of, the Company’s products; the size and timing of orders; the Company’s ability to successfully execute large subsea and drilling projects it has been awarded; the possibility of cancellations of orders in backlog; the Company’s ability to convert backlog into revenues on a timely and profitable basis; the impact of acquisitions the Company has made or may make; changes in the price of (and demand for) oil and gas in both domestic and international markets; raw material costs and availability; political and social issues affecting the countries in which the Company does business, including the difficulty companies are facing in obtaining drilling permits following the lifting of a temporary moratorium imposed by the United States government on drilling activities in deepwater areas of the Gulf of Mexico; fluctuations in currency markets worldwide; and variations in global economic activity. In particular, current and projected oil and gas prices historically have generally directly affected customers’ spending levels and their related purchases of the Company’s products and services. As a result, changes in oil and gas price expectations may impact the demand for the Company’s products and services and the Company’s financial results due to changes in cost structure, staffing and spending levels the Company makes in response thereto. See additional factors discussed in “Factors That May Affect Financial Condition and Future Results” contained herein.
Because the information herein is based solely on data currently available, it is subject to change as a result of, among other things, changes in conditions over which the Company has no control or influence, and should not therefore be viewed as assurance regarding the Company’s future performance. Additionally, the Company is not obligated to make public disclosure of such changes unless required under applicable disclosure rules and regulations.
SECOND QUARTER 2011 COMPARED TO SECOND QUARTER 2010
Market Conditions
Information related to a measure of drilling activity and certain commodity spot and futures prices during each quarter and the number of deepwater floaters and semis under contract at the end of each period follows:
| |
|
Quarter Ended
June 30,
|
|
|
Increase (Decrease)
|
|
| |
|
2011
|
|
|
2010
|
|
|
Amount
|
|
|
%
|
|
|
Drilling activity (average number of working rigs during period)(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
1,829 |
|
|
|
1,508 |
|
|
|
321 |
|
|
|
21.3 |
% |
|
Canada
|
|
|
188 |
|
|
|
166 |
|
|
|
22 |
|
|
|
13.3 |
% |
|
Rest of world
|
|
|
1,146 |
|
|
|
1,088 |
|
|
|
58 |
|
|
|
5.3 |
% |
|
Global average rig count
|
|
|
3,163 |
|
|
|
2,762 |
|
|
|
401 |
|
|
|
14.5 |
% |
|
Commodity prices (average of daily U.S. dollar prices per unit during period)(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate Cushing, OK crude spot price per barrel in U.S. dollars
|
|
$ |
102.28 |
|
|
$ |
77.88 |
|
|
$ |
24.40 |
|
|
|
31.3 |
% |
|
Henry Hub natural gas spot price per MMBtu in U.S. dollars
|
|
$ |
4.36 |
|
|
$ |
4.33 |
|
|
$ |
.03 |
|
|
|
0.7 |
% |
|
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate Cushing, OK crude oil contract (per barrel)
|
|
$ |
98.03 |
|
|
$ |
77.85 |
|
|
$ |
20.18 |
|
|
|
25.9 |
% |
|
Henry Hub Natural Gas contract (per MMBtu)
|
|
$ |
4.65 |
|
|
$ |
5.07 |
|
|
$ |
(0.42 |
) |
|
|
(8.3 |
)% |
|
Number of deepwater floaters and semis under contract in competitive major markets at period-end(3):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Gulf of Mexico
|
|
|
28 |
|
|
|
33 |
|
|
|
(5 |
) |
|
|
(15.2 |
)% |
|
Northwestern Europe
|
|
|
37 |
|
|
|
35 |
|
|
|
2 |
|
|
|
5.7 |
% |
|
West Africa
|
|
|
30 |
|
|
|
24 |
|
|
|
6 |
|
|
|
25.0 |
% |
|
Southeast Asia and Australia
|
|
|
23 |
|
|
|
28 |
|
|
|
(5 |
) |
|
|
(17.9 |
)% |
(1) Based on average monthly rig count data from Baker Hughes
(2) Source: Bloomberg
(3) Source: ODS-Petrodata Ltd.
The average number of worldwide operating rigs trended downward during the second quarter of 2011 due to seasonal factors in Canada. During the second quarter of 2010, the level of worldwide operating rigs remained relatively flat as increased U.S. activity levels offset the seasonal activity decline in Canada. Over 85% of the increase in average worldwide operating rigs during the second quarter of 2011 as compared to the second quarter of 2010 was due to higher North American activity levels largely reflecting the impact of unconventional resource opportunities in the region and higher commodity prices.
Crude oil prices (West Texas Intermediate, Cushing, OK) reached a high for the year of almost $114 per barrel in April 2011 before declining during the remainder of the second quarter to the mid-$90 range by the end of June 2011. Additionally, oil prices trended downward throughout most of the second quarter of 2010. Average prices for the second quarter of 2011, however, were up nearly 26% as compared to the same period in 2010 reflecting the effects of recent turmoil in the Middle East, increased demand from developing countries and the weaker U.S. dollar.
Natural gas (Henry Hub) prices trended upward at a modest pace during the second quarter of 2011 and at a steeper pace during the second quarter of 2010 as compared to price levels at the beginning of both periods. However, the average price for the second quarter of 2011 was relatively flat as compared to the same period in 2010, due largely to increased supplies available in North America as a result of new unconventional resource developments and higher activity levels.
Historically, the level of capital expenditures by the Company’s customers, which impacts demand for much of the Company’s products and services, has been affected by the level of drilling, exploration and production activity as well as the price of oil and natural gas. The recent changes in crude oil and natural gas prices and expectations of future prices as reflected in the twelve-month futures strip price may affect the future capital spending plans of certain of the Company’s customers.
Consolidated Results
Net income for the second quarter of 2011 totaled $148.0 million, or $0.59 per diluted share, compared to net income for the second quarter of 2010 of $129.2 million, or $0.52 per diluted share. Included in the second quarter 2011 results were pre-tax charges of $20.1 million, or approximately $0.07 per diluted share, primarily associated with costs for BOP litigation and certain severance and restructuring-related activities. Results for the second quarter of 2010, included pre-tax charges of $18.4 million, or $0.06 per diluted share, for acquisition integration costs, employee severance, costs for BOP litigation and certain other costs.
Total revenues for the Company increased by $288.4 million, or 19.9%, during the three months ended June 30, 2011 as compared to the three months ended June 30, 2010 on the strength of higher sales in each of the Company’s business segments.
|
|
•
|
Nearly 17% of the revenue increase was due to the impact of a weaker U.S. dollar on revenues denominated in other currencies during the second quarter of 2011 as compared to the second quarter of 2010.
|
|
|
•
|
Sales in the Drilling and Production Systems (DPS) segment, the Valves & Measurement (V&M) segment and the Process & Compression Systems (PCS) segment are discussed in more detail below.
|
As a percent of revenues, cost of sales (exclusive of depreciation and amortization) increased from 67.8% during the second quarter of 2010 to 69.7% for the second quarter of 2011. Margin declines totaling nearly 2.8 percentage-points, mainly related to major drilling, subsea and process system projects, more than offset a 0.9 percentage-point improvement in V&M margins resulting largely from better pricing and higher volumes on distributed valve product sales.
Selling and administrative expenses increased $45.5 million, or 22.2%, during the three months ended June 30, 2011 as compared to the three months ended June 30, 2010.
| |
•
|
Selling and administrative expenses were 14.4% of revenues for the second quarter of 2011 compared to 14.1% for the comparable period during 2010.
|
| |
•
|
Nearly 12% of the increase was attributable to the impact of a weaker U.S. dollar on costs denominated in other currencies.
|
| |
•
|
Nearly 12% of the increase was attributable to the impact of a weaker U.S. dollar on costs denominated in other currencies.
|
| |
•
|
Approximately three-fourths of the remaining increase was due to higher employee-related costs associated with higher headcount levels and higher incentive compensation expense.
|
Depreciation and amortization expense decreased $5.3 million, from $52.9 million for the second quarter of 2010 to $47.6 million for the second quarter of 2011. The decrease was due mainly to lower amortization of intangible assets.
Net interest for the three months ended June 30, 2011 was $22.1 million, an increase of $2.7 million from $19.4 million for the three months ended June 30, 2010. The increase resulted primarily from additional interest expense associated with the public offering of $750.0 million of fixed and floating rate Senior Notes completed in June 2011.
The Company’s effective tax rate for the second quarter of 2011 was 21.0% compared to 25.0% during the second quarter of 2010. The tax provision for the second quarter of 2011 was lower than the comparable period in 2010, primarily due to:
| |
•
|
realization of certain tax benefits totaling $16.0 million associated with tax planning strategies put in place in prior years, and
|
| |
•
|
the recognition of certain historical tax benefits totaling $5.6 million as prior uncertainty regarding those benefits has been resolved during the second quarter of 2011.
|
Segment Results
DPS Segment –
| |
|
Quarter Ended
June 30,
|
|
|
Increase (Decrease)
|
|
|
($ in millions)
|
|
2011
|
|
|
2010(1)
|
|
|
$ |
|
|
|
% |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,002.7 |
|
|
$ |
836.4 |
|
|
$ |
166.3 |
|
|
|
19.9 |
% |
|
Income before income taxes
|
|
$ |
161.4 |
|
|
$ |
145.4 |
|
|
$ |
16.0 |
|
|
|
11.0 |
% |
|
Income before income taxes as a percent of revenues
|
|
|
16.1 |
% |
|
|
17.4 |
% |
|
|
N/A |
|
|
|
(1.3 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Orders
|
|
$ |
1,442.7 |
|
|
$ |
782.6 |
|
|
$ |
660.1 |
|
|
|
84.3 |
% |
|
Backlog (at period end)
|
|
$ |
3,628.3 |
|
|
$ |
3,583.8 |
|
|
$ |
44.5 |
|
|
|
1.2 |
% |
|
(1)
|
Revised based on changes in segments described in Note 1 of the Notes to Consolidated Financial Statements.
|
Revenues
The increase in revenues was mainly due to:
|
|
•
|
a 25% increase in sales of surface equipment as a result of higher activity levels in all major regions,
|
|
|
•
|
a 22% increase in sales of drilling equipment as a result of (i) increased demand for spares and repair services, and (ii) higher shipments of blowout preventers (BOPs) for use on land and jackup rigs, and
|
|
|
•
|
an 11% increase in subsea equipment sales resulting mainly from the impact of a weaker U.S. dollar on revenues denominated in other currencies and higher aftermarket spare parts and repair services.
|
Income before income taxes as a percent of revenues
The decrease in the ratio of income before income taxes as a percent of revenues was due primarily to a 2.1 percentage-point increase in the ratio of cost of sales to revenues during the second quarter of 2011 due mainly to lower margins on major drilling and subsea projects (approximately a 3.5 percentage-point margin decrease) partially offset by higher surface equipment margins (approximately a 1.3 percentage-point margin increase).
Partially offsetting the impact of the cost of sales increase in relation to revenues was a decrease of 0.7 percentage-points in the ratio of selling and administrative costs to revenues due to revenues increasing at a faster rate than selling and administrative expenses during the current quarter.
Selling and administrative expenses increased 12.2% during the second quarter of 2011 as compared to the second quarter of 2010 due mainly to the impact of a weaker U.S. dollar on costs denominated in other currencies, higher employee-related costs due to higher headcount levels and higher rental and lease expenses.
Drilling orders increased 173% in the second quarter of 2011 as compared to the same period last year, accounting for three-fourths of the increase in total segment orders, based on the strength of awards received in the quarter for equipment for nine new deepwater rig construction projects, as well as higher demand for stack upgrades, spares, repairs and field service work. Other increases included:
|
|
•
|
a 72% increase in subsea equipment orders, related primarily to projects offshore Brazil and China, and
|
|
|
•
|
an 8% increase in surface equipment orders due mainly to increased demand for aftermarket parts and services as a result of (i) higher North American activity levels caused by higher oil prices and the impact of new shale gas opportunities, and (ii) increased demand from customers in Latin America and China.
|
A 46% increase in drilling equipment backlog as a result of strong order activity was largely offset by a nearly 13% decline in backlog for subsea equipment at June 30, 2011 as compared to June 30, 2010. Surface equipment backlog levels were up modestly compared to the same period last year.
V&M Segment –
| |
|
Quarter Ended
June 30,
|
|
|
Increase
|
|
|
($ in millions)
|
|
2011
|
|
|
2010
|
|
|
$ |
|
|
|
% |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
426.5 |
|
|
$ |
325.3 |
|
|
$ |
101.2 |
|
|
|
31.1 |
% |
|
Income before income taxes
|
|
$ |
75.5 |
|
|
$ |
45.3 |
|
|
$ |
30.2 |
|
|
|
66.7 |
% |
|
Income before income taxes as a percent of revenues
|
|
|
17.7 |
% |
|
|
13.9 |
% |
|
|
N/A |
|
|
|
3.8 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Orders
|
|
$ |
526.5 |
|
|
$ |
339.1 |
|
|
$ |
187.4 |
|
|
|
55.3 |
% |
|
Backlog (at period end)
|
|
$ |
1,016.2 |
|
|
$ |
630.8 |
|
|
$ |
385.4 |
|
|
|
61.1 |
% |
Revenues
The impact of a weaker U.S. dollar on revenues denominated in other currencies, demand for equipment on subsea pipeline projects, improved market conditions in North America and higher beginning-of-period backlog levels contributed to a 39% increase in sales of engineered valves and a 34% increase in distributed valves sales during the second quarter of 2011 as compared to the same period in 2010. Combined, these two product lines accounted for over 80% of the increase in V&M segment sales.
Income before income taxes as a percent of revenues
The increase in the ratio of income before income taxes as a percent of revenues was due primarily to:
|
|
•
|
a 1.0 percentage-point decrease in the ratio of cost of sales to revenues due largely to improved margins in the distributed valves product line as a result of higher pricing and increased volumes,
|
|
|
•
|
a 1.0 percentage-point decrease in the ratio of depreciation and amortization to revenues mainly resulting from the impact of the increase in revenues on a relatively modest decline in the amortization of intangible assets, and
|
|
|
•
|
a 1.7 percentage-point decrease in the ratio of selling and administrative expenses to revenues as a result of the impact of revenues increasing at a greater rate than the increase in selling and administrative expenses.
|
Selling and administrative expenses increased 17.3% due mainly to higher employee-related costs as a result of headcount increases.
Orders
Orders increased in all product lines with engineered and distributed valves accounting for over 80% of the total segment increase in the second quarter of 2011 as compared to the second quarter of 2010. Demand for engineered valves increased 77% and distributed valve orders were up 65%, due largely to higher North American activity levels and large project awards in the Asia Pacific region during the second quarter of 2011.
Backlog (at period-end)
Backlog levels for all product lines in the V&M segment were up from June 30, 2010, with nearly 78% of the increase attributable to higher levels of backlog in the engineered and process valves lines, reflecting stronger demand in recent periods in those product lines.
PCS Segment –
| |
|
Quarter Ended
June 30,
|
|
|
Increase (Decrease)
|
|
|
($ in millions)
|
|
2011
|
|
|
2010(1)
|
|
|
$ |
|
|
|
% |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
311.9 |
|
|
$ |
291.0 |
|
|
$ |
20.9 |
|
|
|
7.2 |
% |
|
Income before income taxes
|
|
$ |
34.0 |
|
|
$ |
39.5 |
|
|
$ |
(5.5 |
) |
|
|
(13.9 |
)% |
|
Income before income taxes as a percent of revenues
|
|
|
10.9 |
% |
|
|
13.6 |
% |
|
|
N/A |
|
|
|
(2.7 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Orders
|
|
$ |
418.1 |
|
|
$ |
267.4 |
|
|
$ |
150.7 |
|
|
|
56.4 |
% |
|
Backlog (at period end)
|
|
$ |
875.1 |
|
|
$ |
707.0 |
|
|
$ |
168.1 |
|
|
|
23.8 |
% |
|
|
Revised based on changes in segments described in Note 1 of the Notes to Consolidated Financial Statements.
|
Revenues
The increase is due primarily to a 53% increase in sales of reciprocating compression equipment resulting largely from stronger international shipments of Superior compressors. Better current economic conditions contributed to a 28% increase in sales of centrifugal compression equipment, but this increase was more than offset by a 10% decline in sales of process systems applications as a result of lower activity levels for major custom engineered projects, particularly in North America.
Income before income taxes as a percent of revenues
The decrease in the ratio of income before income taxes as a percent of revenues was due primarily to:
|
|
•
|
a 2.7 percentage-point increase in the ratio of cost of sales to revenues during the second quarter of 2011, due mainly to lower project margins in the process systems business that were partially offset by higher reciprocating and centrifugal compression equipment margins due mainly to improved volumes, and
|
|
|
•
|
a 2.7 percentage-point increase in the ratio of selling and administrative costs to revenues resulting from higher employee-related costs and increased legal and consulting fees.
|
This was partially offset by a decrease of 2.7 percentage points in the ratio of depreciation and amortization to revenues during the second quarter of 2011, due mainly to lower amortization of purchased intangibles and lower depreciation from constrained capital spending.
Orders
The increase in orders was due mainly to:
|
|
•
|
a 73% increase in process systems orders resulting from several large project awards received in the second quarter of 2011,
|
|
|
•
|
a 66% increase in centrifugal compression equipment orders due to strong growth across all major regions for engineered gas, air and air separation equipment, and
|
|
|
•
|
an 18% increase in demand for reciprocating compression equipment mainly as a result of several large multi-unit orders received for Ajax units during the second quarter of 2011.
|
Backlog (at period-end)
Strong order levels resulted in a backlog increase in all major product lines as compared to June 30, 2010. A 44% increase in centrifugal compression equipment backlog accounted for 56% of the total segment backlog increase. Additionally, reciprocating compression equipment backlog was up 27% and process systems backlog increased 12% from the prior year.
Corporate Segment –
The $25.6 million increase in the loss before income taxes of the Corporate segment during the second quarter of 2011 as compared to the second quarter of 2010 (see Note 10 of the Notes to Consolidated Condensed Financial Statements) was due primarily to:
|
•
|
$6.9 million of foreign currency gains recorded in the second quarter of 2010 that did not repeat in the second quarter of 2011,
|
|
|
•
|
a $14.0 million increase in selling and administrative expenses due primarily to higher employee and incentive compensation costs, as well as higher costs associated with implementation of the Company's enhanced business information systems, and
|
|
|
•
|
higher interest and other costs which are described in more detail under “Consolidated Results” above.
|
SIX MONTHS ENDED JUNE 30, 2011 COMPARED TO SIX MONTHS ENDED JUNE 30, 2010
Market Conditions
Information related to a measure of drilling activity and certain commodity spot and futures prices follows:
| |
|
Six Months Ended
June 30,
|
|
|
Increase (Decrease)
|
|
| |
|
2011
|
|
|
2010
|
|
|
Amount
|
|
|
%
|
|
|
Drilling activity (average number of working rigs during period)(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
1,773 |
|
|
|
1,427 |
|
|
|
346 |
|
|
|
24.2 |
% |
|
Canada
|
|
|
387 |
|
|
|
318 |
|
|
|
69 |
|
|
|
21.7 |
% |
|
Rest of world
|
|
|
1,156 |
|
|
|
1,075 |
|
|
|
81 |
|
|
|
7.5 |
% |
|
Global average rig count
|
|
|
3,316 |
|
|
|
2,820 |
|
|
|
496 |
|
|
|
17.6 |
% |
|
Commodity prices (average of daily U.S. dollar prices per unit during period)(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate Cushing, OK crude spot price per barrel in U.S. dollars
|
|
$ |
98.40 |
|
|
$ |
78.35 |
|
|
$ |
20.05 |
|
|
|
25.6 |
% |
|
Henry Hub natural gas spot price per MMBtu in U.S. dollars
|
|
$ |
4.27 |
|
|
$ |
4.70 |
|
|
$ |
(0.43 |
) |
|
|
(9.1 |
)% |
|
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate Cushing, OK crude oil contract (per barrel)
|
|
$ |
98.03 |
|
|
$ |
77.85 |
|
|
$ |
20.18 |
|
|
|
25.9 |
% |
|
Henry Hub Natural Gas contract (per MMBtu)
|
|
$ |
4.65 |
|
|
$ |
5.07 |
|
|
$ |
(0.42 |
) |
|
|
(8.3 |
)% |
(1) Based on average monthly rig count data from Baker Hughes
(2) Source: Bloomberg
The average number of worldwide operating rigs increased during the first quarter of 2011 but declined during the second quarter of 2011 to end the period at a level relatively consistent with the beginning of the year rig count level. Both quarterly movements were largely driven by seasonal trends in Canada. The first six months of 2010 reflected a similar trend, however, the rig count level at the end of June 2010 was up approximately 350 rigs from the level at the beginning of 2010, largely on the strength of increased activity levels in the U.S. Increased U.S. activity levels also accounted for nearly 70% of the average global rig count increase during the first six months of 2011 as compared to the first six months of 2010.
Crude oil prices (West Texas Intermediate, Cushing, OK) continued an upward trend during the first six months of 2011 reaching a high of nearly $114 per barrel in April 2011 before declining during the remainder of the period to the mid-$90 range. Oil prices trended downward at a modest rate during the six months ended June 30, 2010. Average prices for the first half of 2011 were up nearly 26% as compared to the first half of 2010 due to the same factors as discussed previously.
Natural gas (Henry Hub) prices remained relatively stable throughout the first six months of 2011. Prices declined, however, during the first six months of 2010, bottoming near the mid-point of the period before recovering slightly by period-end. The average price per MMBtu in the first half 2011 was $4.27, a 9% decrease from the average price per MMBtu in the first half of 2010. A significant portion of the Company’s business is impacted by the exploration and production of natural gas. Should the 12-month futures strip price for natural gas stay depressed for a long period of time, the portion of the North American rig count directed to gas drilling could decline, which could impact the Company’s future order flow.
Consolidated Results
Net income for the six months ended June 30, 2011 totaled $257.6 million, or $1.03 per diluted share, compared to net income for the six months ended June 30, 2010 of $249.6 million, or $1.01 per diluted share. Included in the results for the first six months of 2011 were charges of $0.17 per diluted share primarily associated with cost overruns on a large subsea project in Nigeria and also a lesser charge to reserve for receivables on work previously performed in Libya that are unlikely to be collected due to sanctions imposed by the United States government and other governments during the first half of 2011.
Total revenues for the Company increased by $442.9 million, or 15.8%, during the six months ended June 30, 2011 as compared to the six months ended June 30, 2010, on the strength of higher sales in each of the Company’s business segments. Nearly 13% of the revenue increase was due to the impact of a weaker U.S. dollar on revenues denominated in other currencies during the first six months of 2011 as compared to the first six months of 2010. Sales in the DPS, V&M and PCS segments are discussed in more detail below.
As a percent of revenues, cost of sales (exclusive of depreciation and amortization) increased from 67.8% during the first half of 2010 to 70.0% for the comparable period in 2011. The increase was due largely to a 2.1 percentage-point margin decrease in the DPS segment, three-fourths of which related to a provision recorded in the first six months of 2011 associated with cost overruns on a large subsea project in Nigeria.
Selling and administrative expenses increased $78.6 million, or 19.6%, during the six months ended June 30, 2011 as compared to the six months ended June 30, 2010. As a percent of revenues, selling and administrative expenses increased from 14.3% during the first half of 2010 to 14.8% for the first half of 2011. This increase was due largely to:
|
|
•
|
approximately $59.9 million of higher employee-related costs resulting mainly from headcount increases and increased incentive compensation,
|
|
|
•
|
a $9.7 million increase in bad debt expense associated primarily with (i) receivables arising from work previously performed in Libya that are unlikely to be collected due to sanctions imposed by the United States government during the first six months of 2011, and (ii) the year-over-year impact of reversals in the first six months of 2010 of certain bad debt reserves upon final collection of amounts due, and
|
|
|
•
|
higher legal and consulting fees.
|
Depreciation and amortization expense decreased $8.6 million, from $101.0 million for the first half of 2010 to $92.4 million for the first half of 2011. The decrease was due mainly to lower amortization of intangible assets.
Net interest for the six months ended June 30, 2011 was $42.2 million, an increase of $5.8 million, from $36.4 million for the six months ended June 30, 2010. The increase was due mainly to a $6.1 million benefit recognized in the first half of 2010 associated with the Company’s interest rate swaps which did not reoccur during the first half of 2011.
For the six months ended June 30, 2011, the Company incurred $29.0 million of costs for BOP litigation and certain employee severance and restructuring-related activities. Included in operating results for the six months ended June 30, 2010 were acquisition integration costs, employee severance, costs for BOP litigation and certain other expenses totaling $28.7 million.
The Company’s effective tax rate for the first half of 2011 was 21.3% compared to 25.0% during the first half of 2010. The tax provision for the first six months of 2011 was lower than the comparable period in 2010, primarily due to:
| |
|
realization of certain tax benefits totaling $16.0 million associated with tax planning strategies put in place in prior years, and
|
| |
|
the recognition of certain historical tax benefits totaling $8.8 million as prior uncertainty regarding those benefits has been resolved during the first half of 2011.
|
Segment Results
DPS Segment –
| |
|
Six Months Ended
June 30,
|
|
|
Increase (Decrease)
|
|
|
($ in millions)
|
|
2011
|
|
|
2010(1)
|
|
|
$ |
|
|
|
% |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,868.3 |
|
|
$ |
1,656.1 |
|
|
$ |
212.2 |
|
|
|
12.8 |
% |
|
Income before income taxes
|
|
$ |
277.6 |
|
|
$ |
302.0 |
|
|
$ |
(24.4 |
) |
|
|
(8.1 |
)% |
|
Income before income taxes as a percent of revenues
|
|
|
14.9 |
% |
|
|
18.2 |
% |
|
|
N/A |
|
|
|
(3.3 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Orders
|
|
$ |
2,261.0 |
|
|
$ |
1,316.5 |
|
|
$ |
944.5 |
|
|
|
71.7 |
% |
|
(1)
|
Revised based on changes in segments described in Note 1 of the Notes to Consolidated Financial Statements.
|
Revenues
The increase in revenues was mainly due to:
|
|
•
|
a 25% increase in sales of surface equipment as a result of higher activity levels in North America and increased shipments to customers in the Middle East and Asia-Pacific regions,
|
|
|
•
|
an 11% increase in sales of drilling equipment as a result of increased demand for stack upgrades, spares and repair services, and
|
|
|
•
|
a 3% increase in subsea equipment sales resulting mainly from a weaker U.S. dollar on revenues denominated in other currencies.
|
Income before income taxes as a percent of revenues
The decrease in the ratio of income before income taxes as a percent of revenues was due primarily to:
|
•
|
a 4.7 percentage-point decrease in margins on drilling and subsea projects, more than half of which was due to a $51.0 million adjustment during the first six months of 2011 related to cost overruns on a large subsea project in Nigeria. Offsetting this decrease were higher volumes of higher-margin surface equipment sales, which increased margins by approximately 1.9 percentage points, and
|
|
•
|
a 0.6 percentage-point increase in the ratio of selling and administrative expenses to revenues as selling and administrative expenses increased 19.6% during the first six months of 2011 as compared to the first six months of 2010 due mainly to higher employee-related costs, which accounted for nearly three-fourths of the increase, and a $7.1 million increase in bad debt expense associated with the uncertain collection of receivables, primarily from certain international customers, including receivables arising from work previously performed in Libya that are unlikely to be collected due to sanctions imposed by the United States government in 2011, as well as the year-over-year impact of the reversal in the first half of 2010 of certain bad debt reserves upon final collection of amounts due.
|
Orders
Drilling orders increased 181% in the first half of 2011 as compared to the same period last year, accounting for 70% of the increase in total segment orders, based on the strength of awards received in 2011 for equipment for nine new deepwater rig construction projects, as well as demand for land and jack-up rig BOPs, stack upgrades, spares, repairs and field service work. Other increases included:
|
|
•
|
a 49% increase in subsea equipment orders, related primarily to projects offshore Brazil and West Africa, and
|
|
|
•
|
a 16% increase in surface equipment orders due mainly to (i) increased demand for aftermarket parts and services as a result of higher North American activity levels caused by higher oil prices and the impact of new shale gas opportunities, and (ii) increased demand for new equipment and aftermarket parts and services from customers in Latin America and the Asia-Pacific region.
|
.
V&M Segment –
| |
|
Six Months Ended
June 30,
|
|
|
Increase
|
|
|
($ in millions)
|
|
2011
|
|
|
2010
|
|
|
$ |
|
|
|
% |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
766.4 |
|
|
$ |
624.4 |
|
|
$ |
142.0 |
|
|
|
22.7 |
% |
|
Income before income taxes
|
|
$ |
130.7 |
|
|
$ |
94.3 |
|
|
$ |
36.4 |
|
|
|
38.6 |
% |
|
Income before income taxes as a percent of revenues
|
|
|
17.1 |
% |
|
|
15.1 |
% |
|
|
N/A |
|
|
|
2.0 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Orders
|
|
$ |
953.9 |
|
|
$ |
740.2 |
|
|
$ |
213.7 |
|
|
|
28.9 |
% |
Revenues
Revenues increased across all product lines as a result of:
|
|
•
|
improved market conditions in North America, particularly in unconventional resource areas, which resulted in a 36% increase in sales of distributed valves and a 13% increase in measurement equipment sales during the six months ended June 30, 2011 as compared to the same period in 2010,
|
|
|
•
|
an increase of 19% in sales of engineered valves due to improving North American activity levels, new subsea pipeline projects and the effects of a weaker U.S. dollar against certain other currencies, and
|
| |
•
|
a 12% increase in process valves sales largely as a result of additional transfer and storage projects in the U.S.
|
Income before income taxes as a percent of revenues
The increase in the ratio of income before income taxes as a percent of revenues was due primarily to:
|
|
•
|
a 0.7 percentage-point decrease in the ratio of cost of sales to revenues due mainly to improved margins in the distributed valves product line due to better pricing and improved volumes,
|
|
|
•
|
a 0.7 percentage-point decrease in the ratio of depreciation and amortization to revenues due mainly to the impact of lower amortization of intangible assets on an increasing revenue base, and
|
|
|
•
|
a 0.6 percentage-point decrease in the ratio of selling and administrative expenses to revenues as selling and administrative expenses did not increase at the same rate as revenues during the current period. Selling and administrative expenses increased 18.6% in the first six months of 2011 as compared to the first six months of 2010, due largely to higher employee-related costs resulting from increased headcount and the full six months’ impact of costs in 2011 associated with an acquisition made in February 2010.
|
Orders
Orders increased in all product lines as follows:
|
|
•
|
engineered valve orders were up 34% based on a large project award in the Gulf of Mexico and increasing demand for pipeline valves in North America and the Asia-Pacific region,
|
|
|
•
|
increased upstream activity levels in North America, particularly in shale gas areas, a more active downstream market and a large project in the Asia-Pacific region contributed to increases of 29% in distributed valve orders and 17% in orders for measurement equipment, and
|
|
|
•
|
the increased need in the U.S. and the Asia-Pacific region for storage and transfer projects led to a 28% increase in orders for process valves.
|
PCS Segment –
| |
|
Six Months Ended
June 30,
|
|
|
Increase
|
|
|
($ in millions)
|
|
2011
|
|
|
2010(1)
|
|
|
$ |
|
|
|
% |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
607.6 |
|
|
$ |
518.9 |
|
|
$ |
88.7 |
|
|
|
17.1 |
% |
|
Income before income taxes
|
|
$ |
64.5 |
|
|
$ |
54.9 |
|
|
$ |
9.6 |
|
|
|
17.5 |
% |
|
Income before income taxes as a percent of revenues
|
|
|
10.6 |
% |
|
|
10.6 |
% |
|
|
N/A |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Orders
|
|
$ |
694.8 |
|
|
$ |
543.3 |
|
|
$ |
151.5 |
|
|
|
27.9 |
% |
|
(1)
|
Revised based on changes in segments described in Note 1 of the Notes to Consolidated Financial Statements.
|
Revenues
The increase in revenues was mostly due to:
|
|
•
|
increased shipments to international customers of high-speed packaged Superior compressors and increased domestic and international spending for replacement parts, resulting in a 54% increase in reciprocating compression product line sales,
|
|
|
•
|
improved industrial economic conditions and demand for new plant air and engineered air units, as well as aftermarket parts and services, which contributed to a 26% increase in sales of centrifugal compression products, and
|
|
|
•
|
increased North American demand for process equipment, which led to a 3% increase in Process Systems sales.
|
Income before income taxes as a percent of revenues
The ratio of income before income taxes as a percent of revenues was flat in the first six months of 2011 as compared to the first six months of 2010 primarily due to:
|
|
•
|
a 2.4 percentage-point increase in the ratio of cost of sales to revenues, due largely to lower margins of approximately 5.2 percentage points in the process systems product line, which was partially offset by higher reciprocating and centrifugal compression equipment margins of 2.7 percentage-points, and
|
|
|
•
|
a 0.4 percentage-point increase in the ratio of selling and administrative costs to revenues as a result of higher employee-related costs due to headcount increases, higher legal and consulting fees and higher bad debt expense largely resulting from the reversal in the first six months of 2010 of a $2.5 million provision recorded in a prior period upon final collection of an overdue balance.
|
This was entirely offset by a decrease of 2.8 percentage points in the ratio of depreciation and amortization to revenues, due mainly to certain intangible assets associated with the NATCO acquisition becoming fully amortized at the end of 2010, as well as lower depreciation expense in the first six months of 2011 due to constrained capital spending in recent periods.
Orders
Orders increased across all major product lines as follows:
|
|
•
|
centrifugal compression equipment orders were up 56% as improving economic conditions led to stronger demand for new plant air and engineered units in North America, Europe and the Asia-Pacific region,
|
|
|
•
|
multi-unit awards for new Ajax units and increased demand for Aftermarket parts led to a 23% increase in reciprocating compression equipment orders, and
|
|
|
•
|
a major project award in China and increased North American demand for process equipment resulted in a 19% increase in process systems bookings in the first six months of 2011 as compared to the same period last year.
|
Corporate Segment –
The $27.2 million increase in the loss before income taxes of the Corporate segment during the first six months of 2011 as compared to the first six months of 2010 (see Note 10 of the Notes to Consolidated Condensed Financial Statements) was due primarily to:
| |
•
|
$9.1 million of foreign currency gains recorded in the first half of 2010 as compared to $1.7 million of foreign currency losses incurred during the first half of 2011,
|
|
|
•
|
an $11.7 million increase in selling and administrative expenses due primarily to higher employee-related costs, and
|
|
|
•
|
higher interest as described in more detail under “Consolidated Results” above.
|
Liquidity and Capital Resources
Consolidated Condensed Statements of Cash Flows
During the first six months of 2011, net cash used for operations totaled $225.3 million, an increase of $69.9 million from the $155.4 million of cash used from operations during the first six months of 2010.
Cash totaling $579.8 million was used to increase working capital during the first half of 2011 compared to $532.0 million during the first half of 2010, an increase of $47.8 million.
During the first six months of 2011, increased sales and the timing of collections, particularly in the drilling, subsea and engineered valves businesses, resulted in higher receivables for the Company at June 30, 2011 as compared to December 31, 2010. In addition, inventory levels increased in all major product lines largely as a result of higher order rates and higher backlog levels. Progress payments and customer advances, mainly in the Company’s project-related businesses, declined $62.2 million during the six months ended June 30, 2011, largely due to the lack of new major drilling and subsea project orders in previous periods and the consumption of previously received advances. These factors, along with certain other items, accounted for the majority of the cash used to increase working capital during the six-month period ended June 30, 2011.
Cash used for investing activities increased by $65.5 million, from $101.4 million during the first six months of 2010 to $166.9 million during the first six months of 2011. This increase was due mainly to higher capital spending during the six months ended June 30, 2011, as the drilling and surface businesses expanded their aftermarket capabilities and for enhancements to the Company’s worldwide SAP information technology platform.
Net cash provided by financing activities totaled $589.1 million for the first half of 2011, mainly reflecting $747.8 million of net cash proceeds received from the public offering of Senior Notes by the Company in June 2011. A portion of these proceeds, totaling $203.1 million, were used to redeem $128.9 million principal amount of the Company’s 2.5% Convertible Debentures at a conversion value of $181.2 million and to acquire call options on 5 million shares of the Company’s common stock. Short-term borrowings, primarily at certain international locations, also increased $31.5 million during the first six months of 2011. During the first six months of 2010, the Company repaid short-term debt totaling $18.7 million and acquired 3,176,705 treasury shares for a total cash cost of $123.9 million.
Future liquidity requirements
The Company expects to spend approximately $300 million for capital equipment and facilities for the full year of 2011.
Additionally, the remaining $371.1 million principal amount of the Company’s 2.5% Convertible Debentures have either been purchased on the open market or redeemed by the Company in July 2011 or have been submitted to the Company for conversion by the holders and will be settled in cash during the third quarter of 2011.
Cash on hand and future expected operating cash flows will be utilized to fund, among other things, the remainder of the Company’s 2011 capital spending program and the redemption of the remaining 2.5% Convertible Debentures, including the conversion value in excess of principal on these debentures.
The Company believes, based on its current financial condition, existing backlog levels and current expectations for future market conditions, that it will be able to meet its short- and longer-term liquidity needs, subject to the outcome of the contingency created by the litigation surrounding the Deepwater Horizon matter, with the existing $2.0 billion of cash on hand, expected cash flow from future operating activities and amounts available under its $835 million five-year multi-currency Revolving Credit Facility, which ultimately expires on June 6, 2016 (see Note 8 of the Notes to Consolidated Condensed Financial Statements for additional information). At June 30, 2011, the amount available for borrowing under the Revolving Credit Facility totaled $809.6 million.
Factors That May Affect Financial Condition and Future Results
The Deepwater Horizon matter may have a material adverse effect on the Company.
See a more complete discussion of the Deepwater Horizon incident in Note 13 of the Notes to Consolidated Condensed Financial Statements.
The Deepwater Horizon matter has and will continue to have an impact on the Company for the foreseeable future. Preparation for and participation in the litigation and investigations regarding this matter will continue to divert Company resources and management’s attention, as well as that of the Company’s Drilling Systems division.
The Company derives a significant portion of its revenues from deepwater activities around the world. In fact, six of the Company’s eleven divisions participate in this market. New regulations imposed by the United States government on drilling activities in deepwater areas of the Gulf of Mexico, as well as similar regulations adopted in other jurisdictions where the Company and its customers do business, could affect a portion of the Company’s business and may cause customers who are involved in deepwater drilling to face additional costs and regulations involving future drilling. While these regulations may decrease drilling activity, they also may require customers to purchase additional components and/or services currently available from the Company and could require the Company to develop new technologies. The Company may also be subject to future regulations regarding the development and testing of our equipment, including our blowout preventers, which may add to the manufacturing cost of such equipment. The Company may be unable to recover such additional costs through higher sales prices, which could negatively impact the Company’s future profitability and cash flows. Other regions are currently considering similar regulations.
Additionally, this event may make it increasingly difficult for the industry to obtain adequate insurance on economic terms, if at all.
If our contractual indemnities are determined to be inapplicable, or the indemnitors fail or are unable to fulfill their contractual indemnity obligations, and if the damages and costs ultimately determined to be the Company’s responsibility exceed our available insurance coverage, we could be liable for amounts which could have a material adverse impact on our financial condition, results of operations and cash flows.
As a designer, manufacturer, installer and servicer of oil and gas pressure control equipment, the Company may be subject to liability, personal injury, property damage and environmental contamination should such equipment fail to perform to specifications.
Cameron provides products and systems that serve customers involved in oil and gas exploration, development and production, as well as in certain industrial markets. Certain of the Company’s equipment is designed to operate in high-temperature, high-pressure environments on land, on offshore platforms and on the seabed. Cameron also provides aftermarket parts and repair services at numerous facilities located around the world or at customer sites. Because of the extreme temperature and pressure environments in which certain of the Company’s equipment operates, a failure of such equipment could cause damage to the equipment, damage to a customer’s other property, personal injury and environmental contamination, whether onshore or offshore. In addition, improper servicing and maintenance of such equipment by Company service technicians or by other third parties can contribute to potential failures of the Company’s equipment. Cameron is currently party to litigation involving personal injury, property damage and environmental contamination alleged to have been caused by failures of the Company’s equipment.
In an attempt to mitigate such risks, the Company has invested in engineering and design tools and equipment to enable engineers to conduct product modeling and simulations. The Company has a quality control program to examine materials received from third-party vendors prior to introducing such materials into the Company’s own manufacturing process and tests its products prior to delivery. Additionally, the Company provides training to its service technicians and seeks to mitigate its financial risks from potential failure of its equipment by maintaining property and casualty insurance coverage, which includes coverage for sudden and accidental environmental pollution.
Downturns in the oil and gas industry have had, and will likely in the future have, a negative effect on the Company’s sales and profitability.
Demand for most of the Company’s products and services, and therefore its revenues, depends to a large extent upon the level of capital expenditures related to oil and gas exploration, production, development, processing and transmission. Declines, as well as anticipated declines, in oil and gas prices could negatively affect the level of these activities, or could result in the cancellation, modification or rescheduling of existing orders. As an example, the substantial decline in oil and gas prices which began during the latter half of 2008 and continued into early 2009, combined with the constricted credit markets during that time, caused reductions in orders by the Company’s customers during 2009 which have, in certain cases, negatively impacted the Company’s 2010 and 2011 revenues and profitability.
The inability of the Company to deliver its backlog on time could affect the Company’s future sales and profitability and its relationships with its customers.
At June 30, 2011, the Company’s backlog was $5.5 billion. The ability to meet customer delivery schedules for this backlog is dependent on a number of factors including, but not limited to, access to the raw materials required for production, an adequately trained and capable workforce, project engineering expertise for large subsea projects, sufficient manufacturing plant capacity and appropriate planning and scheduling of manufacturing resources. Many of the contracts the Company enters into with its customers require long manufacturing lead times and contain penalty or incentive clauses relating to on-time delivery. A failure by the Company to deliver in accordance with customer expectations could subject the Company to financial penalties or loss of financial incentives and may result in damage to existing customer relationships. Additionally, the Company bases its earnings guidance to the financial markets on expectations regarding the timing of delivery of product currently in backlog. Failure to deliver backlog in accordance with expectations could negatively impact the Company’s financial performance and thus cause adverse changes in the market price of the Company’s outstanding common stock and other publicly-traded financial instruments.
A deterioration in future expected profitability or cash flows could result in an impairment of the Company’s goodwill.
Total Cameron goodwill approximated $1.5 billion at June 30, 2011, a large portion of which was allocated to the Company’s Process Systems division, which includes the majority of the NATCO operations acquired in 2009. As a result, any future deterioration in expected annual profitability or annual cash flows or a deterioration of expected markets served by the Company or its Process Systems division could negatively impact the estimated fair market values of both, which, if it were to occur, could increase the likelihood of a goodwill impairment charge being required. No goodwill impairment charge was required based on the Company’s annual evaluation conducted in the first quarter of 2011.
Execution of subsea systems projects exposes the Company to risks not present in its other businesses.
Cameron is a significant participant in serving the subsea systems projects market. This market is significantly different from the Company’s other markets since subsea systems projects are significantly larger in scope and complexity, in terms of both technical and logistical requirements. Subsea projects (i) typically involve long lead times, (ii) typically are larger in financial scope, (iii) typically require substantial engineering resources to meet the technical requirements of the project (iv) often involve the application of existing technology to new environments and in some cases, new technology and (v) can require significant amounts of foreign country, locally manufactured content. The Company’s subsea business unit received orders in the amount of $592.0 million during the six months ended June 30, 2011. Total backlog for the subsea business unit at June 30, 2011 was approximately $2.1 billion. To the extent the Company experiences unplanned efficiencies or difficulties in meeting the technical and/or delivery requirements of the projects, the Company’s earnings or liquidity could be positively or negatively impacted. The Company accounts for its subsea projects, as well as separation and drilling projects, using accounting rules for construction-type and production-type contracts. In accordance with this guidance, the Company estimates the expected margin on these projects and recognizes this margin as units are completed. Factors that may affect future project costs and margins include the ability to properly execute the engineering and design phases consistent with our customers’ expectations, production efficiencies obtained, and the availability and costs of labor, materials and subcomponents. These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future period earnings. If the Company experiences cost underruns or overruns, the expected margin could increase or decline. In accordance with the accounting guidance for construction-type and production-type contracts, the Company would record a cumulative adjustment to increase or reduce the margin previously recorded on the related project in the period a change in estimate is determined. For example, the Company recorded a charge of $51.0 million during the first quarter of 2011 related to cost overruns on one of the Company’s large subsea projects. Continued work stoppages, labor issues and general instability in Nigeria could create further delays in performance of this project, which would have a detrimental effect on future costs and margins. Subsea systems projects accounted for approximately 21.7% of total revenues for the six month period ended June 30, 2011. As of June 30, 2011, the Company had a subsea systems project backlog of approximately $1.1 billion.
Fluctuations in worldwide currency markets can impact the Company’s profitability.
The Company has established multiple “Centers of Excellence” facilities for manufacturing such products as subsea trees, subsea chokes, subsea production controls and BOPs. These production facilities are located in the United Kingdom, Brazil and other European and Asian countries. To the extent the Company sells these products in U.S. dollars, the Company’s profitability is eroded when the U.S. dollar weakens against the British pound, the euro, the Brazilian real and certain Asian currencies, including the Singapore dollar. Alternatively, profitability is enhanced when the U.S. dollar strengthens against these same currencies.
The Company’s worldwide operations expose it to economic risks and instability due to changes in economic conditions, civil unrest, foreign currency fluctuations, trade and other risks inherent to international business.
The economic risks of doing business on a worldwide basis include the following:
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volatility in general economic, social and political conditions;
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The effects of sanctions imposed by the United States government on transactions with Libya, where the Company has $23.2 million of unfilled orders involving equipment scheduled to be delivered to Libya and has recorded a charge in the first half of 2011 with respect to receivables which may be uncollectible from sales made prior to the imposition of sanctions and for impairments of certain other assets related to transactions previously entered into involving Libyan customers;
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the effects of civil unrest on the Company’s business operations, customers and employees, such as that currently occurring in several other countries in the Middle East;
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differing tax rates, tariffs, exchange controls or other similar restrictions;
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changes in currency rates;
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reductions in the number or capacity of qualified personnel.
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Cameron has manufacturing and service operations that are essential parts of its business in developing countries and volatile areas in Africa, Latin America, Russia and other countries that were part of the Former Soviet Union, the Middle East, and Central and South East Asia. The Company also purchases a large portion of its raw materials and components from a relatively small number of foreign suppliers in developing countries. The ability of these suppliers to meet the Company’s demand could be adversely affected by the factors described above.
The Company’s worldwide operations expose it to political risks and uncertainties.
Doing business on a worldwide basis necessarily involves exposing the Company and its operations to political risks and the need for compliance with the laws and regulations of many jurisdictions. These laws and regulations include trade regulations, economic sanctions, restrictions on repatriation of income or capital, and various anti-bribery laws, as well as local content rules and the ever-increasing regulatory burdens being imposed on the oil and gas industry in general, all of which expose the Company to potential liability. They also include restrictions on the industry in accessing available oil and gas reserves, as was recently imposed in the U.S. Gulf of Mexico, and in drilling in environmentally sensitive areas.
Compliance with regulations on trade sanctions and embargoes poses a risk to Cameron since its business is conducted on a worldwide basis through various entities. Cameron has received a number of inquiries from U.S. governmental agencies regarding compliance with these regulations. The most recent of these inquiries was a March 25, 2009, letter from the Office of Global Security Risk of the U.S. Securities and Exchange Commission inquiring into the status of Cameron's non-U.S. entities' withdrawal from conducting business in or with Iran, Syria and Sudan, which begin in mid-2006 and has since been completed.
The Company does business and has operations in a number of developing countries that have relatively underdeveloped legal and regulatory systems when compared to more developed countries. Several of these countries are generally perceived as presenting a higher than normal risk of corruption, or as having a culture where requests for improper payments are not discouraged. Maintaining and administering an effective anti-bribery compliance program under the U.S. Foreign Corrupt Practices Act (FCPA) and the United Kingdom’s Bribery Act of 2010, and similar statutes of other nations in these environments presents greater challenges to the Company than is the case in other, more developed countries. As discussed in Note 13 of the Notes to Consolidated Condensed Financial Statements, the Company has recently concluded an investigation into possible FCPA violations in connection with importation of equipment and supplies into Nigeria.
Increasingly, some of the Company’s customers, particularly the national oil companies, have required a certain percentage, or an increased percentage, of local content in the products they buy directly or indirectly from the Company. This requires the Company to add to or expand manufacturing capabilities in certain countries that are presently without the necessary infrastructure or human resources in place to conduct business in a manner as typically done by Cameron. This increases the risk of untimely deliveries, cost overruns and defective products.
The Company recently completed a Focused Assessment Audit regarding compliance with U.S. customs regulations and has received inquiries regarding compliance with customs laws and regulations from several other countries.
Economic conditions around the world have resulted in decreased tax revenues for many governments, which could lead to changes in tax laws in countries where the Company does business, including the United States. Changes in tax laws could have a negative impact on the Company’s future results.
The Company is subject to environmental, health and safety laws and regulations that expose the Company to potential liability.
The Company’s operations are subject to a variety of national and state, provisional and local laws and regulations, including laws and regulations relating to the protection of the environment. The Company is required to invest financial and managerial resources to comply with these laws and expects to continue to do so in the future. To date, the cost of complying with governmental regulation has not been material, but the fact that such laws or regulations are frequently changed makes it impossible for the Company to predict the cost or impact of such laws and regulations on the Company’s future operations. The modification of existing laws or regulations or the adoption of new laws or regulations imposing more stringent environmental restrictions could adversely affect the Company.
Enacted and proposed climate protection regulations and legislation may impact the Company’s operations or those of its customers.
In December 2009, the United States Environmental Protection Agency (EPA) announced a finding under the United States Clean Air Act that greenhouse gas emissions endanger public health and welfare. The EPA also enacted regulations, effective January 1, 2010, requiring monitoring and reporting by certain facilities and companies of greenhouse gas emissions. Carbon emission reporting and reduction programs have also expanded in recent years at the state, regional and national levels with certain countries having already implemented various types of cap-and-trade programs aimed at reducing carbon emissions from companies that currently emit greenhouse gases, such as electric power generators and utilities.
To the extent Cameron is subject to any of these or other similar proposed or newly enacted laws and regulations, the Company expects that its efforts to monitor, report and comply with such laws and regulations, and any related taxes imposed on companies by such programs, will increase the Company’s cost of doing business in certain jurisdictions, including the United States, and may require expenditures on a number of its facilities and possibly modification of certain of its compression products, which involve use of power generation equipment, in order to lower any direct or indirect emissions of greenhouse gases from those facilities and products.
To the extent the Company’s customers, particularly those involved in power generation, petrochemical processing or petroleum refining, are subject to any of these or other similar proposed or newly enacted laws and regulations, the Company is exposed to risks that the additional costs by customers to comply with such laws and regulations could impact their ability or desire to continue to operate at similar levels in certain jurisdictions as historically seen or as currently anticipated, which could negatively impact their demand for the Company’s products and services.
The Company could also be impacted by new laws and regulations establishing cap-and-trade and those that might favor the increased use of non-fossil fuels, including nuclear, wind, solar and bio-fuels or that are designed to increase energy efficiency. If the proposed or newly executed laws dampen demand for oil and gas production, they could lower spending by the Company’s customers for the Company’s products and services.
In addition, environmental concerns have been raised regarding the potential impact on underground water supplies of a procedure known as hydraulic fracturing, which involves the pumping of water and certain chemicals under pressure into a well to break apart shale and other rock formations in order to increase the flow of oil and gas embedded in these formations to the surface for recovery. The Company provides equipment and services to companies employing this enhanced recovery technique. Should governmental regulations be imposed that restrict this practice, the Company’s revenues and earnings could be negatively impacted.
Environmental Remediation
The Company’s worldwide operations are subject to domestic and international regulations with regard to air, soil and water quality as well as other environmental matters. The Company, through its environmental management system and active third-party audit program, believes it is in substantial compliance with these regulations.
The Company is currently identified as a potentially responsible party (PRP) with respect to two sites designated for cleanup under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) or similar state laws. One of these sites is Osborne, Pennsylvania (a landfill into which a predecessor of the PCS operation in Grove City, Pennsylvania deposited waste), where remediation is complete and remaining costs relate to ongoing ground water treatment and monitoring. The other is believed to be a de minimis exposure. The Company is also engaged in site cleanup under the Voluntary Cleanup Plan of the Texas Commission on Environmental Quality at former manufacturing locations in Houston and Missouri City, Texas. Additionally, the Company has discontinued operations at a number of other sites which had been active for many years. The Company does not believe, based upon information currently available, that there are any material environmental liabilities existing at these locations. At June 30, 2011, the Company’s consolidated balance sheet included a noncurrent liability of $5.8 million for environmental matters.
Environmental Sustainability
The Company has pursued environmental sustainability in a number of ways. Processes are monitored in an attempt to produce the least amount of waste. None of the Company’s facilities are rated above Small Quantity Generated status. All of the waste disposal firms used by the Company are carefully selected in an attempt to prevent any future Superfund involvements. Actions are taken in an attempt to minimize the generation of hazardous wastes and to minimize air emissions. None of the Company’s facilities are classified as sites that generate more than minimal air emissions. Recycling of process water is a common practice. Best management practices are used in an effort to prevent contamination of soil and ground water on the Company’s sites.
Under the direction of its corporate Vice President, Operations Integrity, Cameron has implemented a corporate “HSE Management System” based on the principles of ISO 14001 and OHSAS 18001. The HSE Management System contains a set of corporate standards that are required to be implemented and verified by each business unit. Cameron also has developed a corporate compliance audit program to address facility compliance with environmental, health and safety laws and regulations. The compliance program utilizes independent third party auditors to audit facilities on a regular basis specific to country, region, and local legal requirements. Audit reports are circulated to the senior management of the Company and to the appropriate business unit. The compliance program requires corrective and preventative actions be taken by a facility to remedy all findings of non-compliance. Audit findings and corrective action plans are incorporated into and tracked on the corporate HSE data base.
The Company is currently exposed to market risk from changes in foreign currency exchange rates, changes in the value of its equity instruments and changes in interest rates. A discussion of the Company’s market risk exposure in financial instruments follows.
Foreign Currency Exchange Rates
A large portion of the Company’s operations consist of manufacturing and sales activities in foreign jurisdictions, principally in Europe, Canada, West Africa, the Middle East, Latin America and the Pacific Rim. As a result, the Company’s financial performance may be affected by changes in foreign currency exchange rates in these markets. Overall, for those locations where the Company is a net receiver of local non-U.S. dollar currencies, Cameron generally benefits from a weaker U.S. dollar with respect to those currencies. Alternatively, for those locations where the Company is a net payer of local non-U.S. dollar currencies, a weaker U.S. dollar with respect to those currencies will generally have an adverse impact on the Company’s financial results. The impact on the Company’s financial results of gains or losses arising from foreign currency denominated transactions, if material, have been described under “Results of Operations” in this Management’s Discussion and Analysis of Financial Condition and Results of Operations for the periods shown.
In order to mitigate the effect of exchange rate changes, the Company will often attempt to structure sales contracts to provide for collections from customers in the currency in which the Company incurs its manufacturing costs. In certain instances, the Company will enter into foreign currency forward contracts to hedge specific large anticipated receipts or disbursements in currencies for which the Company does not traditionally have fully offsetting local currency expenditures or receipts. The Company was party to a number of long-term foreign currency forward contracts at June 30, 2011. The purpose of the majority of these contracts was to hedge large anticipated non-functional currency cash flows on major subsea, drilling, valve or other equipment contracts involving the Company’s United States operations and its wholly-owned subsidiaries in Italy, Romania, Singapore and the United Kingdom. At June 30, 2011, the Company was also party to certain foreign currency forward and foreign currency option contracts, which have not been accounted for as hedges under the accounting rules for derivatives and hedging activities, involving underlying foreign currency denominated accounts recorded on the balance sheet of its wholly-owned subsidiary in Canada or anticipated foreign currency cash flows of its wholly-owned subsidiary in Italy.
Capital Markets and Interest Rates
The Company is subject to market risk relating to the value of its common stock as traded on the New York Stock Exchange and on the value of options on its common stock. At June 30, 2011, the Company holds call options covering 5 million shares of its common stock. The value of the options are impacted by, among other things, changes in the per share value of the Company’s common stock and the time to maturity of the options. Changes in the fair value of the call options are recognized in earnings in the period in which the change occurs.
The Company is subject to interest rate risk on its variable-interest rate borrowings and interest rate swaps. Variable-rate debt, where the interest rate fluctuates periodically, exposes the Company’s cash flows to variability due to changes in market interest rates. Additionally, the fair value of the Company’s fixed-rate debt changes with changes in market interest rates.
The Company manages its debt portfolio to achieve an overall desired position of fixed and floating rates and employs interest rate swaps as a tool to achieve that goal. The major risks from interest rate derivatives include changes in the interest rates affecting the fair value of such instruments, potential increases in interest expense due to market increases in floating interest rates and the creditworthiness of the counterparties in such transactions.
The fair values of the 4.5% and 6.375% 10-year Senior Notes and the 5.95% and 7.0% 30-year Senior Notes are principally dependent on prevailing interest rates. The fair value of the 2.5% Convertible Debentures is principally dependent on prevailing interest rates and the Company’s current share price as it relates to the initial conversion price of the instrument.
The Company has various other long-term debt instruments, but believes that the impact of changes in interest rates in the near term will not be material to these instruments.
At June 30, 2011, the Company was a party to three interest rate swaps which effectively reduce the Company’s rate on $400.0 million of its 6.375% fixed rate borrowings to an effective fixed interest rate of approximately 5.49% through January 15, 2012, the maturity date of all three swaps. Each of the swaps provide for semiannual interest payments and receipts each January 15 and July 15 and provide for resets of the 3-month LIBOR rate to the then existing rate each January 15, April 15, July 15 and October 15. At June 30, 2011, the fair value of the interest rate swaps was reflected on the Company’s consolidated balance sheet as an asset with the change in the fair value of the swaps reflected as an adjustment to the Company’s consolidated interest expense.
Item 4. Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, the Company carried out an evaluation, under the supervision and with the participation of the Company’s Disclosure Committee and the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2011 to ensure that information required to be disclosed by the Company that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There were no material changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2011.
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
Deepwater Horizon Matter
As described further in Note 13 of the Notes to Consolidated Condensed Financial Statements, claims for personal injury, wrongful death and property damage arising from the Deepwater Horizon incident have been and will continue to be asserted against the Company. Additionally, claims for pollution and other economic damages, including business interruption and loss of revenue, have been, and we anticipate will continue to be, asserted against all parties associated with this incident, including the Company, BP p.l.c. and certain of its subsidiaries, the operator of Mississippi Canyon Block 252 upon which the Macondo well was being drilled, Transocean Ltd. and certain of its affiliates, the rig owner and operator, as well as other equipment and service companies. The Company has been named as one of several defendants in over 350 suits filed and presently pending in a variety of Federal and State courts, a number of which have been filed as class actions or multi-plaintiff actions. Other defendants including BP, Transocean and Halliburton have asserted cross-claims against us as we have asserted such claims against them. Most of the suits pending and presently pending in Federal courts have been consolidated into a single proceeding before a single Federal judge under the Federal rules governing multi-district litigation. The consolidated case is styled In Re: Oil Spill by the Oil Rig “Deepwater Horizon” in the Gulf of Mexico on April 20, 2010, MDL Docket No. 2179. There are also a small number of cases filed and presently pending in state courts. The States of Alabama and Louisiana have brought a claim for destruction of and/or harm to natural resources against those associated with this incident, including Cameron, in State of Alabama, ex. rel. Troy King, Attorney General vs. Transocean Ltd., et. al., Cause No. 2:10cv00691, U.S. Dist. Ct., M.D. Ala., and State of Louisiana vs. BP Exploration & Production , Inc., et. al. MDL No. 2179, as have a number of other local governmental entities and 3 Mexican states. It is possible other such claims may be asserted against the Company by the United States Government (USG) and by other Gulf and/or East Coast States, whose Attorneys General have notified the Company to preserve documents in the event of a claim, and possibly by other parties. The USG has brought suit against BP and certain other parties associated with this incident for recovery under statutes such as the Oil Pollution Act of 1990 (OPA) and the Clean Water Act, which suit has been made part of the MDL proceedings. While the Company was not named as a defendant in this suit by the USG, BP has brought a third-party complaint for contribution under OPA against several parties associated with this incident which were not named by the USG, including the Company. A shareholder derivative suit, Berzner vs. Erikson, et al., Cause No. 2010-71817 in the 190th District Court of Harris County, Texas, has been filed against the Company’s directors in connection with this incident and its aftermath alleging the Company’s directors failed to exercise their fiduciary duties regarding the safety and efficacy of its products.
The Federal Court overseeing the multi-district litigation has ruled that it will begin trying liability issues arising out of the Deepwater Horizon Matter in February 2012, and has issued a number of orders to effectuate this scheduling.
The Company has retained counsel and is, along with counsel, actively participating in the investigation into this matter and the litigation, and its attendant discovery, arising out of this matter. Our counsel are currently evaluating the theories of recovery being relied on by the claimants and cross-claimants and the damages they are asserting as well as our defenses, both factual and legal. Through June 30, 2011, the Company had incurred and expensed legal fees of $34.8 million. The Company has not accrued any amounts relating to this matter because we do not believe at the present time a loss is probable.
The information set forth under the caption “Factors That May Affect Financial Condition and Future Results” on pages 32 – 36 of this Quarterly Report on Form 10-Q is incorporated herein by reference.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Under a resolution adopted by the Board of Directors on February 21, 2008, the Company is authorized to purchase up to 30,000,000 shares of its Common Stock. Additionally, on May 22, 2006, the Company’s Board of Directors approved repurchasing shares of the Company’s common stock with the proceeds remaining from the Company’s 2.5% Convertible Debenture offering, after taking into account a planned repayment of $200,000,000 principal amount of the Company’s outstanding 2.65% senior notes due 2007. This authorization is in addition to the 30,000,000 shares described above.
Purchases pursuant to the 30,000,000-share Board authorization may be made by way of open market purchases, directly or indirectly, for the Company’s own account or through commercial banks or financial institutions and by the use of derivatives such as a sale or put on the Company’s common stock or by forward or economically equivalent transactions. There were no shares of common stock purchased and placed in treasury during the three- and six-month periods ended June 30, 2011 under the Board’s two authorization programs described above. At June 30, 2011, the Company had previously purchased 29,658,873 shares under the above authorizations and had authority to purchase an additional 2,995,897 shares of its common stock in the future.
During the second quarter of 2011, the Company entered into an agreement with a third party financial intermediary for the purchase of 5.0 million call options on its common stock at an average strike price of $47.69 per share. If the individual options are “in-the-money” upon expiration at various dates during August 2011, the option value will be settled on a net-cash basis with the third party financial intermediary, otherwise, the options will be allowed to expire if they have no value to the Company at that time.
Item 3. Defaults Upon Senior Securities
None
N/A
Item 5. Other Information
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(a)
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Information Not Previously Reported in a Report on Form 8-K
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None
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(b)
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Material Changes to the Procedures by Which Security Holders May Recommend Board Nominees.
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There have been no material changes to the procedures enumerated in the Company’s definitive proxy statement filed on Schedule 14A with the Securities and Exchange Commission on March 24, 2011 with respect to the procedures by which security holders may recommend nominees to the Company’s Board of Directors.
Exhibit 31.1 –
Certification
Exhibit 31.2 –
Certification
Exhibit 32.1 –
Certification of the CEO and CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 101.INS –
XBRL Instance Document
Exhibit 101.SCH –
XBRL Taxonomy Extension Schema Document
Exhibit 101. CAL –
XBRL Taxonomy Extension Calculation Linkbase Document
Exhibit 101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
Exhibit 101.LAB –
XBRL Taxonomy Extension Label Linkbase Document
Exhibit 101.PRE –
XBRL Taxonomy Extension Presentation Linkbase Document
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.
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Date: July 29, 2011
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CAMERON INTERNATIONAL CORPORATION
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(Registrant)
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By: /s/ Charles M. Sledge
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Charles M. Sledge
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Senior Vice President and Chief Financial Officer
and authorized to sign on behalf of the Registrant
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EXHIBIT INDEX
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Exhibit Number
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Description
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31.1
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Certification
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31.2
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Certification
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32.1
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Certification of the CEO and CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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101.INS
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XBRL Instance Document
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101.SCH
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XBRL Taxonomy Extension Schema Document
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101.CAL
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XBRL Extension Calculation Linkbase Document
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101.DEF
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XBRL Taxonomy Extension Definition Linkbase Document
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101.LAB
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XBRL Taxonomy Extension Label Linkbase Document
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101.PRE
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XBRL Taxonomy Extension Presentation Linkbase Document
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42