10-Q 1 form10-q.htm FORM 10-Q - 2ND QTR 2011 form10-q.htm



UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q
 
(Mark One)
 
 
R
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the Quarterly Period Ended June 30, 2011
 
OR
 
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 

Commission File Number 1-13884
Cameron International Corporation
(Exact Name of Registrant as Specified in its Charter)

Delaware
76-0451843
(State or Other Jurisdiction of
(I.R.S. Employer
Incorporation or Organization)
Identification No.)
   
1333 West Loop South, Suite 1700, Houston, Texas
77027
(Address of Principal Executive Offices)
(Zip Code)

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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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)

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(unaudited)
 
                         
REVENUES
  $ 1,741.1     $ 1,452.7     $ 3,242.3     $ 2,799.4  
COSTS AND EXPENSES
                               
Cost of sales (exclusive of depreciation and amortization shown separately below)
    1,213.4       984.7       2,271.2       1,898.8  
Selling and administrative expenses
    250.5       205.0       480.3       401.7  
Depreciation and amortization
    47.6       52.9       92.4       101.0  
Interest, net
    22.1       19.4       42.2       36.4  
Other costs (see Note 3)
    20.1       18.4       29.0       28.7  
Total costs and expenses
    1,553.7       1,280.4       2,915.1       2,466.6  
Income before income taxes
    187.4       172.3       327.2       332.8  
Income tax provision
    (39.4 )     (43.1 )     (69.6 )     (83.2 )
Net income
  $ 148.0     $ 129.2     $ 257.6     $ 249.6  
Earnings per common share:
                               
Basic
  $ 0.60     $ 0.53     $ 1.05     $ 1.02  
Diluted
  $ 0.59     $ 0.52     $ 1.03     $ 1.01  
Shares used in computing earnings per common share:
                               
Basic
    245.0       242.9       244.8       243.6  
Diluted
    249.9       246.4       251.1       247.7  

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)
 
   
June 30,
2011
   
December 31,
2010
 
   
(unaudited)
       
ASSETS
           
Cash and cash equivalents
  $ 2,043.1     $ 1,832.5  
Receivables, net
    1,287.8       1,056.1  
Inventories, net
    2,108.0       1,779.3  
Other
    268.5       265.0  
Total current assets
    5,707.4       4,932.9  
Plant and equipment, net
    1,342.4       1,247.8  
Goodwill
    1,531.3       1,475.8  
Other assets
    345.9       348.6  
TOTAL ASSETS
  $ 8,927.0     $ 8,005.1  
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current portion of long-term debt
  $ 431.0     $ 519.9  
Accounts payable and accrued liabilities
    1,928.4       2,016.0  
Accrued income taxes
    23.8       38.0  
Total current liabilities
    2,383.2       2,573.9  
Long-term debt
    1,523.6       772.9  
Deferred income taxes
    85.5       95.7  
Other long-term liabilities
    193.2       170.2  
Total liabilities
    4,185.5       3,612.7  
Stockholders’ Equity:
               
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
    2.6       2.6  
Capital in excess of par value
    2,215.2       2,259.3  
Retained earnings
    3,105.9       2,848.3  
Accumulated other elements of comprehensive income (loss)
    77.9       (27.1 )
Less: Treasury stock, 18,045,968 shares at June 30, 2011
(19,197,642 shares at December 31, 2010)
    (660.1 )     (690.7 )
Total stockholders’ equity
    4,741.5       4,392.4  
TOTAL LIABILITIES AND  STOCKHOLDERS’ EQUITY
  $ 8,927.0     $ 8,005.1  

The accompanying notes are an integral part of these statements.


 

 
 
 
CAMERON INTERNATIONAL CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(dollars in millions)
 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2011
   
2010
   
2011
   
2010
 
   
(unaudited)
Cash flows from operating activities:
                       
Net income
   
148.0
     
129.2
     
257.6
     
249.6
 
Adjustments to reconcile net income to net cash provided by (used for) operating activities:
                               
    Depreciation
   
37.6
     
37.6
     
72.2
     
71.4
 
Amortization
   
10.0
     
15.3
     
20.2
     
29.6
 
Non-cash stock compensation expense
   
9.4
     
6.4
     
17.5
     
18.5
 
Deferred income taxes and tax benefit of employee stock compensation plan transactions
   
(31.8
)
   
12.9
     
(13.0
)
   
7.5
 
Changes in assets and liabilities, net of translation, acquisitions and non-cash  items:
                               
Receivables
   
(169.5
)
   
(39.8
)
   
(201.2
)
   
20.1
 
Inventories
   
(111.5
)
   
(21.9
)
   
(285.0
)
   
(65.9
)
Accounts payable and accrued liabilities
   
115.9
     
(139.8
)
   
(133.4
)
   
(367.5
)
Other assets and liabilities, net
   
93.3
     
(39.6
)
   
39.8
     
(118.7
)
Net cash provided by (used for) operating activities
   
101.4
     
(39.7
)
   
(225.3
)
   
(155.4
)
Cash flows from investing activities:
                               
Capital expenditures
   
(72.4
)
   
(38.2
)
   
(134.3
)
   
(68.1
)
Acquisitions, net of cash acquired
   
(14.9
)
   
(13.0
)
   
(42.5
)
   
(40.9
)
Proceeds from sale of plant and equipment
   
3.2
     
4.7
     
9.9
     
7.6
 
Net cash used for investing activities
   
(84.1
)
   
(46.5
)
   
(166.9
)
   
(101.4
)
Cash flows from financing activities:
                               
Short-term loan borrowings (repayments), net
   
33.5
     
(2.1
)
   
31.5
     
(18.7
)
Issuance of senior debt
   
747.8
     
     
747.8
     
 
Debt issuance costs
   
(4.7
)
   
     
(4.7
)
   
 
Redemption of convertible debentures
   
(181.2
)
   
     
(181.2
)
   
 
Premium for purchased call options
   
(21.9
)
   
     
(21.9
)
   
 
Purchase of treasury stock
   
     
(84.1
)
   
     
(123.9
)
Proceeds from stock option exercises, net of tax  payments from stock compensation plan transactions
   
0.9
     
(5.7
   
16.6
     
(12.2
)
Excess tax benefits from employee stock compensation plan transactions
   
0.1
     
1.5
     
4.8
     
5.4
 
Principal payments on capital leases
   
(2.0
)
   
(1.7
)
   
(3.8
)
   
(3.3
)
Net cash provided by (used for) financing activities
   
572.5
     
(92.1
)
   
589.1
     
(152.7
)
Effect of translation on cash
   
3.7
     
(12.2
)
   
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
 
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,
 
   
2011
   
2010
   
2011
   
2010
 
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,
 
   
2011
   
2010
   
2011
   
2010
 
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,
 
   
2011
   
2010
   
2011
   
2010
 
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.

Environmental Matters

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):
 
   
June 30, 2011
   
December 31, 2010
 
   
Principal
   
Fair Value
   
Principal
   
Fair Value
 
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:

   
June 30, 2011
   
December 31, 2010
 
   
Assets
   
Liabilities
   
Assets
   
Liabilities
 
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,
 
 
2011
   
2010
   
2011
   
2010
   
2011
   
2010
 
   
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,
 
 
2011
   
2010
   
2011
   
2010
   
2011
   
2010
 
   
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,
 
   
2011
   
2010
   
2011
   
2010
 
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.

 
Orders

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.

 
 
Backlog (at period-end)
 
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.