UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

(Mark One) 
RQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 20142015
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)

Delaware76-0451843
(State or Other Jurisdiction of(I.R.S. Employer
Incorporation or Organization)Identification No.)
 
1333 West Loop South, Suite 1700, Houston, Texas77027
(Address of Principal Executive Offices)(Zip Code)

713/513-3300
(Registrant'sRegistrant’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“large accelerated filer"filer”, "accelerated filer"“accelerated filer” and "smaller“smaller reporting company"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'sissuer’s common stock as of July 17, 201415, 2015 was 202,901,463.191,514,291.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
3
Item 1.
Financial Statements
3
Consolidated Condensed Statements of Comprehensive Income
3
Consolidated Condensed Balance Sheets
4
Consolidated Condensed Statements of Cash Flows
5
Consolidated Condensed Statement of Changes in Equity
6
Notes to Consolidated Condensed Financial Statements
7
Item 2. Management's
Management’s Discussion and Analysis of Financial Condition and Results of Operations
  1920
Item 3.
Quantitative and Qualitative Disclosures Aboutabout Market Risk
  3940
Item 4.
Controls and Procedures
  3941
PART II — OTHER INFORMATION
  4042
Item 1.
Legal Proceedings
  4042
Item 1A. 
Risk Factors
  4042
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
  4042
Item 3.
Defaults Upon Senior Securities
  4042
Item 4.
Mine Safety Disclosures
  4042
Item 5.
Other Information
  4143
Item 6.
Exhibits
  4143
SIGNATURES
  4244
 

2
Table of Contents
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Cameron International Corporation
CAMERON INTERNATIONAL CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOMEConsolidated Condensed Statements of Comprehensive Income
(dollars and shares in millions, except per share data)

 
Three Months Ended
June 30,
  
Six Months Ended
June 30,
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 2014  2013  2014  2013  2015  2014  2015  2014 
 (unaudited)  (unaudited) 
 
  
  
  
   
REVENUES $2,641  $2,209  $5,072  $4,270  $2,222  $2,570  $4,495  $4,899 
COSTS AND EXPENSES:                                
Cost of sales (exclusive of depreciation and amortization shown separately below)
  1,893   1,567   3,658   3,020   1,585   1,850   
3,193
   3,540 
Selling and administrative expenses  346   315   675   618   279   333   565   651 
Depreciation and amortization  90   67   177   135   89   88   178   173 
Interest, net  30   25   62   51   33   30   71   62 
Other costs (credits) (see Note 3)  (4)  35   44   66 
Other costs (gains), net (see Note 3)  37   (6)  614   43 
Total costs and expenses  2,355   2,009   4,616   3,890   2,023   2,295   4,621   4,469 
                                
Income from continuing operations before income taxes  286   200   456   380 
Income (loss) from continuing operations before income taxes  199   275   (126)  430 
Income tax provision  (66)  (64)  (114)  (97)  (47)  (65)  (100)  (110)
Income from continuing operations  220   136   342   283 
Income (loss) from continuing operations  152   210   (226)  320 
Income from discontinued operations, net of income taxes  13   4   7   6   3   23   432   28 
Net income  233   140   349   289   155   233   206   348 
                                
Net income attributable to noncontrolling interests  12   –   17   – 
Less: Net income attributable to noncontrolling interests  15   12   17   16 
Net income attributable to Cameron stockholders $221  $140  $332  $289  $140  $221  $189  $332 
                                
Amounts attributable to Cameron stockholders:                                
Income from continuing operations $208  $136  $325  $283 
Income (loss) from continuing operations $137  $198  $(243) $304 
Income from discontinued operations  13   4   7   6   3   23   432   28 
Net income attributable to Cameron stockholders $221  $140  $332  $289  $140  $221  $189  $332 
                                
Earnings per common share attributable to Cameron stockholders:                
Basic                
Earnings (loss) per common share attributable to Cameron stockholders:                
Basic -                
Continuing operations $1.02  $0.55  $1.55  $1.15  $0.71  $0.97  $(1.27) $1.46 
Discontinued operations  0.06   0.02   0.04   0.02   0.02   0.11   2.25   0.13 
Basic earnings per share $0.73  $1.08  $0.98  $1.59 
 $1.08  $0.57  $1.59  $1.17                 
                
Diluted                
Diluted -                
Continuing operations $1.02  $0.55  $1.54  $1.14  $0.71  $0.97  $(1.27) $1.44 
Discontinued operations  0.06   0.02   0.04   0.02   0.02   0.11   2.25   0.13 
 $1.08  $0.57  $1.58  $1.16 
Diluted earnings per share $0.73  $1.08  $0.98  $1.57 
Shares used in computing earnings per common share:
                                
Basic  204   247   209   247   191   204   192   209 
Diluted  205   248   211   249   192   205   192   211 
                                
Comprehensive income $218  $91  $360  $163  $261  $218  $22  $359 
Comprehensive income attributable to noncontrolling interests  4   –   24   – 
Less: Comprehensive income (loss) attributable to noncontrolling interests  49   4   (14)  23 
Comprehensive income attributable to Cameron stockholders $214  $91  $336  $163  $212  $214  $36  $336 

The accompanying notes are an integral part of these statements.
3
Table of Contents

CAMERON INTERNATIONAL CORPORATIONCameron International Corporation
CONSOLIDATED CONDENSED BALANCE SHEETSConsolidated Condensed Balance Sheets
(dollars in millions, except shares and per share data)


 
June 30,
2014
  
December 31,
2013
  
June 30,
2015
  
December 31,
2014
 
 (unaudited)  
  (unaudited)   
ASSETS 
  
     
Cash and cash equivalents $1,525  $1,813  $1,295  $1,513 
Short-term investments  56   41   436   113 
Receivables, net  2,548   2,719   2,096   2,389 
Inventories, net  3,268   3,133   2,938   2,929 
Other  385   463 
Other current assets  390   391 
Assets of discontinued operations  –   217 
Total current assets  7,782   8,169   7,155   7,552 
Plant and equipment, net  2,015   2,037   1,814   1,964 
Goodwill  2,704   2,925   1,880   2,461 
Intangibles, net  856   904   683   728 
Other assets  235   214   200   187 
TOTAL ASSETS $13,592  $14,249  $11,732  $12,892 
                
LIABILITIES AND STOCKHOLDERS' EQUITY        
LIABILITIES AND STOCKHOLDERS’ EQUITY        
Short-term debt $562  $297  $31  $263 
Accounts payable and accrued liabilities  3,506   3,883   2,933   3,748 
Accrued income taxes  100   80   298   168 
Liabilities of discontinued operations  –   90 
Total current liabilities  4,168   4,260   3,262   4,269 
Long-term debt  2,814   2,563   2,813   2,819 
Deferred income taxes  251   277   180   193 
Other long-term liabilities  229   233   167   167 
Total liabilities  7,462   7,333   6,422   7,448 
Stockholders' Equity:
        
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at June 30, 2014 and December 31, 2013
  3   3 
Stockholders’ Equity:        
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at June 30, 2015 and December 31, 2014  3   3 
Capital in excess of par value  3,220   3,207   3,242   3,255 
Retained earnings  5,152   4,820   5,820   5,631 
Accumulated other elements of comprehensive income (loss)  (76)  (80)  (693)  (540)
Less: Treasury stock, 60,027,350 shares at June 30, 2014
(41,683,164 shares at December 31, 2013)
  (3,261)  (2,098)
Total Cameron stockholders' equity  5,038   5,852 
Less: Treasury stock, 71,671,246 shares at June 30, 2015 (68,139,027 shares at December 31, 2014)  (3,955)  (3,794)
Total Cameron stockholders’ equity  4,417   4,555 
Noncontrolling interests  1,092   1,064   893   889 
Total equity  6,130   6,916   5,310   5,444 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $13,592  $14,249 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $11,732  $12,892 

The accompanying notes are an integral part of these statements.
4
CAMERON INTERNATIONAL CORPORATIONCameron International Corporation
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(dollars in millions)
 
 
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 
 2014  2013  2014  2013 
 
 (unaudited) 
 
 
  
  
  
 
Cash flows from operating activities: 
  
  
  
 
Net income $233  $140  $349  $289 
Adjustments to reconcile net income to net cash provided by operating activities:                
Gain on sale of Reciprocating Compression business  (95)  –   (95)  – 
Depreciation  71   59   139   115 
Amortization  19   11   38   25 
Non-cash stock compensation expense  15   14   30   27 
Gain from remeasurement of prior interest in equity method investment  (8)  –   (8)  – 
Deferred income taxes and tax benefit of  employee stock compensation plan transactions
  34   (2)  17   12 
Changes in assets and liabilities, net of translation, and non-cash  items:
                
Receivables  171   (236)  111   (71)
Inventories  (53)  (124)  (228)  (340)
Accounts payable and accrued liabilities  (257)  212   (471)  7 
Other assets and liabilities, net  83   (44)  157   (57)
Net cash provided by operating  activities
  213   30   39   7 
Cash flows from investing activities:                
Proceeds from sales and maturities of short-term investments  18   353   23   628 
Purchases of short-term investments  (33)  (135)  (38)  (421)
Capital expenditures  (73)  (99)  (178)  (182)
Proceeds received from sale of Reciprocating Compression business, net  547   –   547   – 
Other dispositions (acquisitions), net  (18)  8   (18)  9 
Proceeds received and cash acquired from
formation of OneSubsea
  –   603   –   603 
Proceeds from sales of plant and equipment  4   3   10   4 
Net cash provided by investing activities  445   733   346   641 
Cash flows from financing activities:                
Issuance of senior notes  500   –   500   – 
Debt issuance costs  (4)  –   (4)  – 
Short-term loan borrowings (repayments), net  (321)  (28)  9   9 
Purchase of treasury stock  (303)  (93)  (1,205)  (125)
Proceeds from stock option exercises, net of tax payments from stock compensation plan transactions  16   7   25   29 
Excess tax benefits from employee stock compensation plan transactions  4   2   6   8 
Principal payments on capital leases  (5)  (7)  (8)  (10)
Net cash used for financing activities  (113)  (119)  (677)  (89)
Effect of translation on cash  8   (8)  4   (27)
Increase (decrease) in cash and cash equivalents  553   636   (288)  532 
Cash and cash equivalents, beginning of period  972   1,082   1,813   1,186 
Cash and cash equivalents, end of period $1,525  $1,718  $1,525  $1,718 

The accompanying notes are an integral partConsolidated Condensed Statements of these statements.

CAMERON INTERNATIONAL CORPORATION
CONSOLIDATED CONDENSED STATEMENT OF CHANGES IN EQUITYCash Flows
(dollars in millions)

 
 Cameron Stockholders  
 
 
 Common Stock  Capital in Excess of Par Value  Retained Earnings  
Accumulated Other
Elements of Comprehensive Income (Loss)
  Treasury Stock  Noncontrolling Interests 
 
 (Unaudited)  
 
 
 
  
  
  
  
  
 
Balance at December 31, 2013 $3  $3,207  $4,820  $(80) $(2,098) $1,064 
Net income  –   –   332   –   –   17 
Other comprehensive income (loss), net of tax  –   –   –   4   –   7 
Non-cash stock compensation expense  –   30   –   –   –   – 
Purchase of treasury stock  –   –   –   –   (1,210)  – 
Treasury stock issued under stock compensation plans  –   (22)  –   –   47   – 
Tax benefit of stock compensation plan transactions  –   5   –   –   –   – 
Purchase of noncontrolling ownership interests  –   –   –   –   –   4 
Balance at June 30, 2014 $3  $3,220  $5,152  $(76) $(3,261) $1,092 

  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
  2015  2014  2015  2014 
  (unaudited) 
         
Cash flows from operating activities:        
Net income $155  $233  $206  $348 
Adjustments to reconcile net income to net cash provided by (used for) operating activities:                
Asset impairment and other charges  10   4   563   44 
Pre-tax gain on sale of Compression businesses  –   (95)  (681)  (95)
Depreciation  77   71   152   139 
Amortization  12   19   26   38 
Non-cash stock compensation expense  13   15   23   30 
Gain from remeasurement of prior interest in equity method investment  –   (8)  –   (8)
Deferred income taxes and tax benefit of employee stock compensation plan transactions  (14)  34   (15)  17 
Changes in assets and liabilities, net of translation, and non-cash items:                
Receivables  104   171   252   111 
Inventories  35   (53)  (70)  (228)
Accounts payable and accrued liabilities  (284)  (257)  (755)  (471)
Other assets and liabilities, net  (80)  79   134   114 
Net cash provided by (used for) operating activities  28   213   (165)  39 
Cash flows from investing activities:                
Proceeds received from sale of Compression businesses, net  –   547   832   547 
Proceeds from sales and maturities of short-term investments  252   18   400   23 
Purchases of short-term investments  (264)  (33)  (723)  (38)
Capital expenditures  (41)  (73)  (130)  (178)
Acquisitions  –   (18)  –   (18)
Proceeds from sales of plant and equipment  2   4   7   10 
Net cash provided by (used for) investing activities  (51)  445   386   346 
Cash flows from financing activities:                
Issuance of senior notes  –   500   –   500 
Debt issuance costs  –   (4)  –   (4)
Short-term loan borrowings (repayments), net  (11)  (321)  (212)  9 
Purchase of treasury stock  (13)  (303)  (195)  (1,205)
Contributions from noncontrolling interest owners  18   –   18   – 
Proceeds from stock option exercises, net of tax payments from stock compensation plan transactions  3   16   (5)  25 
Excess tax benefits from employee stock compensation plan transactions  –   4   1   6 
Principal payments on capital leases  (3)  (5)  (9)  (8)
Net cash used for financing activities  (6)  (113)  (402)  (677)
Effect of translation on cash  2   8   (37)  4 
Increase (decrease) in cash and cash equivalents  (27)  553   (218)  (288)
Cash and cash equivalents, beginning of period  1,322   972   1,513   1,813 
Cash and cash equivalents, end of period $1,295  $1,525  $1,295  $1,525 

The accompanying notes are an integral part of these statements.

6
5
Cameron International Corporation
Consolidated Condensed Statement of Changes in Equity
(dollars in millions)

  Cameron Stockholders   
  Common Stock  Capital in Excess of Par Value  Retained Earnings  
Accumulated Other
Elements of Comprehensive Income (Loss)
  Treasury Stock  Noncontrolling Interests 
  (Unaudited) 
             
Balance at December 31, 2014 $3  $3,255  $5,631  $(540) $(3,794) $889 
Net income  –   –   189   –   –   17 
Other comprehensive income (loss), net of tax  –   –   –   (153)  –   (31)
Non-cash stock compensation expense  –   23   –   –   –   – 
Purchase of treasury stock  –   –   –   –   (191)  – 
Treasury stock issued under stock compensation plans  –   (35)  –   –   30   – 
Tax benefit of stock compensation plan transactions  –   (1)  –   –   –   – 
Contributions from noncontrolling interest owners  –   –   –   –   –   18 
Balance at June 30, 2015 $3  $3,242  $5,820  $(693) $(3,955) $893 
The accompanying notes are an integral part of these statements.

6
Table of ContentsCAMERON INTERNATIONAL CORPORATION
NOTES TO CONSOLIDATED CONDENSED FINANCIAL 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 U.S. 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 Current Report on Form 8-K dated June 16, 2014, which reflects a recasting of the Audited Consolidated Financial Statements and Notes thereto filed by the Company on Form 10-K for the year ended December 31, 2013 to reflect the Reciprocating Compression business as a discontinued operation for all periods presented (see Note 22014.

Preparation of the Notes to Consolidated Condensed Financial Statements below for further information).
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-typeproduction contracts, estimated losses on accounts receivable, estimated realizable value on excess and obsolete inventory, contingencies including(including tax contingencies, estimated liabilities for litigation exposures and liquidated damages,damages), estimated warranty costs, estimates related to pension accounting, estimates used to determine fair values in purchase accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill and long-lived assets 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.

Certain prior year amounts have been reclassified to conform to the current year presentation.

Note 2: Discontinued Operations

Effective June 1, 2014, theThe Company completed its previously announcedthe sale of its Reciprocating Compression business a division of the Process and Compression Systems (PCS) segment, to General Electric, foreffective June 1, 2014, and the sale of its Centrifugal Compression business to Ingersoll Rand on January 1, 2015. The gross cash consideration from the sale of approximately $547 million, net of transaction costs.  As a result of this sale,both businesses was $1.4 billion, subject to pending closing adjustments.

Summarized financial information showing the Reciprocating Compression business is being reported as a discontinued operation in the Company's results of operations for the three- and six-month periods ended June 30, 2014 and 2013.of these discontinued operations was as follows:

  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
(dollars in millions) 2015  2014  2015  2014 
         
Revenues $–  $134  $–  $284 
Cost of sales (excluding depreciation and amortization)  –   (93)  –   (203)
All other (costs) gains(1)
  4   (25)  (1)  (58)
Gain on sale of Compression businesses, before tax  –   95   681   95 
                 
Income before income taxes  4   111   680   118 
Income tax provision  (1)  (88)  (248)  (90)
Income from discontinued operations, net of income taxes $3  $23  $432  $28 

(1)– Includes post-closing adjustments during the three months ended June 30, 2015.
 
     Summarized financial information for the Reciprocating Compression business is as follows (in millions):


 
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 
 2014  2013  2014  2013 
 
 
  
  
  
 
Results of Operations: 
  
  
  
 
Revenues $64  $78  $111  $135 
Cost of sales (excluding depreciation and amortization)  (49)  (58)  (86)  (99)
All other costs  (11)  (14)  (29)  (27)
Gain on sale of Reciprocating Compression business, before tax  95   –   95   – 
Income  before income taxes  99   6   91   9 
Income tax provision  (86)  (2)  (84)  (3)
Income from discontinued operations, net of income taxes $13  $4  $7  $6 
7
The gain on the sale of the Reciprocating Compression businessbusinesses was determined as follows (in millions):follows:

 
 
(dollars in millions) Sale of Centrifugal Compression  Sale of Reciprocating Compression 
Sales price $550  $850  $550 
Net assets sold  (442)  (160)  (442)
Transaction and other costs associated with the sale  (13)  (9)  (13)
Pre-tax gain  95   681   95 
Tax provision  (85)  (248)  (85)
Gain on sale $10  $433  $10 

The tax provision associated with the pre-tax gain ison the Reciprocating Compression business was impacted by nondeductible goodwill of approximately $192 million included in the total net assets sold.

The net assets sold of the Reciprocating Compression business were as follows (in millions):

 
 
 
Accounts receivable $79 
Inventory  122 
Goodwill  214 
All other  27 
Net assets sold $442 

Note 3: Other Costs (Credits)(Gains), Net

Other costs (credits)(gains) consisted of the following (in millions):following:
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
(dollars in millions) 2015  2014  2015  2014 
         
Asset charges -        
Goodwill impairment $–  $–  $517  $40 
Other long-lived asset impairments  –   4   36   4 
Accelerated depreciation on underutilized assets10–10–
Total $10  $4  $563  $44 
                 
Other costs (gains) -                
Facility closures and severance  17   3   33   8 
Mark-to-market impact on currency derivatives not designated as accounting hedges  (1)  –   11   – 
Gain from Venezuela currency devaluation  –   –   (4)  – 
Gain from remeasurement of prior interest in equity method investment  –   (8)  –   (8)
Loss from Angola currency devaluation9–9–
All other costs, net2(5)2(1)
Total  27   (10)  51   (1)
Total other costs (gains),net $37  $(6) $614  $(43)

Asset impairment charges

 
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 
 2014  2013  2014  2013 
 
 
  
  
  
 
Goodwill impairment $–  $–  $40  $– 
OneSubsea formation costs  –   28   –   45 
Gain from remeasurement of prior interest in equity method investment  (8)  –   (8)  – 
Impairment of intangible assets  4   –   4   – 
Acquisition and other integration costs  –   2   2   3 
Mark-to-market impact on currency derivatives not designated as accounting hedges  –   (3)  –   – 
Currency devaluation, severance, restructuring and other costs, net  –   8   6   18 
Total other costs (credits) $(4) $35  $44  $66 
The Company tests the carrying value of goodwill in accordance with accounting rules on impairment of goodwill, which require that the Company estimate the fair value of each of its reporting units annually, or when impairment indicators exist, and compare such amounts to their respective carrying values to determine if an impairment of goodwill is required.

In connection with our annual goodwill impairment test as of March 31, 2015, we tested the goodwill for each of our six reporting units. With the exception of the Process Systems reporting unit, no goodwill impairments were indicated. As described further in Note 2our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, we recorded a goodwill impairment charge of $517 million at March 31, 2015 for the NotesProcess Systems reporting unit, leaving a remaining balance of goodwill in this reporting unit at June 30, 2015 of $53 million.
Previously, goodwill totaling $40 million relating to Consolidated Condensed Financial Statements, the Company completed the sale of its Reciprocating Compression business to General Electric, effective June 1, 2014.  Reciprocating Compression had previously been included with theCompany’s Process Systems and Equipment (PSE) business in the Process Systems & Reciprocating Compression reporting unit for goodwill impairment evaluation purposes.  As a result ofwas considered to be fully impaired during the classification of Reciprocating Compression as a discontinued operation in the first quarter of 2014 when a definitive agreement to sell the business was entered into, total reporting unit goodwill was allocated between the two businesses.  Following this, the PSE business was evaluated as a separate reporting unit in connection with the Company's annual goodwill impairment review conducted during the first quarter of 2014.

The Company also recognized impairment charges of $36 million during the six months ended June 30, 2015 relating to certain underutilized facilities resulting from weak market conditions. Charges of $4 million were recognized during the first six months of 2014 for impairment of certain intangible assets.
As a result of this review,current market conditions and the PSE goodwill amount, totaling approximately $40impact on the Company’s operations, charges of $43 million was fully impaired at that time.were recognized during the six months ended June 30, 2015 related to the impact of pending facility closures, accelerated depreciation on underutilized assets, and workforce reductions.
Gain from Venezuela currency devaluation

Because of the continuing economic turmoil in Venezuela and further statutory changes which impact exchange rates companies are allowed to use by the Venezuelan government when converting bolivars into dollars, Cameron recognized a gain of $4 million relating to the impact on its bolivar-denominated net liabilities of a devaluation of the Venezuelan currency from the official exchange rate used in the past to a market-based rate during the first six months of 2015.

Gain from remeasurement of prior interest in equity method investment

In May 2014, the Company increased its prior ownership interest in Cameron Services Middle East LLC from 49% to 90%, for approximately $18 million. The Company recognized a pre-tax gain of nearly $8 million as a result of remeasuring its prior interest, which had been accounted for under the equity method, to fair value upon obtaining control of this entity during the second quarter of 2014.  At June 30, 2014, the purchase price allocation for this business has been based upon preliminary estimates and assumptions, which are subject to change upon the receipt of additional information required to finalize the valuation.  The primary areas that have not yet been finalized include amounts relating to inventory, property, plant and equipment, identifiable intangible assets, certain preacquisition contingencies, related adjustments to deferred income taxes and goodwill.  The final valuation will be completed no later than one year from the acquisition date.  Preliminary goodwill recognized at June 30, 2014 was approximately $21 million, which is not deductible for tax purposes.
Note 4: Receivables

Receivables consisted of the following (in millions):following:

 
June 30,
2014
  
December 31,
2013
 
(dollars in millions) 
June 30,
2015
  
December 31,
2014
 
 
  
     
Trade receivables $2,107  $2,368  $1,359  $1,678 
Costs and estimated earnings in excess of billings on uncompleted contracts  305   253   632   621 
Other receivables  160   119   150   122 
Allowance for doubtful accounts  (24)  (21)  (45)  (32)
Total receivables $2,548  $2,719  $2,096  $2,389 

Note 5: Inventories

Inventories consisted of the following (in millions):following:

(dollars in millions) 
June 30,
2015
  
December 31,
2014
 
     
Raw materials $153  $159 
Work-in-process  786   827 
Finished goods, including parts and subassemblies  2,226   2,150 
Other  23   24 
Total gross inventories  3,188   3,160 
Excess of current standard costs over LIFO costs  (73)  (86)
Allowances  (177)  (145)
Total net inventories $2,938  $2,929 
 
 
 
June 30,
2014
  
December 31,
2013
 
 
 
  
 
Raw materials $375  $238 
Work-in-process  1,015   894 
Finished goods, including parts and subassemblies  2,067   2,208 
Other  25   22 
   3,482   3,362 
Excess of current standard costs over LIFO costs  (91)  (120)
Allowances  (123)  (109)
Total inventories $3,268  $3,133 
9
Note 6: Plant and Equipment and Goodwill

Plant and equipment consisted of the following (in millions):

 
June 30,
2014
  
December 31,
2013
 
(dollars in millions) 
June 30,
2015
  
December 31,
2014
 
 
  
     
Plant and equipment, at cost $3,671  $3,670  $3,523  $3,580 
Accumulated depreciation  (1,656)  (1,633)  (1,709)  (1,616)
Total plant and equipment $2,015  $2,037  $1,814  $1,964 

Changes in goodwill during thesix months ended June 30, 2014 were as follows (in(dollars in millions):
Balance at December 31, 2013 $2,925 
Sale of Reciprocating Compression business  (213)
Impairment (See Note 3)  (40)
Acquisitions  21 
Adjustments to the purchase price allocation for prior year acquisitions  19 
Translation effect of currency changes and other  (8)
Balance at June 30, 2014 $2,704 
9
Balance at December 31, 2014 $2,461 
Impairment of goodwill (Note 3)  (517)
Adjustments to the purchase price allocation for prior year acquisitions  (12)
Translation effect of currency changes and other  (52)
Balance at June 30, 2015 $1,880 

Note 7: Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following (in millions):following:

(dollars in millions) 
June 30,
2015
  
December 31,
2014
 
     
Trade accounts payable and accruals $520  $1,084 
Advances from customers  1,352   1,576 
Other accruals  1,061   1,088 
Total accounts payable and accrued liabilities $2,933  $3,748 
 
 
June 30,
2014
  
December 31,
2013
 
 
 
  
 
Trade accounts payable and accruals $690  $1,184 
Advances from customers  1,737   1,676 
Other accruals  1,079   1,023 
Total accounts payable and accrued liabilities $3,506  $3,883 
Activity during the six months ended June 30, 2014 associated with the Company's product warranty accruals was as follows (in millions):
Balance
December 31,
2013
  
Net
warranty
provisions
  
Charges
against
accrual
  Sale of Reciprocating Compression  
Translation
and other
  
Balance
June 30,
2014
 
  
  
  
  
  
 
$46  $26  $(18) $(7) $–  $47 

Note 8: Debt

The Company'sCompany’s debt obligations were as follows (in millions):

 
 
June 30,
2014
  
December 31,
2013
 
 
 
  
 
Commercial paper (0.33% weighted average rate) $263  $– 
Senior notes:        
Floating rate notes due June 2, 2014  –   250 
1.6% notes due April 30, 2015  250   250 
1.15% notes due December 15, 2016  250   250 
1.40% notes due June 15, 2017  250   – 
6.375% notes due July 15, 2018  450   450 
4.5% notes due June 1, 2021  250   250 
3.6% notes due April 30, 2022  250   250 
4.0% notes due December 15, 2023  250   250 
3.7% notes due June 15, 2024  250   – 
7.0% notes due July 15, 2038  300   300 
5.95% notes due June 1, 2041  250   250 
5.125% notes due December 15, 2043  250   250 
Unamortized original issue discount  (7)  (7)
Other debt  60   57 
Obligations under capital leases  60   60 
 
  3,376   2,860 
Current maturities  (562)  (297)
Long-term maturities $2,814  $2,563 

On June 20, 2014, the Company completed the public offering of $500 million in aggregate principal amount of senior unsecured notes as follows:

·$250 million principal amount of 1.4% Senior Notes due June 15, 2017, sold at an offering price of 99.951%, and
·$250 million principal amount of 3.7% Senior Notes due June 15, 2024, sold at an offering price of 99.769%.
(dollars in millions) 
June 30,
2015
  
December 31,
2014
 
     
Commercial paper (0.49% weighted average rate at December 31, 2014) $–  $201 
Senior notes:        
1.15% notes due December 15, 2016  250   250 
1.40% notes due June 15, 2017  250   250 
6.375% notes due July 15, 2018  450   450 
4.5% notes due June 1, 2021  250   250 
3.6% notes due April 30, 2022  250   250 
4.0% notes due December 15, 2023  250   250 
3.7% notes due June 15, 2024  250   250 
7.0% notes due July 15, 2038  300   300 
5.95% notes due June 1, 2041  250   250 
5.125% notes due December 15, 2043  250   250 
Unamortized original issue discount  (7)  (7)
Other debt  35   67 
Obligations under capital leases  66   71 
   2,844   3,082 
Current maturities  (31)  (263)
Long-term maturities $2,813  $2,819 
 
Interest on the notes will be payable semiannually on June 15 and December 15 of each year, beginning December 15, 2014.  The notes may be redeemed in whole or in part by the Company prior to maturity, as provided for in the terms of each note, for an amount equal to the principal amount of the notes redeemed plus a specified make-whole premium.  All of the Company's senior notes rank equally with the Company's other existing unsecured and unsubordinated debt.
Utilizing proceeds from these notes, on July 21, 2014, the Company paid approximately $253 million, which included a make-whole premium plus accrued interest, to redeem early its $250 million principal amount of 1.6% Senior Notes.Commercial paper program

During the first quarter of 2014, the Company's Board of Directors authorized the establishment ofThe Company has in place a $500 million commercial paper program.  This program for general corporate purposes which allows for issuances of up to $500 million of commercial paper with maturities of up tono more than 364 days to bedays. This program is used for general corporate purposes.

Credit agreements and revolving credit facilities

In order to extend the length of its currently available credit facilities, the Company, including certain of its subsidiaries, entered into an amended and restated multi-currency credit agreement (the “Credit Agreement”) with various banks and other financial institutions on May 14, 2015. The averageCredit Agreement is for $750 million, has a term of the outstanding commercial paper atfive years, expiring on May 14, 2020, and replaces a previously existing $835 million multi-currency credit agreement due to expire in June 2016. The Credit Agreement will be used to finance working capital needs and for other general corporate purposes, including acquisitions, capital expenditures, repurchases of common stock, repayment of debt and issuances of letters of credit. At June 30, 2014 was approximately 62 days.2015, no letters of credit had been issued under the Credit Agreement, leaving $750 million available for future use.

On April 11, 2014, theThe Company entered intoalso has a new $750 million three-year multi-currency syndicated Revolving Credit Facility expiring April 11, 2017. Up to $200 million of this new facility may be used for letters of credit and $92 million of letters of credit issued and outstanding under a previously existing $170 million bi-lateral facility were transferred to the new Revolving Credit Facility at close and concurrently the $170 million bi-lateral facility was amended to reduce its capacity to $40 million.  The new Revolving Credit Facility contains covenants and terms consistent with the Company's existing $835 million five-year multi-currency Revolving Credit Facility, which matures on June 6, 2016, and it serves as the primary backstop to the commercial paper program.  At June 30, 2014, no amounts had been borrowed under the $835 million Revolving Credit Facility.credit. The Company has issued letters of credit totaling $77$44 million under the new $750 million Revolving Credit Facility, and $29leaving $706 million under the $40 million bi-lateral facility, leaving $673 million and $11 million, respectively, available for future use at June 30, 2014.2015.

Note 9: Income Taxes

The Company'sCompany’s effective income tax rate on income from continuing operations for the first six months of 20142015 was 25.1%a negative 79.2% as compared to 25.6%25.2% for the first halfsix months of 2013.2014. The components of the effective tax rates for both periods were as follows (dollars in millions):follows:

 Six Months Ended June 30,  Six Month Ended June 30, 
 2014  2013  2015  2014 
(dollars in millions) Tax Provision  Tax Rate  Tax Provision  Tax Rate 
 Tax Provision  Tax Rate  Tax Provision  Tax Rate         
 
  
  
  
 
Forecasted tax expense by jurisdiction $109   24.0% $91   23.8%
Provision (benefit) based on international income (loss) distribution $(29)  23.0% $101   23.5%
Adjustments to income tax provision:                                
Recognition of certain historical tax benefits as prior uncertainty regarding those benefits has been resolved  –   –   (1)  (0.1)
Tax effect of goodwill impairment  10   2.1   –   – 
Asset impairments with no tax benefit  127   (100.5)  10   2.2 
Other asset impairments  (1)  0.9   –   – 
Finalization of prior year returns  (4)  (0.9)  9   2.4   2   (2.0)  2   0.4 
Tax effects of changes in legislation  –   –   (7)  (1.9)
Changes in valuation allowances  –   –   5   1.4   1   (0.6)  1   0.1 
Accrual adjustments and other  (1)  (0.1)  –   –   –   –   (4)  (1.0)
Tax provision $114   25.1% $97   25.6% $100   (79.2)% $110   25.2%

11

Note 10: Business Segments

The Company'sCompany’s operations are organized into threefour separate business segments – Subsea, Surface, Drilling & Production Systems (DPS),and Valves &and Measurement (V&M) and PCS.. Summary financial data by segment follows (in millions):follows:

     
Three Months Ended
June 30,
  
Six Month Ended
June 30,
 
(dollars in millions) 2015  2014  2015  2014 
Revenues:        
Subsea $658  $735  $1,289  $1,416 
Surface  510   613   1,053   1,151 
Drilling  719   766   1,445   1,433 
   V&M  381   539   809   1,039 
Elimination of intersegment revenues  (46)  (83)  (101)  (140)
Total revenues $2,222  $2,570  $4,495  $4,899 
                 
Segment income before interest and income taxes:                
Subsea $67  $46  $124  $75 
Surface  69   108   161   199 
Drilling  119   97   254   164 
   V&M  44   110   89   208 
Elimination of intersegment earning  (7)  (24)  (23)  (36)
Segment income before interest and income taxes  292   337   605   610 
                  
Corporate items:                
Corporate expenses  (23)  (38)  (46)  (75)
Interest, net  (33)  (30)  (71)  (62)
Other (costs) gains, net (see Note 3)
  (37)  6   (614)  (43)
Income (loss) from continuing operations before income taxes $199  $275  $(126) $430 
 
 
 
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 
 2014  2013  2014  2013 
Revenues: 
  
  
  
 
DPS $1,903  $1,438  $3,608  $2,707 
V&M  536   534   1,028   1,056 
PCS  202   237   436   507 
  $2,641  $2,209  $5,072  $4,270 
 
                
Income (loss) before income taxes:                
DPS $235  $196  $418  $350 
V&M  107   109   201   222 
PCS  13   17   28   37 
Corporate & other  (69)  (122)  (191)  (229)
 
 $286  $200  $456  $380 
Corporate & other includesitems include governance expenses associated with the Company's backCompany’s corporate office, support and public company costs,as well as all of the Company'sCompany’s interest income and interest expense, goodwill and asset impairment charges, severance and restructuring expenses, the impact of currency devaluations, foreign currency gains and losses from certain derivative and intercompany lending activities managed by the Company’s centralized treasury function and various other unusual or one-time costs or gains that are not considered a component of segment operating income. Consolidated interest income and expense are treated as described further in Note 3corporate items because cash equivalents, short-term investments and debt, including location, type, currency, etc., are managed on a worldwide basis by the corporate treasury department.
12
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,
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
(dollars and shares in millions, except per share amounts) 2015  2014  2015  2014 
 2014  2013  2014  2013         
 
  
  
  
 
Net income from continuing operations $220  $136  $342  $283 
Net income attributable to noncontrolling interests  12   –   17   – 
Net income from continuing operations attributable to Cameron   208   136   325   283 
Net income (loss) from continuing operations $152  $210  $(226) $320 
Less: Net income attributable to noncontrolling interests
  15   12   17   16 
Net income (loss) from continuing operations attributable to Cameron  137   198   (243)  304 
Income from discontinued operations, net of taxes  13   4   7   6   3   23   432   28 
Net income attributable to Cameron $221  $140  $332  $289  $140  $221  $189  $332 
                                
Average shares outstanding (basic)  204   247   209   247   191   204   192   209 
Common stock equivalents  1   1   2   2   1   1   –   2 
Diluted shares  205   248   211   249   192   205   192   211 
                                
Basic earnings per share:                
Basic earnings (loss) per share:                
Continuing operations $1.02  $0.55  $1.55  $1.15  $0.71  $0.97  $(1.27) $1.46 
Discontinued operations  0.06   0.02   0.04   0.02   0.02   0.11   2.25   0.13 
Basic earnings per share $0.73  $1.08  $0.98  $1.59 
 $1.08  $0.57  $1.59  $1.17                 
                
Diluted earnings per share:                
Diluted earnings (loss) per share:                
Continuing operations $1.02  $0.55  $1.54  $1.14  $0.71  $0.97  $(1.27) $1.44 
Discontinued operations  0.06   0.02   0.04   0.02   0.02   0.11   2.25   0.13 
 $1.08  $0.57  $1.58  $1.16 
Diluted earnings per share $0.73  $1.08  $0.98  $1.57 
Activity in the Company'sCompany’s treasury shares were as follows:

 
Three Months Ended
June 30,
  
Six Months Ended
June 30,
  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
 2014  2013  2014  2013  2015  2014  2015  2014 
 
  
  
  
         
Treasury shares at beginning of period  56,109,636   15,768,832   41,683,164   16,415,336   71,543,192   56,109,636   68,139,027   41,683,164 
Purchases of treasury shares  4,516,668   1,500,002   19,673,771   2,113,455   278,700   4,516,668   4,225,234   19,673,771 
Net change in treasury shares owned by participants in nonqualified deferred compensation plans  
(1,614
)
  (1,068)  38,148   52,107   (599)  (1,614)  (732)  38,148 
Treasury shares issued in satisfaction of stock option exercises and vesting of restricted stock units  (597,340)  (266,036)  (1,367,733)  (1,579,168)  (150,047)  (597,340)  (692,283)  (1,367,733)
Treasury shares at end of period  
60,027,350
   17,001,730   60,027,350   17,001,730   71,671,246   60,027,350   71,671,246   60,027,350 
Average cost per share $46.35  $63.00  $45.38  $61.37 

The average cost of treasury shares acquired for the three- and six-month periods ended June 30, 2014 was $63.00 and $61.37, respectively.  The average cost of treasury shares acquired for the three- and six-month periods ended June 30, 2013 was $60.93 and $61.77, respectively. 

The Company has an authorized stock repurchase program whereby the Company may purchase shares directly or indirectly by way of open market transactions or structured programs, including the use of derivatives, for the Company's own account or through commercial banks or financial institutions.  The program, initiated in October 2011, has had a series of authorizations by the Board of Directors totaling $3.2 billion since inception.  At June 30, 2014,2015, the Company had remaining authority for future stock purchases totaling approximately $456$285 million.

Note 12: Accumulated Other Comprehensive Income (Loss)

The changes in the components of accumulated other elements of comprehensive income (loss) attributable to Cameron stockholders for the three months ended June 30, 20142015 and 20132014 were as follows (in millions):follows:

 Three Months Ended June 30, 2014  
  Three Months Ended June 30, 2015   
(dollars in millions) 
Accumulated Foreign Currency Translation
Gain (Loss)
  Prior Service Credits and Net Actuarial Losses  Accumulated Gain (Loss) on Cash Flow Hedge Derivatives  Total  Three Months Ended June 30, 2014 
 
Accumulated Foreign Currency Translation
Gain (Loss)
  Prior Service Credits and Net Actuarial Losses  Accumulated Gain (Loss) on Cash Flow Hedge Derivatives  Total  Three Months Ended June 30, 2013           
Balance at beginning of period $(40) $(45) $16  $(69) $(107) $(625) $(78) $(62) $(765) $(69)
                                        
Other comprehensive income (loss) before reclassifications:                                        
Pre-tax  (3)  –   (3)  (6)  (51)  50   –   15   65   (6)
Tax effect  –   –   1   1   1   –   –   (12)  (12)  1 
                                        
Amounts reclassified from accumulated other comprehensive income to:                                        
Revenues  –   –   (2)  (2)  -   –   –   18   18   (2)
Cost of sales  –   –   (2)  (2)  -   –   –   9   9   (2)
Selling and administrative expense  –   –   –   –   1 
Tax effect  –   –   2   2   -   –   –   (8)  (8)  2 
Net current period other comprehensive loss  (3)  –   (4)  (7)  (49)
Net current period other comprehensive income (loss)  50   –   22   72   (7)
Balance at end of period $(43) $(45) $12  $(76) $(156) $(575) $(78) $(40) $(693) $(76)
The changes in the components of accumulated other elements of comprehensive income (loss) attributable to Cameron stockholders for the six months ended June 30, 20142015 and 20132014 were as follows (in millions):follows:

 Six Months Ended June 30, 2014  
  Six Months Ended June 30, 2015   
(dollars in millions) 
Accumulated Foreign Currency Translation
Gain (Loss)
  Prior Service Credits and Net Actuarial Losses  Accumulated Gain (Loss) on Cash Flow Hedge Derivatives  Total  Six Months Ended June 30, 2014 
 
Accumulated Foreign Currency Translation
Gain (Loss)
  Prior Service Credits and Net Actuarial Losses  Accumulated Gain (Loss) on Cash Flow Hedge Derivatives  Total  Six Months Ended June 30, 2013           
 
  
  
  
  
 
Balance at beginning of year $(49) $(45) $14  $(80) $(30)
Balance at beginning of period $(428) $(78) $(34) $(540) $(80)
                                        
Other comprehensive income (loss) before reclassifications:                                        
Pre-tax  6   –   4   10   (132)  (147)  –   (43)  (190)  10 
Tax effect  –   –   (2)  (2)  5   –   –   4   4   (2)
                                        
Amounts reclassified from accumulated other comprehensive income to:                                        
Revenues  –   –   (5)  (5)  (2)  –   –   29   29   (5)
Cost of sales  –   –   (2)  (2)      –   –   17   17   (2)
Selling and administrative expense  –   –   –   –   3 
Tax effect  –   –   3   3   -   –   –   (13)  (13)  3 
Net current period other comprehensive income (loss)  6   –   (2)  4   (126)  (147)  –   (6)  (153)  4 
Balance at end of period $(43) $(45) $12  $(76) $(156) $(575) $(78) $(40) $(693) $(76)
 
Note 13: Contingencies

The Company is subject to a number of contingencies, including litigation, tax contingencies and environmental matters.

Litigation

The Company has been and continues to be named as a defendant in a number of multi-defendant, multi-plaintiff tort lawsuits. At June 30, 2014,2015, the Company'sCompany’s Consolidated Condensed Balance Sheet included a liability of approximately $16$18 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.

Tax and Other Contingencies

The Company has legal entities in overnearly 50 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 often require interpretation and/or the application of 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'sauthority’s interpretation of the tax laws and regulations, the Company could be exposed to additional taxes.
The Company has been assessed customs duties and penalties by the government of Brazil totaling a U.S. dollar equivalent of almost $58$42 million at June 30, 2014,2015, including interest accrued at local country rates, following a customs audit for the years 2003-2010. The Company has filed an administrative appeal and believes a majority of this assessment will ultimately be proven to be incorrect because of numerous errors in the assessment, and because the government has not provided appropriate supporting documentation for the assessment. As a result, the Company currently expects no material adverse impact on its results of operations or cash flows as a result of the ultimate resolution of this matter. No amounts have been accrued for this assessment as of June 30, 20142015 as no loss is currently considered probable.

Environmental Matters

The Company is currently identified as a potentially responsible party (PRP) for one site designated for cleanup under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) or similar state law. The Osborne site is Osborne, Pennsylvania (aa landfill into which a predecessor of the Company’s former Reciprocating Compression operation in Grove City, Pennsylvania deposited waste),waste, where remediation was completed in 2011 and remaining costs relate to ongoing ground water monitoring. The Company is also a party with de minimis exposure at other CERCLA sites.

The Company is engaged in site cleanup under the Voluntary Cleanup Plan of the Texas Commission on Environmental Quality ("TCEQ") at a former manufacturing location in Houston, Texas and one in Missouri City, Texas. With respect to the Missouri City site, the Company was notified in 2014 by the TCEQ that it may discontinue and decommission the ground-water treatment system there in preparation for site closure.  With respect to the Houston site, inIn 2001, the Company discovered that contaminated underground water 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 on property values led to a number of claims by homeowners. The Company has settled these claims, primarily as a result ofthrough the settlement of a class action lawsuit and is obligatedwhich obligates the Company to reimburse approximately 190 homeowners for any diminution in value of their property due to contamination concerns at the time of the property's sale. Test results of monitoring wells on the southeastern border of the plume indicate that the plume is moving in a new direction, likely as a result of a ground water drainage system completed as part of an interstate highway improvement project. As a result, the Company notified 39 additional homeowners, and may provide notice to additional homeowners, whose property is adjacent to the class area that their property may be affected. The Company continues to monitor the situation to determine whether additional remedial measures would be appropriate. 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 Condensed Balance Sheet included a noncurrent liability of approximately $7 million for these matters as of June 30, 2014. 2015.

Additionally, the Company has discontinuedceased operations at a number of other sites which had been active for many years and which may have yet undiscovered contamination. The Company does not believe, based upon information currently available, that there are any material environmental liabilities existing at these locations. At June 30, 2014,2015, the Company's Consolidated Condensed Balance Sheet included a noncurrent liability of nearly $3 million for these environmental matters.

Note 14: Fair Value of Financial Instruments

Fair Value of Financial Instruments

The Company'sCompany’s financial instruments consist primarily of cash and cash equivalents, short-term investments, trade receivables, trade payables, derivative instruments and debt instruments. The book values of trade receivables, trade payables and floating-rate debt instruments are considered to be representative of their respective fair values.

15
Following is a summary of the Company'sCompany’s financial instruments which have been valued at fair value in the Company'sCompany’s Consolidated Balance Sheets at June 30, 20142015 and December 31, 2013:2014:

 
Fair Value Based on Quoted Prices in Active Markets for Identical Assets
(Level 1)
  
Fair Value Based on Significant Other Observable Inputs
(Level 2)
  Total  
Fair Value Based on Quoted Prices in Active Markets for Identical Assets
(Level 1)
  
Fair Value Based on Significant Other Observable Inputs
(Level 2)
  Total 
(in millions) 2014  2013  2014  2013  2014  2013  2015  2014  2015  2014  2015  2014 
 
  
  
  
  
  
             
Cash and cash equivalents: 
  
  
  
  
  
             
Cash $536  $618  $–  $–  $536  $618  $685  $616  $–  $–  $685  $616 
Money market funds  960   1,172   –   –   960   1,172   338   842   –   –   338   842 
Commercial paper  –   –   10   4   10   4   –   –   55   13   55   13 
U.S. Treasury securities  –   5   –   –   –   5 
U.S. corporate obligations  14   4   –   –   14   4 
Non-U.S. bank and other obligations  19   19   –   –   19   19   203   33   –   –   203   33 
Short-term investments:                                                
Commercial paper  –   –   114   11   114   11 
U.S. Treasury securities  56   41   –   –   56   41   63   51   –   –   63   51 
U.S. corporate obligations  193   51   –   –   193   51 
U.S. non-governmental agency asset-backed securities  –   –   66   –   66   – 
Non-qualified plan assets:                                                
Money market funds  1   1   –   –   1   1   –   1   –   –   –   1 
Domestic bond funds  3   3   –   –   3   3   3   3   –   –   3   3 
Domestic equity funds  6   5   –   –   6   5   6   5   –   –   6   5 
International equity funds  3   3   –   –   3   3   3   3   –   –   3   3 
Blended equity funds  5   4   –   –   5   4   6   5   –   –   6   5 
Common stock  2   2   –   –   2   2   2   2   –   –   2   2 
Derivatives, net asset (liability):                                                
Foreign currency contracts  –   –   5   19   5   19   –   –   (50)  (99)  (50)  (99)
 $1,591  $1,868  $15  $23  $1,606  $1,891 
Total $1,516  $1,621  $185  $(75) $1,701  $1,546 

Fair values for financial instruments utilizing level 2 inputs were determined from information obtained from third party pricing sources, broker quotes or calculations involving the use of market indices.
At June 30, 2014,2015, the fair value of the Company'sCompany���s fixed-rate debt (based on Level 1 quoted market rates) was approximately $3.3$2.8 billion as compared to the $3.0$2.7 billion face value of the debt recorded, net of original issue discounts, in the Company'sCompany’s Consolidated Condensed Balance Sheet. At December 31, 2013,2014, the fair value of the Company'sCompany’s fixed-rate debt (based on Level 1 quoted market rates) was approximately $2.7$2.9 billion as compared to the $2.5$2.7 billion face value of the debt.

Derivative Contracts

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 expect to have fully offsetting local currency expenditures or receipts. The Company was party to a number of short- and long-term foreign currency forward contracts at June 30, 2014.2015. 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. Many of these contracts have been designated as and are accounted for as cash flow hedges with changes in the fair value of those contracts recorded in accumulated other comprehensive income (loss) in the period such change occurs. Certain other contracts, many of which are centrally managed, are intended to offset other foreign currency exposures but have not been designated as hedges for accounting purposes and, therefore, any change in the fair value of those contracts is reflected in earnings in the period such change occurs. 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.

The Company manages its debt portfolio to achieve an overall desired position of fixed and floating rates and employs from time to time interest rate swaps as a tool to achieve that goal.
Total gross volume bought (sold) by notional currency and maturity date on open derivative contracts at June 30, 20142015 was as follows (in millions):follows:

 Notional Amount - Buy  Notional Amount - Sell  Notional Amount - Buy  Notional Amount - Sell 
 2014  2015  2016  Total  2014  2015  2016  Total 
(amounts in millions) 2015  2016  2017  Total  2015  2016  2017  2018  Total 
Foreign exchange forward contracts - 
  
  
  
  
  
  
  
                   
Notional currency in: 
  
  
  
  
  
  
  
                   
Australian dollar  17   –   –   17   (17)  –   –   (17)  –   –   –   –   (1)  –   –   –   (1)
Chinese yuan  20   –   –   20   –   –   –   – 
Euro  107   28   10   145   (23)  (4)  (1)  (28)  143   60   36   239   (49)  (11)  –   –   (60)
Malaysian ringgit  51   215   3   269   (14)  –   –   (14)  275   61   –   336   (16)  –   –   –   (16)
Norwegian krone  612   513   54   1,179   (159)  (64)  –   (223)  412   579   31   1,022   (31)  (64)  (4)  –   (99)
Pound sterling  52   17   1   70   (37)  (17)  (1)  (55)
Pound Sterling  140   9   –   149   (25)  (1)  –   –   (26)
U.S. dollar  56   7   –   63   (389)  (215)  (47)  (651)  11   30   2   43   (411)  (260)  (101)  (1)  (773)

While the Company reports and generally settles its individual derivative financial instruments on a gross basis, the agreements between the Company and its third party financial counterparties to the derivative contracts generally provide both the Company and its counterparties with the legal right to net settle contracts that are in an asset position with other contracts that are in an offsetting liability position, if required. The fair values of derivative financial instruments recorded in the Company'sCompany’s Consolidated Condensed Balance Sheets at June 30, 20142015 and December 31, 20132014 were as follows (in millions):follows:
 
 
 June 30, 2014  December 31, 2013 
 
 Assets  Liabilities  Assets  Liabilities 
 
 
  
  
  
 
Derivatives designated as hedging instruments: 
  
  
  
 
Current $18  $13  $28  $10 
Non-current  3   2   3   2 
Total derivatives designated as hedging instruments  21   15   31   12 
 
                
Derivatives not designated as hedging instruments:                
Current  2   3   6   6 
Non-current  –   –   –   – 
Total derivatives not designated as hedging instruments  2   3   6   6 
 
                
Total derivatives $23  $18  $37  $18 

  June 30, 2015  December 31, 2014 
(dollars in millions) Assets  Liabilities  Assets  Liabilities 
         
Derivatives designated as hedging instruments:        
Current $15  $67  $8  $83 
Non-current  5   8   1   12 
Total derivatives designated as hedging instruments  20   75   9   95 
                 
Derivatives not designated as hedging instruments:                
Current  10   5   1   14 
Non-current  –   –   –   – 
Total derivatives not designated as hedging instruments  10   5   1   14 
                 
Total derivatives $30  $80  $10  $109 

The amount of pre-tax gain (loss) from the ineffective portion of derivatives designated as hedging instruments and from derivatives not designated as hedging instruments was (in millions):was:

  
Three Months Ended
June 30,
  
Six Months Ended
June 30,
 
(dollars in millions) 2015  2014  2015  2014 
         
Derivatives designated as hedging instruments -        
Cost of sales $4  $(1) $1  $1 
                 
Derivatives not designated as hedging instruments -                
Cost of sales  10   1   (9)  2 
Other (costs) gains  1   –   (11)  – 
Total pre-tax gain (loss) $15  $–  $(19) $3 
 
 Three Months Ended  Six Months Ended 
 
 June 30,  June 30, 
 
 2014  2013  2014  2013 
 
 
  
  
  
 
Derivatives designated as hedging instruments - 
  
  
  
 
Cost of sales $(1) $(1) $1  $(5)
 
                
Derivatives not designated as hedging instruments -                
Cost of sales  1   –   2   – 
Other costs  –   3   –   – 
 
 $–  $2  $3  $(5)

Note 15: Recently Issued Accounting Pronouncements

Revenue

In May 2014, the U.S. Financial Accounting Standards Board (FASB) and the International Accounting Standards Board (IASB) jointly issued a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP and International Financial Reporting Standards (IFRS).

The core principle of Accounting Standards Update 2014-09, Revenue from Contracts with Customers (ASU 2014-09), is that a company will recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods and services. CompaniesIn order to comply with this new standard, companies will need to:

·identify performance obligations in each contract,
·estimate the amount of variable consideration to include in the transaction price, and
·allocate the transaction price to each separate performance obligation.

ASU 2014-09, as amended, will be effective for Cameron no earlier thanbeginning in the first quarter of 2017.2018. In May 2015, the FASB issued further proposed amendments to this standard that would address accounting for licenses of intellectual property and identifying performance obligations. The FASB has also indicated they are planning to issue other proposed amendments that would clarify the collectibility criterion and provide practical expedients to ease transition, among other things. The Company is beginning the process ofhas begun evaluating the impact of the new standard on its business and addressingwill ultimately determine after further analysis whether it will select either the full retrospective or the modified retrospective implementation method upon adoption in 2017.method.

Discontinued operations
18
Debt Issuance Costs

The FASB issued Accounting Standards Update 2014-08, ASU 2015-03 Interest—Reporting Discontinued Operations and DisclosuresImputation of DisposalsInterest (Subtopic 835-30): Simplifying the Presentation of Components of an Entity Debt Issuance Costs(ASU 2014-08) (ASU 2015-03) in April 2014.

2015. ASU 2015-03 requires that debt issuance costs related to a recognized liability in the balance sheet be presented as a direct deduction to that liability rather than as an asset. This new standard:
raiseswill align the threshold for disposals to qualify as discontinued operations,
allows companies to have significant continuing involvementpresentation of debt issuance costs with that of debt discounts and continuing cash flows with the discontinued operation, and
provides for new and additional disclosures of discontinued operations and individually material disposal transactions.

premiums. The Company expects to adopt thethis new standard when it becomes effectivebeginning January 1, 2016, with the guidance applied retrospectively to all prior periods presented in financial statements issued after that date. The Company does not currently anticipate a material impact on its Consolidated Balance Sheet at the first quartertime of 2015.adoption of this new standard.
 

Item 2.  Management's
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

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, 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'sCompany’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'sCompany’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'sCompany’s results of operations, liquidity or financial condition. Such factors may include overall demand for, and pricing of, the Company'sCompany’s products; the size and timing of orders; the Company'sCompany’s ability to successfully execute large subsea and drilling projects it has been awarded; the possibility of cancellations of orders in backlog; the Company'sCompany’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; 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'customers’ spending levels and their related purchases of the Company'sCompany’s products and services. As a result, changes in oil and gas price expectations may impact the demand for the Company'sCompany’s products and services and the Company'sCompany’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“Factors That May Affect Financial Condition and Future Results"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'sCompany’s future performance. Additionally, the Company is not obligated to make public disclosure of such changes unless required under applicable disclosure rules and regulations.

19
20

SECOND QUARTER 20142015 COMPARED TO SECOND QUARTER 20132014

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:

 
Three Months Ended
June 30,
  Increase (Decrease)  
Three Months Ended
June 30,
  Increase (Decrease) 
 2014  2013  Amount  %  2015  2014  Amount  % 
Drilling activity (average number of working rigs during period)(1):
 
  
  
  
         
United States  1,852   1,761   91   5.2%  909   1,852   (943)  (50.9)%
Canada  202   155   47   30.3%  100   202   (102)  (50.5)%
Rest of world  1,345   1,306   39   3.0%  1,169   1,348   (179)  (13.3)%
Global average rig count  3,399   3,222   177   5.5%  2,178   3,402   (1,224)  (36.0)%
                                
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 $103.06  $94.14  $8.92   9.5%
Henry Hub natural gas spot price per MMBtu in U.S. dollars $4.59  $4.02  $0.57   14.2%
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
                
West Texas Intermediate Cushing, OK crude oil contract (per barrel) $101.10  $93.62  $7.48   8.0%
Henry Hub natural gas contract (per MMBtu) $4.35  $3.76  $0.59   15.7%
Commodity prices (average of daily U.S. dollar prices per unit during period)(2):
                
West Texas Intermediate (WTI) Cushing, OK crude spot price (per barrel)
 $57.85  $103.06  $(45.21)  (43.9)%
Brent crude oil spot price (per barrel)
 $66.22  $106.96  $(40.74)  (38.1)%
Henry Hub natural gas spot price (per MMBtu)
 $2.73  $4.59  $(1.86)  (40.5)%
                
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
                
West Texas Intermediate (WTI) Cushing, OK crude oil contract (per barrel)
 $60.97  $101.10  $(40.13)  (39.7)%
Brent crude oil contract (per barrel)
 $63.59  $112.36  $(48.77)  (43.4)%
Henry Hub natural gas contract (per MMBtu)
 $3.05  $4.35  $(1.30)  (29.9)%
                                
Contracted drillships and semi-submersibles by location at period-end(3):
                                
U.S. Gulf of Mexico  49   40   9   22.5%  46   49   (3)  (6.1)%
Central and South America  76   88   (12)  (13.6)%  60   76   (16)  (21.1)%
Northwestern Europe  46   47   (1)  (2.1)%  41   46   (5)  (10.9)%
West Africa  45   27   18   66.7%  36   45   (9)  (20.0)%
Southeast Asia and Australia  26   23   3   13.0%
Far East, Southeast Asia and Australia  29   26   3   11.5%
Indian Ocean  10   16   (6)  (37.5)%
Other  44   45   (1)  (2.2)%  22   28   (6)  (21.4)%
Total  286   270   16   5.9%  244   286   (42)  (14.7)%

(1)Based on average monthly rig count data from Baker Hughes
(1)Based on average monthly rig count data from Baker Hughes
(2)Source: Bloomberg
(2)Source: Bloomberg
(3)Source: ODS-Petrodata Ltd.
(3)Source: IHS Energy – IHS Petrodata World Rig Forecast

The increase inSecond quarter 2015 average worldwide operating rigsrig count levels were down significantly from the same period in 2014, largely due to lower activity levels in the United States, mainly reflecting (i) the sharp drop in commodity prices that began during the second quarterlatter half of 2014 as comparedand (ii) the resulting 2015 capital spending cuts announced by many of the largest oil and gas production companies. Average worldwide working rig count levels for the month of June 2015 were down 40% from December 2014 and more than 16% from March 2015 and were at their lowest levels since mid-2009. Although the Company has a substantial backlog of work that is scheduled to be executed during 2015, these declines in commodity prices and drilling activity levels have already had and will continue to have a negative impact on future demand for our products and services and our future revenues and earnings. Based on the second quarter of 2013 was primarily due to a 30% increase in activity in Canada as a result of a 41% increaseCompany’s long history in the average numberenergy sector, we believe such declines in commodity prices and the level of rigs drilling for gas.  Also contributingdemand are typically cyclical in nature. During such cyclical downturns, we take steps to adjust our commercial, manufacturing and support operations as appropriate to ensure that the increase duringCompany remains competitive. The Company cannot predict the quarter was a 9% increase induration or depth of this down cycle.
In the United States, the average number of rigs drilling for oil during the second quarter of 2015 was down 55% from the second quarter of 2014 and, at the end of June 2015, was down 23% from the end of the first quarter of 2015, to its lowest level since August 2010. Rigs drilling for oil accounted for approximately 73% of total U.S. rig count levels at the end of June 2015, compared to 83% at the end of June 2014. The number of rigs drilling for gas in North Americathe United States during the second quarter of 2015 was 30% lower than the second quarter of 2014. Based on data from Baker Hughes, gas rig count levels in the United States during the second quarter of 2015 declined to their lowest levels in more than a quarter of a century.

The decrease in the Canadian rig count during the second quarter of 2015 as compared to the second quarter of 2013.2014 was due largely to a decrease of 63% in the number of rigs drilling for oil. Rigs drilling for gas were also down over 38% during those same periods. Based on data from Baker Hughes, the number of rigs drilling for oil in Canada declined to a six-year low during the second quarter of 2015.

CrudeNearly 45% of the average rig count decline noted in the table above for the remainder of the world was primarily the result of lower activity levels in Latin America.

Average crude oil and natural gas prices (West Texas Intermediate, Cushing, OK) were fairly consistent but trended upward towardssignificantly lower during the second quarter of 2015 as compared to the same period last year. Both WTI and Brent crude prices at the end of the second quarter of 2014 reaching a high of $107.26 in late June before closing the period at $105.37 per barrel.  On2015 have declined over 40% since mid-2014 levels, although average daily crude oil prices were almost 10% higherincreased during the second quarter of 20142015 as compared to the secondfirst quarter of 2013.2015. The twelve monthtwelve-month futures price for WTI crude oil at June 30, 20142015 was slightly lower compared toapproximately 3% higher than spot prices at the end of the quarter. The twelve-month futures price for Brent crude oil at June 30, 2015 was approximately 3% lower than spot prices at the end of the quarter.

Average natural gas prices during the second quarter of 2015 were down over 40% from the same period in 2014 and continued to decline slightly from average prices during the first quarter of 2015, although prices did recover somewhat near the end of the quarter.
Natural gas (Henry Hub) prices were fairly consistent throughout the second quarter of 2014, averaging $4.59 per MMBtu, which is a 14% increase as compared to2015.  Spot prices at the same period in 2013.end of June 2015 were almost 6% higher than at the end of March 2015. The 12-monthtwelve-month futures strip price for natural gas at June 30, 20142015 was $4.35$3.05 per MMBtu at Henry Hub, which is comparable towas 10% higher than the spot price at June 30, 2014.that date of $2.77. 

With the recent increase in theThe total number of drillships and semi-submersibles available for contract and under contract a slowdownat June 30, 2015 was down from June 30, 2014 due to the decline in demand for newbuild construction has occurred as thecommodity prices and drilling industry undergoes a rebalancing of supply and demand for such rigs.

The oilfield service industry has also been experiencing customer slowdowns and delays on certain large subsea projects.  As an example, the Company announced in November 2013activity that Chevron's Rosebank projectbegan in the UK North Sealatter half of 2014. Based on data from IHS Energy, the contracted utilization rates for drillships was being deferred87.5% in orderJune 2015 compared to 96.2% in June 2014 and the contracted utilization rate for Chevronsemi-submersibles was 85.4% in June 2015 compared to work92.0% in June 2014. At June 30, 2015, the supply of available semi-submersibles and drillships currently exceeds demand with its partnersadditional supply expected to improve project economics.  The original award received by Cameron for this project totaled in excesscome on-line during the remainder of $500 million.  It was agreed that OneSubsea would continue to work on its awarded scope2015 and work with Chevron on improving the project's economics.

Critical Accounting Policies

Goodwill – During the first quarter of each annual period, the Company reviews the carrying value of goodwill in accordance with accounting rules on impairment of goodwill, which require that the Company estimate the fair value of each of its reporting units annually, or when impairment indicators exist, and compare such amounts to their respective carrying values to determine if an impairment of goodwill is required. The estimated fair value of each reporting unit is determined using discounted future expected cash flow models (level 3 unobservable inputs) consistent with the accounting guidance for fair value measurements.  Certain estimates and judgments are required in the applicationbeyond. Many of the discounted cash flow models, including, butnewbuild drillships and semi-submersibles that are currently on order, planned or under construction do not limited to, estimates of future cash flows and the selection of a discount rate.  

As described furthercurrently have contracts in Note 2 of the Notes to Consolidated Condensed Financial Statements, effective June 1, 2014, the Company completed the previously announced sale of its Reciprocating Compression business, a division of the Process and Compression Systems (PCS) segment, to General Electric for cash consideration of approximately $547 million, net of transaction costs.  Reciprocating Compression had previously been included with the Process Systems and Equipment (PSE) business in the Process Systems & Reciprocating Compression reporting unit for goodwill impairment evaluation purposes.  As a result of the classification of Reciprocating Compression as a discontinued operation in the first quarter of 2014 when a definitive agreement to sell the business was entered into, total reporting unit goodwill was allocated between the two businesses.  Following this, the PSE business was evaluated as a separate reporting unit inplace. In connection with the Company's annual goodwill impairment review conducted during the first quarterthis, and in response to current market conditions, certain drilling contractors are making efforts to defer delivery of 2014.  As a result of this review, the PSE goodwill amount, totaling approximately $40 million, was fully impaired at that time.newbuild units and have begun to cold stack or scrap certain older rigs in their existing portfolios.

Consolidated Results

Net income attributable to Cameron stockholders for the second quarter of 20142015 totaled $221$140 million, compared to $140$221 million for the second quarter of 2013.same period in 2014. Earnings from continuing operations per diluted share totaled $1.02$0.71 for the second quarter of 2015, compared to $0.97 per diluted share for the same period in 2014. Included in the second quarter 2015 results were certain costs totaling $0.12 per diluted share, primarily associated with:

facility closures and severance activities, and

asset charges and other costs.
Included in the results for the second quarter of 2014 compared to $0.55 per diluted share for the second quarter of 2013. Included in the second quarter 2014 results were certainafter-tax gains, net of costs, totaling $0.02 per diluted share, primarily associated with:
related to a gain from remeasurement of a prior interest in an equity method investment, and
anpartially offset by certain long-lived asset impairment of certain intangible assets.

The results for the second quarter of 2013 included after-tax charges of $0.22 per share, primarily related to formation costs for OneSubsea, including additional income tax expense incurred in connection with the formation, as well as currency devaluation, severance, restructuring and other costs.charges.

Absent these gains, net of certain costs, and other costs for the same period in 2013,unusual amounts, diluted earnings from continuing operations per share would have increaseddecreased nearly 30%13% in the second quarter of 20142015 as compared to the second quarter of 2013.2014.
Total revenues for the Company increased $432decreased $348 million, or 19.6%13.5%, during the three months ended June 30, 20142015 as compared to the three months ended June 30, 20132014. Nearly 35% ofRevenues declined in all reporting segments due to weak market conditions resulting from the increase was attributable to businesses acquired during the last twelve months with the remaining increase reflecting higher revenuesdecrease in each major product line in the Drilling & Production Systems (DPS) segment.  Revenues in the Valves & Measurement (V&M) segment were relatively flat compared to the same period last year, while PCS segment revenues, excluding discontinued operations, were down nearly 15%.commodity prices and activity levels described above.

As a percent of revenues,The Company’s gross product margins (revenues minus cost of sales, (exclusive ofexcluding depreciation and amortization)amortization, divided by revenues) increased from 70.9%to 28.7% during the second quarter of 2013 to 71.7% for2015 from 28.0% during the second quarter ofsame period in 2014 mainly as a result of higher costscontinuing improvements in relation to revenuesproject execution in the DPS segmentSubsea and Drilling segments as described further below under "Segment Results"“Segment Results”.

Selling and administrative expenses increased $31decreased $54 million, or 9.8%16.2%, during the three months ended June 30, 20142015 as compared to the three months ended June 30, 2013.2014. This increase was primarily duedecrease reflects the results of the Company’s internal transformation which began in 2014. The goal of this transformation effort is to higher business activity levels inpermanently lower the DPS segment, along with the impact of additional costs from newly acquired businesses.Company’s operating cost structure. Selling and administrative expenses were 13.1%12.6% of revenues for the second quarter of 2014,2015, down from 14.3%13.0% for the second quarter of 2013, reflecting the impact of cost control efforts initiated in 2014.

Depreciation and amortization expense totaled $90 million for the second quarter of 2014 as compared to $67 million during the second quarter of 2013, an increase of $23 million.  The increase was due mainly to higher depreciation expense as a result of recent increased levels of capital spending and the impact of additional depreciation and acquired intangible amortization expense associated mainly with businesses acquired from Schlumberger in connection with the formation of OneSubsea.

Net interest increased $5 million, from $25 million during the second quarter of 2013 to $30 million during the second quarter of 2014, mainly resulting from additional interest associated with $750 million of new senior notes issued by the Company in December 2013.

Other credits, net of costs totaled $4$37 million for the three months ended June 30, 2014 as compared2015, largely related to costspending facility closures and severance activities taken in response to current market conditions, accelerated depreciation on underutilized assets, and a devaluation of $35 millionthe Angolan currency.  Certain non-operating gains accounted for the three months ended June 30, 2013.majority of the net gain of $6 million recognized in the second quarter of 2014.  See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information on the nature of these items.information.

The Company'sCompany’s effective tax rate on income from continuing operations for the second quarter of 20142015 was 23.0%23.5% compared to 31.8%23.0% for the second quarter of 2013.2014. The components of the effective tax rates for both periods were as follows (dollars in millions):follows:

 Three Months Ended June 30,  Three Months Ended June 30, 
 2014  2013  2015  2014 
(dollars in millions) Tax Provision  Tax Rate  Tax Provision  Tax Rate 
 Tax Provision  Tax Rate  Tax Provision  Tax Rate         
 
  
  
  
 
Forecasted tax expense by jurisdiction $68   24.0% $50   24.7%
Provision based on international income distribution $46   23.0% $65   23.5%
Adjustments to income tax provision:                                
Recognition of certain historical tax benefits as prior uncertainty regarding those benefits has been resolved  –   –   (1)  (0.3)
Other asset impairments  (1)  (0.6)  –   – 
Finalization of prior year returns  (1)  (0.5)  10   4.8   1   0.7   –   – 
Changes in valuation allowances  –   –   5   2.6   1   0.4   1   0.1 
Accrual adjustments and other  (1)  (0.5)  –   –   –   –   (1)  (0.6)
Tax provision $66   23.0% $64   31.8% $47   23.5% $65   23.0%


Segment Results

DPSSegment revenues and operating income before interest and income taxes represent the results of activities involving third-party customers and transactions with other segments. Segment operating income before interest and income taxes represents the profit remaining in the segment after deducting third-party and intersegment cost of sales, selling and administrative expenses and depreciation and amortization expense from third-party and intersegment revenues. For further information on the Company’s segments, see Note 10 of the Notes to Consolidated Condensed Financial Statements included in this Quarterly Report on Form 10-Q.
Subsea Segment –

 
Three Months Ended
June 30,
  Increase (Decrease)  
Three Months Ended
June 30,
  Increase (Decrease) 
($ in millions) 2014  2013  $   % 
(dollars in millions) 2015  2014  $   % 
 
  
  
               
Revenues $1,903  $1,438  $465   32.3% $658  $735  $(77)  (10.5)%
Income from continuing operations before income taxes $235  $196  $39   19.9%
Income from continuing operations before income taxes as a percent of revenues  12.3%  13.6%  N/A   (1.3)%
Segment operating income before interest and income taxes $67  $46  $21   45.7%
Segment operating income before interest and income taxes as a percent of revenues
  10.2%  6.3%  N/A  3.9 pts. 
                                
Orders $1,690  $1,503  $187   12.4% $742  $596  $146   24.5%
Backlog (at period-end) $9,209  $8,470  $739   8.7% $4,178  $4,763  $(585)  (12.3)%

Revenues

The increaseRevenues decreased in revenues was due to:

a 37% increase in drilling equipment revenues,the second quarter of 2015 as compared to the second quarter of 2014, primarily related to increased shipments associated with higher beginning-of-the-period backlog levels and production efficiency improvements,

growth of 37% in subsea equipment revenues, mainly due to businesses acquired during the last twelve months, which represented almost three-fourths of the change, along with higher revenues on a large project offshore West Africa, and

a 19% increase in sales of surface equipment, largely as a result of highera slowdown in shipments for a project offshore West Africa.

Segment operating income before interest and income taxes as a percent of revenues

Segment operating income before interest and income taxes as a percent of revenues improved in the second quarter of 2015 as compared to the same period in 2014, due mainly to continued improvement in execution, cost control efforts and favorable mix.

Orders

Orders increased during the three months ended June 30, 2015 as compared to the same period in 2014, primarily due to the favorable impact of a $330 million award received for a subsea production system offshore North Africa and a significant award for subsea boosting in the Gulf of Mexico.

Backlog (at period-end)

The main drivers for the reduction in backlog levels at June 30, 2015 as compared to June 30, 2014 were weak order rates in relation to revenues as changing market conditions during the latter part of 2014 and the first quarter of 2015 caused a slowdown in new subsea production project awards from customers.

Surface Segment –

  
Three Months Ended
June 30,
  Decrease 
(dollars in millions) 2015  2014  $  % 
           
Revenues $510  $613  $(103)  (16.8)%
Segment operating income before interest and income taxes $69  $108  $(39)  (36.1)%
Segment operating income before interest and income taxes as a percent of revenues
  13.5%  17.6%  N/A  (4.1) pts. 
                 
Orders $471  $619  $(148)  (23.9)%
Backlog (at period-end) $970  $1,146  $(176)  (15.4)%
Revenues

The majority of the decline in revenues during the second quarter of 2015 as compared to the second quarter of 2014 was due to weak market conditions in North America. Other contributing factors included lower activity levels in Latin America, particularly Mexico and Venezuela, as well as lower shipments in Europe due to weakness in recent order levels.

Segment operating income before interest and income taxes as a percent of revenues

Nearly one-half of the decline in segment operating income before interest and income taxes as a percent of revenues was attributable to lower product margins due to pricing pressures and the unfavorable impact of lower utilization of rental equipment combined with modestly higher depreciation and amortization expense during the second quarter of 2015 as compared to the same period in 2014.

Orders

Orders declined during the second quarter of 2015 as compared to the second quarter of 2014 as a result of reduced activity levels in various North American unconventional resource regions of North America,in response to declining commodity prices, as well as higher shipmentslower demand for new products from customers in Saudi Arabia.

Backlog (at period-end)

The decrease in segment backlog at June 30, 2015 as compared to customers operatingJune 30, 2014 largely reflects weakness in demand for new equipment during the latter part of 2014 and the first half of 2015 due to current weak market conditions resulting from the recent decline in commodity prices.

Drilling Segment –

   
Three Months Ended
June 30,
  Increase (Decrease) 
(dollars in millions) 2015  2014  $  % 
           
Revenues $719  $766  $(47)  (6.1)%
Segment operating income before interest and income taxes $119  $97  $22   22.7%
Segment operating income before interest and income taxes as a percent of revenues
  16.6%  12.7%  N/A  3.9 pts. 
                 
Orders $327  $639  $(312)  (48.8)%
Backlog (at period-end) $2,405  $3,922  $(1,517)  (38.7)%

Revenues

Segment revenues decreased in the North Seasecond quarter of 2015 as compared to the second quarter of 2014 mainly as a result of a drop in service revenue (includes activities and products to support our existing customer installed base), reflecting (i) a decrease in our installed base as customers have elected to scrap older rigs and (ii) the impactdeferral of businesses acquired during the last twelve months.customer spending on discretionary services.

Income from continuing operationsSegment operating income before interest and income taxes as a percent of revenues

The decreaseincrease in the ratio ofsegment operating income from continuing operations before interest and income taxes as a percent of revenues in the second quarter of 2015 as compared to the same period last year was due primarily to:to (i) continued improvement in project execution and (ii) cost control efforts, including a decrease in selling and administrative expenses.
Orders

a 0.9 percentage-point increase in the ratio of cost of sales to revenues resulting mainly from lower project margins in the drilling equipment product line due to higher costs, as well as higher warranty costs, partially offset by better cost recovery on a West African subsea project, and

a 0.6 percentage-point increase in the ratio of depreciation and amortization expense to revenues as a result of higher depreciation and amortization expenseOrder rates declined during the second quarter of 2015 as compared to the same period in 2014 largely related to (1) businesses acquired from Schlumberger as part of the formation of OneSubsea and (2) higher capital spending to (a) enhance the Company's aftermarket capabilities, and (b) expand the fleet of rental equipment available in the Surface Systems division.

Orders

The increase in total segment orders was primarily thea result of (i) cyclical weakness and a 70% increasesignificant industry-wide over-supply of drilling rigs which has led to the scrapping of older rigs, (ii) a sharp reduction in subsea orders mainly due to businesses acquired duringdemand for new rigs and (iii) the last twelve months, which accounted for approximately 63%deferral of the growth, as well as changes to a large project offshore West Africa.customer spending on discretionary services.

Partially offsetting these increases was a 5% decline in orders for drilling equipment primarily reflecting a slowdown in activity relating to jack-up rigs.
Backlog (at period-end)

Higher subsea equipment backlog, largely as a result of strong 2013 order rates, accounted for nearly 80% of the total increase in DPS segment backlog
Backlog at June 30, 2015 decreased from June 30, 20132014 mainly due to June 30, 2014.   Strong order rates, primarily in North America and the Asia Pacific/Middle East region, as well as backlog added from businesses acquired during the last twelve months, also led to a nearly 24% increase in surface equipment backlog levels from June 30, 2013.  Drilling equipment backlog was down less than 1% despite the reversallack of nearly $243 million in backlogmeaningful activity in the first quarter of 2014new rig construction market, especially in relation to deepwater rigs.  Service backlog (includes activities and products to support our existing customer installed base) has also declined as the result ofcustomer decisions to scrap older rigs have resulted in a customer cancellation of a large drilling project award issueddecrease in 2012.  The Company reached agreement with the customer in July 2014 which will result in an additional payment from the customer of $21 million in connection with the cancelled contract.our installed base and as customers have elected to defer discretionary spending on services.

V&M Segment –

 
Three Months Ended
June 30,
  Increase/(Decrease)  
Three Months Ended
June 30,
  Decrease 
($ in millions) 2014  2013  $   % 
(dollars in millions) 2015  2014  $   % 
 
  
  
               
Revenues $536  $534  $2   0.4% $381  $539  $(158)  (29.3)%
Income from continuing operations before income taxes $107  $109  $(2)  (1.8)%
Income from continuing operations before income taxes as a percent of revenues  20.0%  20.4%  N/A   (0.4)%
Segment operating income before interest and income taxes $44  $110  $(66)  (60.0)%
Segment operating income before interest and income taxes as a percent of revenues
  11.5%  20.4%  N/A  (8.9) pts. 
                                
Orders $517  $524  $(7)  (1.3)% $369  $517  $(148)  (28.6)%
Backlog (at period-end) $1,026  $1,063  $(37)  (3.5)% $809  $1,026  $(217)  (21.2)%

Revenues

Favorable North American market conditions and the impact of businesses acquiredSegment revenues declined in the last twelve months contributedsecond quarter of 2015 as compared to an increasethe second quarter of 25%2014, as lower North America upstream activity levels, caused by a decline in commodity prices, resulted in lower sales of measurement products and a 12% improvement in sales of distributed valves.  Mostly offsetting these gains were lower activity levels resulting from project slippage and recent order weakness for pipeline valves and the timing of valve deliveries due to various customer changes which resulted in sales declines of 14% and 7%measurement products. Additionally, lower beginning backlog levels for engineered valves and process valves respectively.for use in midstream and downstream applications have also negatively impacted current shipment levels in comparison to the prior year quarter.

Income from continuing operationsSegment operating income before interest and income taxes as a percent of revenues

The ratio of segment operating income from continuing operations before interest and income taxes as a percent of revenues was down slightlydeclined sharply in the second quarter of 2015 as compared to the same periodsecond quarter of the year.  Increased overhead2014, primarily due to lower North America valve and measurement product margins resulting from pricing pressures and higher costs, andas well as higher depreciation and amortization expense on lower volumes. Although selling and administrative expenses declined in the second quarter of 2015 as a resultcompared to the second quarter of increased capital spending2014, the rate of decline was less than the rate of decline in recent periods more than offset slightly higher product margins.revenues.

Orders

Overall, total segment orders were down modestlyOrders for the second quarter of 2015 reflected a significant decline when compared to the same period last year.  Project timing delays contributed to a 19% decrease in engineered valve orders. Mostly offsetting this decline was a 28% improvement in distributed valve orders reflecting highersecond quarter of 2014. Lower North America upstream activity levels and high distributor inventory levels reduced demand for valve and measurement products. Additionally, current weakness in North America.activity levels has also negatively impacted demand for valves for new midstream and downstream projects.

Backlog (at period-end)

Backlog levels for the V&M segment decreased slightly from June 30, 2013,2014 to June 30, 2015, as recent order rates during the last twelve months for new engineeredcustom valve and process valvesmeasurement products have not kept uppace with recent deliveries. These decreases were partially offset by strong demand for distributed valves and measurement products reflecting continued strength in the North American market.

24
Corporate Expenses

PCS Segment –

 
 
Three Months Ended
June 30,
  Increase (Decrease) 
($ in millions) 
2014(1)
  
2013(1)
  $   % 
 
 
  
  
     
Revenues $202  $237  $(35)  (14.8)%
Income from continuing operations before income taxes $13  $17  $(4)  (23.5)%
Income from continuing operations before income taxes as a percent of revenues  6.4%  7.2%  N/A   (0.8)%
 
                
Orders $229  $212  $17   8.0%
Backlog (at period-end) $908  $832  $76   9.1%

(1)Excluding discontinued operations

Revenues

The revenue decrease in the PCS segment was due primarily to:

an 18% decrease in custom process systems revenues largely as a result of the timing of manufacturing activity on large projects,

a 7% decrease in centrifugal compression revenues mainly due to declines in deliveries of plant air equipment and aftermarket revenues as a result of recent weak order rates, and

a 4% decline in deliveries of wellhead and midstream processing equipment due to weak demand.


Income from continuing operations before income taxes as a percent of revenues

The decrease in the ratio of income from continuing operations before income taxes as a percent of revenues was due primarily to a 1.1 percentage-point increase in the ratio of depreciation and amortization expense to revenues as a result of higher depreciation and amortization expense duringCorporate expenses were $23 million for the second quarter of 20142015, a decline of $15 million from $38 million in relation to lower revenues for the period, as mentioned above.  Depreciation and amortization increased across each of the businesses mainly due to increased capital spending in recent periods.

Orders

The increase in segment orders was almost entirely attributable to a 46% increase in demand for wellhead and midstream processing equipment, mainly related to a large award for a new cryogenic gas processing system.

Backlog (at period-end)
Overall segment backlog was up 9% at June 30, 2014 as compared to June 30, 2013, as a 33% increase in backlog in the custom process systems business, largely resulting from a $250 million award received in the fourth quarter of 2013 for equipment to be provided for a gas processing facility in Malaysia, was partially offset by a 19% decline in backlog for centrifugal compression equipment, due to recent weak order rates for new plant air, air separation and engineered air units.


Corporate Segment –

The $53 million decrease in the loss from continuing operations before income taxes in the Corporate segment during the second quarter of 2014 as compared to2014. This decrease reflects the second quarter of 2013 (see Note 10results of the NotesCompany’s internal transformation which began in 2014. The goal of this transformation effort is to Consolidated Condensed Financial Statements) was due mainly to:permanently lower the Company’s operating cost structure.

a $39 million decrease in other costs, net of credits, as described further in Note 3 of the Notes to Consolidated Condensed Financial Statements, and

a $12 million decrease in selling and administrative expenses, mainly reflecting the effects of cost control efforts put in place in 2014 which have lowered employee-related costs, including travel, and information technology and other facility costs.

 
SIX MONTHS ENDED JUNE 30, 20142015 COMPARED TO SIX MONTHS ENDED JUNE 30, 20132014

Market Conditions

Information related to drilling activity and certain commodity spot prices during the first six months of each period follows:

 
Six Months Ended
June 30,
  Increase  
Six Months Ended
June 30,
  Decrease 
 2014  2013  Amount  %  2015  2014  Amount  % 
Drilling activity (average number of working rigs during period)(1):
 
  
  
  
         
United States  1,816   1,760   56   3.2%  1,145   1,816   (671)  (36.9)%
Canada  364   346   18   5.2%  204   364   (160)  (44.0)%
Rest of world  1,341   1,290   51   4.0%  1,215   1,341   (126)  (9.4)%
Global average rig count  3,521   3,396   125   3.7%  2,564   3,521   (957)  (27.2)%
                                
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 $100.89  $94.22  $6.67   7.1%
Henry Hub natural gas spot price per MMBtu in U.S. dollars $4.95  $3.76  $1.19   31.6%
Commodity prices (average of daily U.S. dollar prices per unit during period)(2):
                
West Texas Intermediate (WTI) Cushing, OK crude spot price (per barrel)
 $53.25  $100.89  $(47.64)  (47.2)%
Brent crude oil spot price (per barrel)
 $63.07  $106.26  $(43.19)  (40.6)%
Henry Hub natural gas spot price (per MMBtu)
 $2.80  $4.87  $(2.07)  (42.5)%

(1)Based on average monthly rig count data from Baker Hughes
(1)Based on average monthly rig count data from Baker Hughes
(2)Source: Bloomberg
(2)Source: Bloomberg

The increasedecrease in average worldwide operating rigs during the first six months of 2015 as compared to the same period in 2014 reflects a significant decline in activity levels, particularly in the United States and Canada, which began at the end of 2014 and continued throughout the first six months of 2015. This drop in activity levels was in response to a significant decline in commodity prices which began during the last six months of 2014. In the United States, the average number of rigs drilling for oil has decreased almost 40% during the first six months of 2015 as compared to the same period in 2014, while rigs drilling for gas have declined 23% during the same period. In Canada, the average number of rigs drilling for oil was down 58% during the first six months of 2015 as compared to the first six months of 2013 was driven by higher North American oil drilling activity and higher foreign activity primarily in the Middle East and Africa. Despite the improvement in natural gas pricing, the challenging economics associated with horizontal shale development drilling at current prices continues to constrain the overall rig market.  The average number of2014, while rigs drilling for gas was flatwere down 21%. Internationally, the average number of active working rigs declined in North America inall major regions of the first half of 2014 as compared toworld, except the first half of 2013.Middle East.

Crude oil prices (West Texas Intermediate, Cushing, OK) continued to trend upward throughout much of the first half of 2014 reaching a high of $107.26 per barrel in mid-June before closing the period at $105.37 per barrel.  On average,Average crude oil and natural gas prices were 7% highersignificantly lower during the first halfsix months of 2014 as compared to the first half of 2013.
In early February 2014, natural gas (Henry Hub) prices reached their highest levels since September 2011, before leveling off to close at $4.41 per MMBtu at June 30, 2014.  On average, prices during the first half of 2014 were up 32%2015 as compared to the same period in 2013.last year. Both WTI and Brent crude prices at the end of the first six months of 2015 have declined over 40% since mid-2014 levels, although average daily crude oil prices did increase during the second quarter of 2015 as compared to the first quarter of 2015.
 
While average natural gas prices during the first six months of 2015 were down significantly from the first six months of 2014, prices did begin to recover somewhat near the end of the first half of 2015 as compared to earlier in 2015.

Consolidated Results

Net income attributable to Cameron stockholders for the six months ended June 30, 20142015 totaled $332$189 million, compared to $289$332 million for the first six months of 2013.  Earnings2014. The Company had a loss from continuing operations for the first six months of 2015 of $243 million, largely resulting from a goodwill impairment charge in the Process Systems business totaling $517 million. Offsetting this loss was income from discontinued operations of $432 million, which represented the gain on the sale of the Company’s Centrifugal Compression business. The Company’s loss from continuing operations per diluted share totaled $1.54$1.27 for the first six months of 2014,2015, compared to $1.14earnings from continuing operations per diluted share of $1.44 for the same period in 2014. The goodwill impairment charge described above, as well as other asset impairment charges and certain other costs described further in Note 3 of the Notes to Consolidated Condensed Financial Statements totaled $3.01 per diluted share for the same period in 2013.  Included in the results for thefirst six months ended June 30, 2014 were charges, net of certain gains, totaling $0.19 per diluted share, primarily associated with:
a goodwill impairment charge related to the PSE business and an impairment of certain intangible assets, 

a gain from remeasurement of a prior interest in an equity method investment, and

severance, restructuring, integration and other costs, net of certain gains.
2015.

The results for the first six months of 20132014 included after-tax charges of $0.31$0.19 per share, primarily related to formation costs for OneSubsea, including additional income tax expense incurreda goodwill impairment charge in connection with the formation,Process Systems and Equipment (PSE) business, an impairment of certain intangible assets, as well as currency devaluation, severance, restructuring and other costs.costs, net of certain non-operating gains.

Absent these costs in both periods, diluted earnings from continuing operations per share would have increased nearly 19%approximately 7% as compared to the first half of 2013.2014.

Total revenues for the Company increased $802decreased $404 million, or 18.8%8.2%, during the six months ended June 30, 20142015 as compared to the six months ended same period inJune 30, 2013 2014. Nearly 34%Revenues declined in each segment except Drilling due to the impact of the increase was attributable to businesses acquired duringweak market conditions resulting from the last twelve months with the remaining increase reflecting higher revenuesdecrease in each major product line in the DPS segment.  Revenues in the V&M segment were down 3% compared to the same period last year while PCS segment revenues, excluding discontinued operations, were down 14%.commodity prices and activity levels described above.

As a percent of revenues,The Company’s gross product margins (revenues minus cost of sales, (exclusive ofexcluding depreciation and amortization) were 72.1% foramortization, divided by revenues) increased to 29.0% during the first six months of 2015 from 27.7% during the same period in 2014, as comparedmainly due to 70.7% for the first six months of 2013.  The increase was mainly the result of higher costsimprovements in relation to revenuesproject execution in the DPSSubsea and PCSDrilling segments as described further below under "Segment Results"“Segment Results”.

Selling and administrative expenses increased $57decreased $86 million, or 9.2%13.2%, during the six months ended June 30, 20142015 as compared to the six months ended same period inJune 30, 2013. 2014. This increase was primarily duedecrease reflects the results of the Company’s internal transformation which began in 2014. The goal of this transformation effort is to higher business activity levels inpermanently lower the DPS segment, along with the impact of additional costs from newly acquired businesses.Company’s operating cost structure. Selling and administrative expenses were 13.3%12.6% of revenues for the first six months of 2014,2015, down from 14.5%13.3% for the same period in 2013, reflecting the impact of cost control efforts initiated in 2014.

Depreciation and amortization expense totaled $177 million for the six months ended June 30, 2014 as compared to $135 million for the six months ended June 30, 2013, an increase of $42 million.  The increase was due mainly to higher depreciation expense as a result of recent increased levels of capital spending and the impact of additional depreciation and acquired intangible amortization expense associated mainly with businesses acquired from Schlumberger in connection with the formation of OneSubsea.

Net interest increased $11$9 million, from $51 million during the first half of 2013 to $62 million during the first half of 2014 to $71 million during the first half of 2015, mainly resulting from additional interest associated with $750as a result of $500 million of new senior notes issued by the Company in December 2013.June 2014 and higher interest on capital leases.

Other costs netwere $614 million in the first six months of credits, totaled $44 million2015, largely associated with (i) the goodwill impairment for the Process Systems business described above, (ii) impairment of certain underutilized facilities, (iii) pending facility closures and severance activities taken in response to current market conditions, (iv) accelerated depreciation on underutilized assets, and (v) a devaluation of the Venezuelan and Angolan currencies.  Charges of $43 million were recognized during the first six months ended June 30,of 2014 as compared to $66 million primarily for a goodwill impairment in the six months ended June 30, 2013, a decreasePSE business and impairment of $22 million.  certain intangible assets.
See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information on the nature of these items.information.


The Company’s effective income tax rate on income from continuing operations for the first six months of 20142015 was 25.1%a negative 79.2% as compared to 25.6%25.2% for the first six months of 2013.same period in 2014. The components of the effective tax rates for both periods were as follows (dollars in millions):follows:

 Six Months Ended June 30,  Six Month Ended June 30, 
 2014  2013  2015  2014 
(dollars in millions) Tax Provision  Tax Rate  Tax Provision  Tax Rate 
 Tax Provision  Tax Rate  Tax Provision  Tax Rate         
 
  
  
  
 
Forecasted tax expense by jurisdiction $109   24.0% $91   23.8%
Provision (benefit) based on international income (loss) distribution $(29)  23.0% $101   23.5%
Adjustments to income tax provision:                                
Recognition of certain historical tax benefits as prior uncertainty regarding those benefits has been resolved  –   –   (1)  (0.1)
Tax effect of goodwill impairment  10   2.1   –   – 
Asset impairments with no tax benefit  127   (100.5)  10   2.2 
Other asset impairments  (1)  0.9   –   – 
Finalization of prior year returns  (4)  (0.9)  9   2.4   2   (2.0)  2   0.4 
Tax effects of changes in legislation  –   –   (7)  (1.9)
Changes in valuation allowances  –   –   5   1.4   1   (0.6)  1   0.1 
Accrual adjustments and other  (1)  (0.1)  –   –   –   –   (4)  (1.0)
Tax provision $114   25.1% $97   25.6% $100   (79.2)% $110   25.2%


Segment Results

DPSSubsea Segment –

 
 
Six Months Ended
June 30,
  Increase (Decrease) 
($ in millions) 2014  2013  $   % 
 
 
  
  
     
Revenues $3,608  $2,707  $901   33.3%
Income from continuing operations before income taxes $418  $350  $68   19.4%
Income from continuing operations before income taxes as a percent of revenues
  11.6%  12.9%  N/A   (1.3)%
 
                
Orders $3,449  $4,246  $(797)  (18.8)%
  
Six Months Ended
June 30,
  Increase (Decrease) 
(dollars in millions) 2015  2014  $   % 
           
Revenues $1,289  $1,416  $(127)  (9.0)%
Segment operating income before interest and income taxes $124  $75  $49   65.3%
Segment operating income before interest and income taxes as a percent of revenues
  9.6%  5.3%  N/A  4.3 pts. 
                 
Orders $1,302  $1,025  $277   27.0%

Revenues

The increase in revenues was due to:

an increase of 47% in subsea equipment revenues, over two-thirds of which was due to businesses acquired during the last twelve months, along with higher revenues associated with a large project offshore West Africa, higher project activity levelsRevenues decreased in the Europe/Africa region and increased aftermarket sales,

an increasefirst half of 37%2015 as compared to the same period in drilling equipment revenues,2014, primarily related to increased shipments associated with higher beginning-of-the-year backlog levels and production efficiency improvements, and

growth of 16% in surface equipment revenues, largely as a result of increased activity levelsa slowdown in unconventional resource regions of North America, as well as increased deliveries to customers operatingnew product shipments, largely associated with projects offshore West Africa and in Asia.  This was partially offset by modest growth in the North Seasegment’s Services business (includes activities and the impact of businesses acquired during the last twelve months.products to support our existing customer installed base).


Income from continuing operationsSegment operating income before interest and income taxes as a percent of revenues

The decrease in the ratio of Segment operating income from continuing operations before interest and income taxes as a percent of revenues was due primarily to a 1.2 percentage-point increaseimproved significantly in the ratio of cost of sales to revenues resulting mainly from:

a mix shift to a higher proportion of subsea project revenues, which inherently carry lower margins than non-project related businesses, during the first six months of 20142015 as compared to the same period in 2013,2014, due mainly to continued improvement in execution, cost control efforts and
favorable mix.

lower margins in the drilling equipment product line due to higher project costs, as well as higher warranty costs.
Orders

The decreaseOrders increased during the six months ended June 30, 2015 as compared to the same period in orders was2014, primarily due to:to the favorable impact of a $330 million award received for a subsea production system offshore North Africa and a significant award for subsea boosting in the Gulf of Mexico.
Surface Segment –

  
Six Months Ended
June 30,
  Decrease 
(dollars in millions) 2015  2014  $   % 
           
Revenues $1,053  $1,151  $(98)  (8.5)%
Segment operating income before interest and income taxes $161  $199  $(38)  (19.1)%
Segment operating income before interest and income taxes as a percent of revenues
  15.3%  17.3%  N/A  (2.0) pts. 
                 
Orders $921  $1,255  $(334)  (26.6)%

Revenues

The majority of the decline in revenues during the first half of 2015 as compared to the same period in 2014 was due to weak market conditions in North America. Other contributing factors included lower activity levels in Latin America, particularly Mexico and Venezuela, as well as lower shipments in Europe due to weakness in recent order levels.

Segment operating income before interest and income taxes as a percent of revenues

a 62% decreaseNearly three quarters of the decline in subsea orders, mainlythe ratio of segment operating income before interest and income taxes as a resultpercent of an award receivedrevenues was attributable to higher depreciation and amortization expense during the first six months of 2013 from Petrobras for subsea trees and associated equipment for use in Pre- and Post-Salt basins offshore Brazil,2015 as well as a large booking incompared to the same period in 2014 due to supply subsea production systems to a project offshore Nigeria, with no similar-sized large awards receivedinvestment in rental assets in 2014.  Although selling and administrative expenses declined in the first six months of 2014, and

a 5% decrease in orders for surface equipment due mainly to a slowdown in 2014 in the pace of orders from customers operating in Saudi Arabia and Iraq2015 as compared to the record level of orders received in 2013.  This decline was largely offset by continued strength in activity levels in the unconventional resource regions in North America.

Offsetting these decreases were nearly $200 million of orders added from businesses acquired during the last twelve months and a 9% increase in orders for drilling equipment reflecting several large rig project awards received early in 2014.

V&M Segment –

 
 
Six Months Ended
June 30,
  Decrease 
($ in millions) 2014  2013  $   % 
 
 
  
  
     
Revenues $1,028  $1,056  $(28)  (2.7)%
Income from continuing operations before income taxes $201  $222  $(21)  (9.5)%
Income from continuing operations before income taxes as a percent of revenues
  19.6%  21.0%  N/A   (1.4)%
 
                
Orders $1,053  $1,062  $(9)  (0.8)%

Revenues

Overall segment sales were down modestly for the six months ended June 30, 2014 when compared to the same period last year.   Project slippage and recent order weakness for pipeline valves andin 2014, the timingrate of valve deliveries duedecline was less than the rate of decline in revenues.
Orders

Orders declined during the first six months of 2015 as compared to various customer changes contributed to sales declines of 15% and 9% for engineered valves and process valves, respectively.   Partially offsetting these declines were increases of 8% and 19% for sales of distributed valves and measurement products, respectively,the same period in 2014 as a result of current strengthreduced activity levels in thevarious North American market.unconventional resource regions in response to declining commodity prices, as well as lower demand for new products from customers in Saudi Arabia as compared to the levels experienced during the first six months of 2014.

IncomeDrilling Segment –

  
Six Months Ended
June 30,
  Increase (Decrease) 
(dollars in millions) 2015  2014  $  % 
           
Revenues $1,445  $1,433  $12  0.8%
Segment operating income before interest and income taxes $254  $164  $90  54.9%
Segment operating income before interest and income taxes as a percent of revenues
  17.6%  11.4%  N/A  6.2 pts. 
                 
Orders $594  $1,456  $(862) (59.2)%
Revenues

Revenues for the first half of 2015 were essentially flat with the first half of 2014 as continued improvement in project execution from beginning-of-the-year backlog levels mostly offset a decline in service revenue (includes activities and products to support our existing customer installed base), reflecting a decrease in our installed base as customers have elected to scrap older rigs and the deferral of customer spending on discretionary services.
Segment operating income before interest and income taxes as a percent of revenues

The decreasesubstantial increase in the ratio of segment operating income from continuing operations before interest and income taxes as a percent of revenues was primarily attributable to a 0.5 percentage-point increase in the ratiofirst six months of selling and administrative costs to revenues, due mainly to higher employee-related costs in relation to the decline in revenues, and a 0.8 percentage-point increase in the ratio of depreciation and amortization expense to revenues due to higher depreciation from higher recent capital spending levels mainly in the engineered valve product line and the impact of businesses acquired during the last twelve months.
Orders
Overall, total segment orders were relatively flat when2015 as compared to the same period last year.  Project slippage contributedin 2014 was due primarily to declines(i) continued improvement in project execution and (ii) cost control efforts, including a decrease in selling and administrative expenses as compared to the first six months of approximately 10% and 20% in both engineered and process valve orders, respectively.  This was mostly offset by a 17% increase in orders for distributed valves resulting from higher North American activity levels.2014.

PCSOrders

Order rates declined during the first half of 2015 as compared to the first half of 2014 as a result of (i) cyclical weakness and a significant industry-wide over-supply of drilling rigs which has led to the scrapping of older rigs, (ii) a sharp reduction in demand for new rigs and (iii) the deferral of customer spending on discretionary services.

V&M Segment –

 
 
Six Months Ended
June 30,
  Decrease 
($ in millions) 2014  2013  $   % 
 
 
  
  
     
Revenues $436  $507  $(71)  (14.0)%
Income from continuing operations before income taxes $28  $37  $(9)  (24.3)%
Income from continuing operations before income taxes as a percent of revenues
  6.4%  7.3%  N/A   (0.9)%
 
                
Orders $416  $480  $(64)  (13.3)%
  
Six Months Ended
June 30,
  Decrease 
(dollars in millions) 2015  2014  $   % 
           
Revenues $809  $1,039  $(230)  (22.1)%
Segment operating income before interest and income taxes $89  $208  $(119)  (57.2)%
Segment operating income before interest and income taxes as a percent of revenues
  11.0%  20.0%  N/A  (9.0) pts. 
                 
Orders $757  $1,053  $(296)  (28.1)%

Revenues

The decreaseSegment revenues declined in revenues was due primarily to:the first six months of 2015 as compared to the same period in 2014, as lower North America upstream activity levels, caused by a decline in commodity prices, resulted in lower sales of valves and measurement products. Additionally, lower beginning-of-the-year backlog levels for engineered and process valves for use in midstream and downstream applications and shipment slippages have also negatively impacted current shipment levels in comparison to the prior year.

a 13% decline in custom process systems revenues largely as a result of the timing of manufacturing activity on large projects,

a 19% decline in wellheadSegment operating income before interest and midstream processing equipment sales mainly to customers in North America, and

a 16% decrease in sales of centrifugal air separation and engineered air equipment due to recent weak order rates.

Income from continuing operations before income taxes as a percent of revenues

The decrease in the ratio of segment operating income before interest and income taxes as a percent of revenues was primarily due to:

a 0.6 percentage-point increasedeclined sharply in the ratiofirst half of cost2015 as compared to the first half of sales to revenues2014, primarily due to lower North America valve and measurement product margins resulting from pricing pressures and higher costs. Although selling and administrative expenses declined in the wellhead and midstream processing equipment product line, and

first half of 2015 as compared to the first half of 2014, the rate of decline was less than half the rate of decline in revenues. Also contributing to the lower ratio was higher depreciation and amortization expense in relation to a decline in revenues, primarily due to increased capital spending in recent periods, the impact of which has been partially offset by an improvement in the ratio of selling and administrative costs to revenues due to the effect of cost control efforts implemented during 2014.

on lower volumes.

Orders

Overall, segment orders decreased across most major product lines. The decreases were primarilyOrders for the result of:first six months of 2015 reflected a significant decline when compared to the same period in 2014. Lower North America upstream activity levels and high distributor inventory levels reduced demand for valve and measurement products. Additionally, current weakness in activity levels has also negatively impacted demand for valves for new midstream and downstream projects.
 
a 15% decline in orders for custom process systems largely related to slippage31

a 15% decline in centrifugal compression equipment orders driven mainly by a 45% decrease in demand for plant air machines, primarily from international customers, and

a 7% decline in demand for wellhead and midstream processing equipment, mainly from customers in North America.
Corporate Expenses -

Corporate Segment –

The $38expenses were $46 million decreasefor the first six months of 2015, a decline of $29 million from $75 million in the loss before income taxes infirst six months of 2014. This decrease reflects the Corporate segment during the six-month period ended June 30, 2014 as compared to the six-month period ended June 30, 2013 (see Note 10results of the NotesCompany’s internal transformation which began in 2014. The goal of this transformation effort is to Consolidated Condensed Financial Statements) was due primarily to:

a $22 million decrease in other costs, net of credits, as described further in Note 3 ofpermanently lower the Notes to Consolidated Condensed Financial Statements, and

a $15 million decrease in selling and administrative expenses, mainly reflecting the effects ofCompany’s operating cost control efforts put in place in 2014 which have lowered employee-related costs, including travel, and certain facility costs.
structure.

Liquidity and Capital Resources

Consolidated Condensed Statements of Cash Flows

During the first six months of 2014,2015, net cash provided byused for operations totaled $39$165 million, an increasea decrease of $32$204 million from the $7$39 million of cash provided by operations during the same period in 2014. The change is largely reflective of the decline in earnings during the first six months of 2013.2015 as compared to the same period in 2014. Additionally, a targeted reduction in the Company’s inventory has been slowed by the lengthy nature of many supply chains and the reduced pace of manufacturing activity.

Cash totaling $588$573 million was used to increase working capital during the first six months of 20142015 compared to $404$588 million during the first six monthssame period in 2014, a decrease of 2013, an increase of $184$15 million. During the first six months of 2014,2015, increased collections due to the high level of year end receivables across all segments added $111$252 million in cash. Offsetting this was $228$70 million of cash used to buildas inventory levels primarilycontinued to increase in the DPSeach segment in order to meet the demands from the high backlog and activity levels in that business segment.other than Drilling. The timing of payments to third parties, the consumption of customer advances on projects and annual employee incentive payouts made in the first half of 20142015 also contributed to a use of cash totaling $471$755 million for the period.

Cash provided by investing activities was $346$386 million for the first six months of 2015 as compared to $346 million during the same period in 2014. In June2015, the Company received $832 million of cash, net of transaction costs, from the sale of the Centrifugal Compression business to Ingersoll Rand. In 2014, the Company received $547 million, of cash, net of transaction costs, from the sale of the Reciprocating Compression business to General Electric. Additionally, capital spendingApproximately $323 million of cash was used to increase the Company’s short term investments portfolio during the first six months of 2014 totaled2015 and capital spending during the period consumed an additional $130 million, as compared to capital spending of $178 million.million during the same period in 2014. Capital needs in the Subsea, Surface Systems and OneSubsea divisions of the DPS segment, along with continued development of the Company's enhanced business information systems,Drilling segments accounted for the majority of the 20142015 capital spending.

Net cash used for financing activities totaled $677$402 million for the first six months of 2015 as compared to $677 million used for financing activities during the same period in 2014. During the first half of 2015, the Company acquired over 4 million shares of treasury stock at a cash cost of $195 million. Approximately $1.2 billion of cash was used to acquire nearly 20 million shares of treasury stock during the first half of 2014. In 2014, the Board of Directors authorized the Company to initiate a commercial paper program with authority to issue up to $500 million in short-term debt. Under this program, the Company issued commercial paper totaling $263had $201 million in principal amount for use in funding the treasury stock purchases referred to above and for other corporate needs.  The average term of the outstanding commercial paper asat December 31, 2014 that was repaid during the first six months of 2015. Contributions from noncontrolling interest owners also added $18 million during the first six months of 2015, primarily relating to their share of a capital contribution made to OneSubsea in June 30, 2014 was approximately 62 days.  The Company currently anticipates being able to continue to issue new commercial paper to fund or extend outstanding commercial paper as it comes due for payment.  During2015. Additionally, during June 2014, the Company repaid $250 million of floating rate notes upon maturity and issued a total of $500 million of new senior notes split equally between 3- and 10-year maturities.
Future liquidity requirements

At June 30, 2014,2015, the Company had $1.6$1.7 billion of cash, cash equivalents and short-term investments. Approximately $493$635 million of the Company'sCompany’s cash, cash equivalents and short-term investments at June 30, 20142015 were in the OneSubsea venture. Dividends of available cash from OneSubsea to the venture partners 40% of which would go to Schlumberger, require approval of the OneSubsea Board of Directors prior to payment. On July 11, 2014, a dividend of €75 million was paid to theThe venture partners with Cameron's non-U.S. partnership receiving €45made a combined cash contribution to OneSubsea totaling $50 million and Schlumberger receiving €30 million.  in June 2015.
Of the remaining cash, cash equivalents and short-term investments not held byin the OneSubsea $657venture, $333 million was located in the United States. Of this amount, approximately $253 million, which included a make-whole premium plus accrued interest, was used to redeem early the Company's $250 million principal amount of 1.6% Senior Notes on July 21, 2014.

Total debt at June 30, 20142015 was nearly $3.4$2.8 billion, most of which was in the United States. Excluding capital leases, approximately $1.0 billion$518 million of the debt obligations have maturities within the next three-year period. The remainder of the Company'sCompany’s long-term debt is due in varying amounts between the last half of 2018 and 2043.

Excluding discontinued operations,Largely as a result of the Company'sweak market conditions which have suppressed new demand, the Company’s backlog decreased slightly from December 31, 2013, mainly due to the cancellation of a large drilling project award in the first quarter of 2014 totaling nearly $243 million, but was still at a near record high at June 30, 2014.  Orders2015 has declined $1.2 billion, or 12%, since December 31, 2014 to approximately $8.4 billion at June 30, 2015. Additionally, orders during the first six months of 20142015 were down nearly 15%25% from the same period in 2013 due mainly to certain large subsea project awards received in the first six months of 2013 that did not repeat during the half of 2014.  The timing of such large project awards are inconsistent period over period. The Company views its backlog of unfilled orders, current order rates, current rig count levels and current and future expected oil and gas prices to be, in varying degrees, leading indicators of and factors in determining its estimates of future revenues, cash flows and profitability levels. Information regarding actual 2014first half 2015 and 20132014 average rig count and commodity price levels and forward-looking twelve-month market-traded futures prices for crude oil and natural gas are shown in more detail under the captions "Market Conditions"“Market Conditions” above. A more detailed discussion of second quarter and year-to-date orders and June 30 backlog levels by segment may be found under "Segment Results"“Segment Results” above.

While the Company believes, based on its past experience, that the current decline in commodity prices and the level of demand are cyclical in nature, we cannot predict the duration or depth of this down cycle. The current weak level of orders and the decline in backlog have negatively impacted our reported revenues and results of operations and will continue to negatively impact those measures of performance in the future until customer demand begins to increase again. As a result of these market conditions, the Company has taken steps to control costs and adjust production levels to match current and expected demand.

In order to extend the length of its currently available credit facilities, the Company, including certain of its subsidiaries, entered into an amended and restated multi-currency credit agreement (the “Credit Agreement”) with various banks and other financial institutions on May 14, 2015. The Credit Agreement is for each period above.$750 million, has a term of five years, expiring on May 14, 2020, and replaces a previously existing $835 million multi-currency credit agreement due to expire in June 2016. The Company currently anticipates growth in consolidated orders, backlogCredit Agreement will be used to finance working capital needs and revenues duringfor other general corporate purposes, including acquisitions, capital expenditures, repurchases of common stock, repayment of debt and issuances of letters of credit. At June 30, 2015, no letters of credit had been issued under the second half of 2014 in relation to the same period in 2013.  Credit Agreement, leaving $750 million available for future use.

The Company also expects full year capital spending on new equipment and facilitieshas a $750 million multi-currency syndicated Revolving Credit Facility expiring April 11, 2017. Up to $200 million of this facility may be between $450used for letters of credit. The Company has issued letters of credit totaling $44 million to $500under the Revolving Credit Facility, leaving $706 million available for 2014, as compared to $520 million during 2013.  The high backlog levels and expected growth however, may increase working capital needs in certain businesses in order in order to meet the increased customer demand.future use at June 30, 2015.

TheDespite current market conditions, the Company believes, based on its current financial condition, existing backlog levels and current expectations for future longer-term market conditions, that it will be able to meet its short- and longer-term liquidity needs with existing cash, cash equivalents and short-term investments on hand, expected cash flow from future operating activities and amounts available for borrowing under the credit facilities described above, including its $835$500 million five-year multi-currency Revolving Credit Facility, which matures on June 6, 2016, and its new three-year $750 million Revolving Credit Facility,commercial paper program described further in Note 8 of the Notes to Consolidated Condensed Financial Statements.  Up to $200 million of this new facilityStatements, and any future credit facilities the Company may be used for letters of credit. The Company also has a bi-lateral $40 million facility with a third-party bank, expiring on February 2, 2015.  enter into.

At June 30, 2014, no amounts had been borrowed under the $835.0 million facility.  The Company had issued letters of credit totaling $77 million under the new $750 million Revolving Credit Facility and $29 million under the $40 million bi-lateral facility, leaving $673 million and $11 million, respectively, available for future use.

In addition, the Company announced in January 2014 that it was exploring strategic alternatives for its Centrifugal Compression business.

The Company has an authorized stock repurchase program whereby the Company may purchase shares directly or indirectly by way of open market transactions or structured programs, including the use of derivatives, for the Company's own account or through commercial banks or financial institutions.  The program, initiated in October 2011, has had a series of authorizations by the Board of Directors totaling $3.2 billion since inception.  At June 30, 2014,2015, the Company had remaining authority for future stock purchases totaling approximately $456$285 million.


Factors That May Affect Financial Condition and Future Results

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 revenue, depends to a large extent upon the level of capital expenditures related to oil and gas exploration, development, production, processing and transmission. Declines, as well as anticipated declines, in oil and gas prices could negatively affect the level of these activities, and could result in the cancellation, modification or rescheduling of existing orders. For example, oil prices began declining during the third quarter of 2014 and continued to decline during the first half of 2015. Average daily prices for West Texas Intermediate and Brent crude during the first six months of 2015 were down more than 40% from the first six months of 2014. Similarly, natural gas prices declined from an average of $4.87 per MMBtu during the first six months of 2014 to $2.80 per MMBtu for the first six months of 2014. These declines in commodity prices began to impact the average number of working rigs which began declining in late 2014 and continued to decline during the first half of 2015. Globally, the average rig count for the first six months of 2015 was down 27% from the first six months of 2014, with even steeper declines occurring in the United States and Canada. These market conditions negatively affected our second quarter and first half 2015 results and are expected to continue to significantly affect future exploration and production activity levels and, therefore, demand for the Company’s products and services at least through the remainder of 2015. During the first half of 2015 there have been numerous deepwater projects deferred and deepwater rigs idled. Efforts are also being made by drilling contractors to defer deliveries of new deepwater rigs currently under construction. In addition to a decline in future orders and revenues, the Company expects to incur additional costs as it continues to adjust, as necessary, its commercial, manufacturing and support operations levels to meet expected future customer demand. See also the discussion in “Market Conditions” above for the second quarter of 2015 as compared to the second quarter of 2014.
Cancellation, downsizing or delays of orders in backlog are possible.

As described above, commodity prices have declined significantly since mid-2014 which has resulted in various oil and gas exploration and production companies announcing spending cuts or deferrals in their 2015 capital spending plans, as well as headcount reductions. At current price levels, certain projects, particularly those in deepwater environments and unconventional resource regions, may become uneconomical for the risk involved. Certain customers that are more highly leveraged may also experience concerns regarding future projected cash flows based on current price levels. These factors could result in existing orders in backlog being cancelled, downsized or future shipment dates may be delayed, all of which could further negatively impact the Company’s future profitability.
At June 30, 2015, the Company’s backlog was approximately $8.4 billion, down 12% from December 31, 2014.  An example of a cancellation of an existing order is the reversal of $243 million of backlog during the first quarter of 2014 as the result of a customer cancellation of a large drilling project award issued in 2012.  Another example of a delay or downsizing of a previous award is the announcement by a customer in late 2013 of the deferral of its large project in the North Sea in order to work with its partners to improve the project’s economics.  This project was awarded to Cameron earlier in 2013.  As a result of the Company’s collaboration with our customer, we reduced the scope of this project in our backlog during the second quarter of 2015 to $416 million.  Additionally, the Company’s primary customer in Brazil, has announced plans for a significant reduction in future capital spending and is seeking to delay, and defer or cancel some existing projects, including projects for which the Company has direct or indirect contractual arrangements to supply products or services over a multi-year period.  While the Company’s contracts provide protection against cancellations, the Company continues to engage in discussions with the customer to reach a mutually agreeable solution.  At the end of the second quarter of 2015, the Company’s backlog included approximately $1 billion of direct or indirect product and services for this customer.
The inability of the Company to deliver its backlog or future orders on time could affect the Company's futureCompany’s sales and profitability and its relationships with its customers.

At June 30, 2014, the Company's backlog was approximately $11 billion, excluding discontinued operations.  The ability to meet customer delivery schedules for thison the Company’s existing backlog, as well as future orders, 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 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 future order rates and the timing
Portions of the Company's common stockbacklog for our Subsea and other publicly-traded financial instruments.

Expansion of the Company's offerings in the drilling market creates additional risks not previously present.

The Company's acquisitions of LeTourneau Technologies Drilling Systems, Inc. and the TTS Energy Division of TTS Group ASA (TTS) expanded the Company's portfolio of products and services availablesegments are subject to customers involved in oil and gas drilling activities.  These acquisitions brought large drilling rig construction projects not previously offered and a record backlog.  As a result of both, the complexity ofheightened execution within this business has increased from that of the past.  Also, the Company has recently struggled to increase production capacity to deliver its record backlog.

Large drilling rig projects are accounted for using accounting rules for production-type and construction-type contracts.  In accordance with this guidance, the Company estimates the expected margin on these projects and recognizes this margin as units are completed.  These projects (i) require significantly more engineering and project management expertise than are needed for projects involving the supply of drilling stacks and associated equipment to customers, (ii) are larger in financial scope and (iii) require longer lead times than many other projects involving the Company's Drilling Systems business.  Additionally, unplanned difficulties in engineering and managing the construction of such major projects could result in cost overruns and financial penalties which could negatively impact the Company's margins and cash flow.   Similar to subsea systems projects described below, a reduction in expected margins on these projects from such unplanned events would result in a cumulative adjustment to reduce margins previously recognized in the period a change in estimate is determined.

Execution of subsea systems projects exposes the Company to risks not present in its other businesses.risk.

Cameron is involved in projects to provide customers with deepwater stacks and complete drilling packages for jackup rigs and, through OneSubsea,our Subsea segment, is a significant participant in the subsea systems projects market. This market is different from mostSome of the Company's otherprojects for these markets since subsea systems projects are larger incarry heightened execution risk because of their scope and complexity, in terms of both technical and logistical requirements. SubseaSuch projects typically (i) may often involve long lead times, (ii) are larger in financial scope, (iii) require substantial engineering resources to meet the technical requirements of the project and (iv) often involve the application of existing technology to new environments and, in some cases, may require the development of new technology. The Company's OneSubsea business hasAs a backlogsubset of approximately $4 billion for subsea systems projectsits total backlog at June 30, 2014.2015, the Company’s Drilling segment had projects fitting this risk profile that amounted to approximately $930 million. As a subset of its total backlog at June 30, 2015, the Company’s Subsea segment had projects fitting this risk profile that amounted to approximately $2.2 billion. To the extent the Company experiences unplanned difficulties in meeting the technical and/or delivery requirements of the projects, or has difficulty fully integrating the businesses contributed by Schlumberger to OneSubsea into its operations, the Company'sCompany’s earnings or liquidity could be negatively impacted. As the integration of the Schlumberger and Cameron businesses continues, issues may arise as we continue to refine the technologies and scale up the combined operations to meet customer demand.  The Company accounts for its drilling and subsea projects, as it does its separation and drilling projects, using accounting rules for construction-type and production typeproduction-type contracts. Factors that may affect future project costs and margins include the ability to properly execute the engineering and design phases consistent with our customers'customers’ expectations, production efficiencies obtained, and the availability and costs of labor, materials and subcomponents. These factors can impact the accuracy of the Company'sCompany’s estimates and materially impact the Company'sCompany’s future period earnings. If the Company experiences cost overruns, the expected margin could decline. Were this to occur, in accordance with the accounting guidance, the Company would record a cumulative adjustment to reduce the margin previously recorded on the related project in the period a change in estimate is determined. SubseaDeepwater stack and jackup complete drilling packages, and subsea systems projects, accounted for approximately 14.9%8% and 15%, respectively, of total revenues infor the first six months of 2014.2015.
As a designer, manufacturer, installer and servicer of oil and gas pressure control equipment, the Company may be subject to liability for personal injury, property damage and environmental contamination should such equipment fail to perform to specifications.expectations.

Cameron provides products and systems to customers involved in oil and gas exploration, development and production, as well as in certain other industrial markets. Some of the Company'sCompany’s equipment is designed to operate in high-temperature and/or high-pressure environments on land, on offshore platforms and on the seabed, and some equipment is designed for use in hydraulic fracturing operations. Cameron also provides aftermarket parts and repair services at numerous facilities located around the world, oras well as at customer sites for this and othertype of equipment. Because of applications to which the Company'sCompany’s products and services are put, particularly those involving the high temperature and/or pressure environments, a failure of such equipment, or a failure of our customer to maintain or operate the equipment properly, could cause damage to the equipment, damage to the property of customers and others, personal injury and environmental contamination, onshore or offshore, leading to claims against Cameron.

Certain of the Company’s risk mitigation strategies may not be fully effective.

The Company relies on customer indemnifications and third-party insurance as part of its risk mitigation strategy. There is, however, an increasing reluctance of customers to provide what had been typical oilfield indemnifications for pollution, consequential losses, property damage, and personal injury and death, and a reluctance, even refusal, of counterparties to honor their contractual indemnity obligations when given. In addition, insurance companies may refuse to honor their policies.

An example of both is the Company’s experience in the Deepwater Horizon matter. The Company’s customer denied that it owed any indemnification under its contract with us, and when called on to participate in the Company’s settlement with BP Exploration and Production Inc., one of the seven insurers refused to provide coverage. The Company subsequently sued its insurer and won a judgment for the full policy amount plus interest and costs, but the insurer continues to litigate the matter and has appealed the judgment.
The implementation of an upgraded business information system may disrupt the Company'sCompany’s operations or its system of internal controls.controls.

The Company has a project underway to upgrade its SAP business information systems worldwide. The first stage of this multi-year effort was completed at the beginning of the third quarter of 2011 with the deployment of the upgraded system for certain businesses withinto the Company's PCS segment.  CertainCompany’s process systems and compression businesses. Since then, other businesses began operating on the upgraded system during 2012.and business functions have been migrated in stages. As of December 2013,June 30, 2015, nearly all businesses within the V&M segment, were utilizing the upgraded system and, effective July 1, 2014; the Surface Systems division ofsegment, the DPS segment beganCompany’s worldwide engineering and human resource functions, as well as other corporate office activities are now operating on the upgraded system. The Drilling Systems and OneSubsea divisions of the DPS segment and the corporate office functions are expected to bewas migrated to the upgraded system duringin July 2015, and the remainder of 2014 and beyond, with completion anticipatedOneSubsea business is scheduled to begin using the upgraded system in 2016. The DPSDrilling segment and V&M segmentsthe OneSubsea business are major contributors to the Company'sCompany’s consolidated revenues and income before income taxes.

As this system continues to be deployed throughout the Company, delays or difficulties may be encountered in effectively and efficiently processing transactions and conducting business operations, including project management, until such time as personnel are familiar with all appropriate aspects and capabilities of the upgraded systems.

The Company'sCompany’s operations and information systems are subject to cybersecurity risks.

Cameron continues to increase its dependence on digital technologies to conduct its operations. Many of the Company'sCompany’s files are digitized and more employees are working in almost paperless environments. Additionally, the hardware, network and software environments to operate SAP, the Company'sCompany’s main enterprise-wide operating system, have been outsourced to third parties. Other key software products used by the Company to conduct its operations either reside on servers in remote locations or are operated by the software vendors or other third parties for the Company'sCompany’s use as "Cloud-based"“Cloud-based” or "Web-based"“Web-based” applications. The Company has also outsourced certain information technology development, maintenance and support functions. As a result, the Company is exposed to potentially severe cyber incidents at both its internal locations and outside vendor locations that could result in a theft of intellectual property and/or disruption of its operations for an extended period of time resulting in the loss of critical data and in higher costs to correct and remedy the effects of such incidents, although no such material incidents have occurred to date.date to the Company’s knowledge.

Fluctuations in currency markets can impact the Company'sCompany’s profitability.

The Company has established multiple "Centers“Centers of Excellence"Excellence” facilities for manufacturing such products as subsea trees, subsea chokes, subsea production controls and blowout preventers. These production facilities are located in the United Kingdom, Brazil, Romania, Italy, Norway and other European and Asian countries. To the extent the Company sells these products in U.S. dollars, the Company'sCompany’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. For further information on the use of derivatives to mitigate certain currency exposures, see Item 3, "Quantitative“Quantitative and Qualitative Disclosures about Market Risk"Risk” below and Note 14 of the Notes to Consolidated Condensed Financial Statements.
The Company'sCompany’s operations expose it to risks of non-compliance with numerous countries'countries’ import and export laws and regulations, and with various nations'nations’ trade regulations including U.S. sanctions.

The Company'sCompany’s operations expose it to trade and import and export regulations in multiple jurisdictions. In addition to using "Centers“Centers of Excellence"Excellence” for manufacturing products to be delivered around the world, the Company imports raw materials, semi-finished goods and finished products into many countries for use in country or for manufacturing and/or finishing for re-export and import into another country for use or further integration into equipment or systems. Most movement of raw materials, semi-finished or finished products by the Company involves exports and imports. As a result, compliance with multiple trade sanctions and embargoes and import and export laws and regulations poseposes a constant challenge and risk to the Company. The Company has received a number of inquiries from U.S. governmental agencies, including the U.S. Securities and Exchange Commission and the Office of Foreign Assets Control, regarding compliance with U.S. trade sanction and export control laws,regulations, the most recent of which was received in December 2012 and replied to by the Company in January 2013. The Company has undergone and will likely continue to undergo governmental audits to determine compliance with export and customs laws and regulations.
The United States and the European Union (EU) also recently imposed sanctions on various sectors of the Russian economy and on transactions with certain Russian nationals and entities. These sanctions may severely limit the amount of future business the Company does with customers involved in activities in Russia. As of June 30, 2015, approximately 1% of the Company’s backlog related to future deliveries to customers doing business in Russia. Sales to customers doing business in Russia during the first six months of 2015 totaled less than 1% of the Company’s sales during the period. In addition, the sanctions of the U.S. and the EU are inconsistent and neither is, as yet, well defined, both of which factors increase the risk of an unintended violation.

The Company'sCompany’s operations expose it to political and economic risks and instability due to changes in economic conditions, civil unrest, foreign currency fluctuations, and other risks, such as local content requirements, inherent to international businesses.

The political and economic risks of doing business on a worldwide basis include the following:
•volatility in general economic, social and political conditions;
•the effects of civil unrest and sanctions imposed by the United States and other governments on transactions with various countries, such as Iran;
•the effects of civil unrest and, in some cases, military action on the Company's business operations, customers and employees, such as that recently occurring in several countries in the  Middle East, in Ukraine and in Venezuela;
•exchange controls or other similar measures that result in restrictions on repatriation of capital and/or income, such as those involving the currencies of, and the Company's operations in, Angola and Nigeria; and
•reductions in the number or capacity of qualified personnel.

volatility in general economic, social and political conditions;

the effects of civil unrest and, in some cases, military action on the Company’s business operations, customers and employees, such as that recently occurring in several countries in the Middle East, in Ukraine and in Venezuela;

exchange controls or other similar measures which result in restrictions on repatriation of capital and/or income, such as those involving the currencies of, and the Company’s operations in, Angola and Nigeria; and

reductions in the number or capacity of qualified personnel.
In recent months, civil unrest and military action have increased in Iraq which may impact the ability of that country to continue to produce and export oil at current levels. Such unrest may also jeopardize the Company'sCompany’s in-country investments and on-going business activities supporting Iraq'sIraq’s oil and gas production infrastructure. At June 30, 2014,2015, less than 1% of the Company'sCompany’s backlog related to future deliveries to customers doing business in Iraq. Additionally, less than 1% of the Company'sCompany’s property, plant and equipment waswere located in Iraq and less than 1% of the Company's receivables were for sales into Iraq to multinational operators and to Iraqi drilling and production companies.Iraq. The Company is also evaluating its options under the force majeure clauses of each of the major contracts with its customers doing business in Iraq in the event the current situation in that country continues to deteriorate.

Cameron also has manufacturing and service operations that are essential parts of its business in other 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. Recent increases in activity levelsOperating in certain of these regions havehas increased the Company'sCompany’s risk of identifying and hiring sufficient numbers of qualified personnel to meet increased customer demand in selected locations. The Company also purchases a large portion of its raw materials and components from a relatively small number of foreign suppliers in China, India and other developing countries. The ability of these suppliers to meet the Company'sCompany’s demand could be adversely affected by the factors described above.
In addition, customers in countries such as Angola and Nigeria increasingly are requiring the Company to accept payments in the local currencies of these countries. These currencies do not currently trade actively in the world'sworld’s foreign exchange markets.

The Company also has variouscertain manufacturing and aftermarketservices operations in Venezuela that contributed $37 million inless than 1% of the Company’s consolidated revenues during the first six months of 2014.2015. The economy in Venezuela is highly inflationaryinflationary. As a result, the Company’s operations in Venezuela are accounted for as having a U.S. dollar functional currency and becoming more regulated.  Thesethe Company considers its earnings in Venezuela to be permanently reinvested. Because of the continuing economic turmoil in Venezuela and further statutory changes which impact exchange rates companies are allowed to use by the Venezuelan government when converting bolivars into dollars, Cameron recognized a gain of $4 million relating to the impact on its bolivar-denominated net liabilities of a devaluation of the Venezuelan currency from the official exchange rate used in the past to a market-based rate during the first six months of 2015. The factors described above which led to the currency devaluation, along with recent civil unrest, create political and economic uncertainty with regard to theirthe impact on the Company'sCompany’s continued operations in this country.
The Venezuelan government has maintained currency controls and a fixed official exchange rate since February 2003.  In February 2013,Net assets associated with the Venezuelan government devalued its currency from 4.3 bolivars to the U.S. dollar to an official rate of 6.3 bolivars to the U.S. dollar.  Since then, the Company has used the official rate of 6.3 bolivars to the U.S. dollar to remeasure non-functional currency transactions in its financial statements.  Due to the highly inflationary status of the Venezuelan economy, the Company'sCompany’s operations in Venezuela are accounted for as U.S. dollar functional currency entities.  In addition, the Company considers its earnings in Venezuela to be permanently reinvested.    In early 2014, Venezuelan government officials indicated that this official rate will increasingly be reserved only for settlement of U.S. dollar denominated obligations related to purchases of "essential goods and services."  Through the end of the second quarter of 2014, Petroleos de Venezuela (PDVSA), the Company's primary customer, has continued to pay its U.S. dollar denominated obligations to the Company at the official rate. Recent events, however, create uncertainty as to whether this will continue.  First, in January 2014, the Venezuelan government significantly expanded the use of the Supplementary Foreign Currency Administration System (SICAD) auction rate and indicated this rate (SICAD 1) would be used for certain transactions and activities.  In February 2014, the Venezuelan government signed into law a plan to open a new exchange control mechanism (SICAD 2) which may be available to all entities for all transactions.  At June 30, 2014, the published SICAD 1 rate was 10.6 bolivars to the U.S. dollar and the published SICAD 2 rate was2015 totaled approximately 49.98 bolivars to the U.S. dollar.  Recently, Rafael Ramirez, the Venezuelan Vice President for the Economy and Oil Minister announced that the three exchange rates would progressively converge, with a new system involving a single unified rate that could be in place by the end$46 million.
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Increasingly, some of the Company'sCompany’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'sCompany’s operations expose it to risks resulting from differing and/or increasing tax rates.

Economic conditions around the world have resulted in decreased tax revenues for many governments, which have led and could continue to lead to changes in tax laws in countries where the Company does business, including further changes in the United States. Changes in tax laws could have a negative impact on the Company'sCompany’s future results.

The Company'sCompany’s operations require it to deal with a variety of cultures, as well as agents and other intermediaries, exposing it to anti-corruption compliance risks.

Doing business on a worldwide basis necessarily involves exposing the Company and its operations to risks inherent in complying with the laws and regulations of a number of different nations. These laws and regulations include various anti-bribery and anti-corruption laws.

The Company does business and has operations in a number of developing countries that have relatively underdeveloped legal and regulatory systems 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 in which 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), the United Kingdom'sKingdom’s Bribery Act of 2010, and similar statutes of other nations, in these environments presentspresent greater challenges to the Company than is the case in other, more developed countries.
Additionally, the Company'sCompany’s business involves the use of agents and other intermediaries, such as customs clearance brokers, in these countries as well as others. As a result, the risk to the Company of compliance violations is increased because actions taken by any of them when attempting to conduct business on our behalf could be imputed to us by law enforcement authorities.

As an example, various employees and former employees of the Company’s primary customer in Brazil are being investigated currently over allegations of bribery and other acts of corruption. This investigation, along with the current recessionary economic conditions in Brazil, is, at present, having a negative impact on future orders and growth prospects for the Company’s operations in Brazil. Sales to customers in Brazil accounted for approximately 5% of the Company’s consolidated revenues during the first six months of 2015, as well as the first six months of 2014.

The Company is subject to environmental, health and safety laws and regulations that expose the Company to potential liability and proposed new regulations that would restrict activities to which the Company currently provides equipment and services.

The Company'sCompany’s operations are subject to a variety of national and state, provincial 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'sCompany’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.

The Company provides equipment and services to companies employing hydraulic fracturing or "fracking"“fracking” and could be adversely impacted by additional regulations of this enhanced recovery technique.

Environmental concerns have been raised regarding the potential impact on underground water supplies of 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. Recently,On March 20, 2015, the U.S. Interior Department’s Bureau of Land Management (BLM) released a final rule regulating hydraulic fracturing activities on Federal and Indian lands. The final rule includes new well-bore integrity requirements, imposes standards for interim storage of recovered waste fluids, and requires notifications and waiting periods for key parts of the fracturing process, which could lead to delays in fracturing and/or drilling operations. The rule also mandates disclosure of the chemicals used in the process. Additionally, on April 7, 2015, the U.S. Environmental Protection Agency (EPA) published a proposed rule that would prohibit the disposal of unconventional oil and natural gas wastewater at publicly owned treatment works.

A number of U.S. states have also proposed regulations regarding disclosure of chemicals used in fracking operations or have temporarily suspended issuance of permits for such operations. The State of New York implemented a statewide ban on hydraulic fracturing at the beginning of 2015 which limits natural gas production from a portion of the Marcellus Shale region. Additionally, the United States Environmental Protection Agency (EPA)EPA issued rules, which becomebecame effective in January 2015, that are designed to limit the release of volatile organic compounds, or pollutants, from natural gas wells that are hydraulically fractured.  The EPA has published draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuels and is continuing to study whether the fracking process has any negative impact on underground water supplies.  A draft of the final report on the results of the study is expected in 2014.  

Should these regulations, or additional regulations and bans by governments, continue to restrict or further curtail hydraulic fracturing activities, the Company'sCompany’s revenues and earnings could be negatively impacted.

Enacted and proposed climate protection regulations and legislation may impact the Company'sCompany’s operations or those of its customers.

The EPA has made a finding under the United States Clean Air Act that greenhouse gas emissions endanger public health and welfare and the EPA has enacted regulations requiring monitoring and reporting by certain facilities and companies of greenhouse gas emissions. In June 2014, the U.S. Supreme Court prohibited the EPA from being able to require limits on carbon dioxide and other heat trapping gases from sources that would otherwise not need an air pollution permit.

Also, in June 2014, the EPA, acting under President Obama'sObama’s Climate Action Plan, proposed its Clean Power Plan, which would set U.S. state-by-state guidelines for power plants to meet by 2030 to cut their carbon emissions by 30% nationwide from 2005 levels. The guidelines are also intended to cut pollution, nitrogen oxides and sulfur dioxide by more than 25% during the same period. Under the Clean Power Plan, states are to develop plans to meet state-specific goals to reduce carbon pollution and submit those plans to the EPA by June 2016, with a later deadline provided under certain circumstances. While these proposed rules may hasten the switch from coal to cleaner burning fuels such as natural gas, the overall long-term economic impact of the plan is uncertain at this point.

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.
To the extent the Company'sCompany’s customers are subject to 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 current or anticipated levels in certain jurisdictions, which could negatively impact their demand for the Company'sCompany’s products and services.

To the extent Cameron becomes 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'sCompany’s cost of doing business in certain jurisdictions, including the United States, and may require expenditures on a number of its facilities and possibly on modifications of certain of its products.

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 have the effect of dampening demand for oil and gas production, they could lower spending by customers for the Company'sCompany’s products and services.

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.Environmental Remediation

Demand for most of the Company's products and services, and therefore its revenue, depends to a large extent upon the level of capital expenditures related to oil and gas exploration, development, production, 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, natural gas spot prices in the United States declined during the first half of 2012 to less than $2 per MMBtu, the lowest level in the last decade.  Although natural gas prices have subsequently increased, current rig count levels associated with dry gas extraction activities have not fully recovered to previous levels.  This price decline negatively impacted 2012 order levels by certain of the Company's customers which affected the Company's 2012 and 2013 revenues and profitability.  See also the discussion in "Market Conditions" above.
Environmental Remediation
The Company'sCompany’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 systemHealth, Safety and activeEnvironmental (HSE) Management System and corporate third-party regulatory compliance audit program, believes it is in substantial compliance with these regulations.

The Company is heir to a number of older manufacturing plants that conducted operations in accordance with the standards of the time, but which have since changed. The Company has undertaken clean-up efforts at these sites and now conducts its business in accordance with today'stoday’s standards. The Company'sCompany’s clean-up efforts have yielded limited releases of liability from regulators in some instances, and have allowed sites with no current operations to be sold. The Company conducts environmental due diligence prior to all new site acquisitions. For further information, refer to Note 13 of the Notes to Consolidated Condensed Financial Statements.

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. 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. 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'sCompany’s sites.

Cameron has implemented a corporate "HSEHSE Management System" based onSystem that incorporates many of 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 has also implementedhas a corporate regulatory compliance audit program to verify facility compliance with environmental, health and safety laws and regulations.  The compliance program employs orwhich uses independent third-party auditors to audit facilities on a regular basis specific to verify facility compliance with the relevant country, region and local legal requirements.environmental, health and safety laws and regulations. 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 which are tracked on the corporate HSE data base.

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Item 3.
Item 3.Quantitative and Qualitative Disclosures about Market Risk

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'sCompany’s market risk exposure in financial instruments follows.

Foreign Currency Exchange Rates

A large portion of the Company'sCompany’s operations consist of manufacturing and sales activities in foreign jurisdictions, principally in Europe, Canada, West Africa, the Middle East, Latin America, China and other countries in the Pacific Rim. As a result, the Company'sCompany’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'sCompany’s financial results. The impact on the Company'sCompany’s financial results of gains or losses arising from foreign currency denominated transactions, if material, have been described under "Results“Results of Operations"Operations” in this Management'sManagement’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 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, 2015. 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 various wholly-owned international subsidiaries. Many of these contracts have been designated as and are accounted for as cash flow hedges, with changes in the fair value of those contracts recorded in accumulated other comprehensive income (loss) in the period such change occurs. Certain other contracts, many of which are centrally managed, are intended to offset other foreign currency exposures but have not been designated as hedges for accounting purposes and, therefore, any change in the fair value of those contracts are reflected in earnings in the period such change occurs. The Company expects to expand its use of such contracts in the future.

Capital Markets and Interest Rates

The Company is subject to interest rate risk on its variable-interest rate and commercial paper borrowings. Variable-rate debt, where the interest rate fluctuates periodically, exposes the Company'sCompany’s cash flows to variability due to changes in market interest rates. Additionally, the fair value of the Company'sCompany’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 from time to time 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 1.15% and 1.4% 3-year Senior Notes, the 3.6%, 3.7%, 4.0%, 4.5% and 6.375% 10-year Senior Notes and the 5.125%, 5.95% and 7.0% 30-year Senior Notes are principally dependent on prevailing interest rates. The fair value of the commercial paper and other short-term debt is expected to approximate its book value.

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.

Derivatives Activity

Total gross volume bought (sold) by notional currency and maturity date on open derivative contracts at June 30, 2015 was as follows:

   Notional Amount - Buy  Notional Amount - Sell 
(amounts in millions) 2015  2016  2017  Total  2015  2016  2017  2018  Total 
Foreign exchange forward contracts -                  
Notional currency in:                  
Australian dollar  –   –   –   –   (1)  –   –   –   (1)
Euro  143   60   36   239   (49)  (11)  –   –   (60)
Malaysian ringgit  275   61   –   336   (16)  –   –   –   (16)
Norwegian krone  412   579   31   1,022   (31)  (64)  (4)  –   (99)
Pound Sterling  140   9   –   149   (25)  (1)  –   –   (26)
U.S. dollar  11   30   2   43   (411)  (260)  (101)  (1)  (773)

Item 4.
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'sCompany’s Sarbanes-Oxley Disclosure Committee and the Company'sCompany’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company'sCompany’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'sCompany’s disclosure controls and procedures were effective as of June 30, 20142015 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'sSEC’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'sCompany’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'sCompany’s internal control over financial reporting during the quarter ended June 30, 2014.2015.

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41
PART II — OTHER INFORMATION

Item 1.
Item 1.Legal Proceedings

The Company has been and continues to be named as a defendant in a number of multi-defendant, multi-plaintiff tort lawsuits. At June 30, 2014,2015, the Company'sCompany’s Consolidated Condensed Balance Sheet included a liability of approximately $16$18 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.

Item 1A.
Item 1A.Risk Factors

The information set forth under the caption "Factors“Factors That May Affect Financial Condition and Future Results"Results” on pages 3332 – 3839 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item 2.
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

The Company has an authorized stock repurchase program whereby the Company may purchase shares directly or indirectly by way of open market transactions or structured programs, including the use of derivatives, for the Company's own account or through commercial banks or financial institutions.  The program, initiated in October 2011, has had a series of authorizations by the Board of Directors totaling $3.2 billion since inception.  At June 30, 2014,2015, the Company had remaining authority for future stock purchases totaling approximately $456$285 million.

Shares of common stock purchased and placed in treasury during the three months ended June 30, 20142015 under the Board'sBoard’s authorization program described above were as follows:

  
Period  
 Total number of shares purchased during the period  Average price paid per share  Cumulative number of shares purchased as part of repurchase program  
Maximum number of shares that may yet be purchased under
repurchase program(1)
 
4/1/14 – 4/30/14  3,788,207  $62.73   46,362,733   2,815,393 
5/1/14 – 5/31/14  452,100  $63.62   46,814,833   7,416,387 
6/1/14 – 6/30/14  276,361  $65.76   47,091,194   6,736,137 
Total  4,516,668  $63.00   47,091,194   6,736,137 
 
Period
 Total number of shares purchased during the period  Average price paid per share  Cumulative number of shares purchased as part of repurchase program  
Maximum number of shares that may yet be purchased under
repurchase program(1)
 
4/1/15 – 4/30/15  278,700  $46.35   59,613,149   5,193,109 
5/1/15 – 5/31/15  –  $–   59,613,149   5,546,196 
6/1/15 – 6/30/15  –  $–   59,613,149   5,436,056 
Total  278,700  $46.35   59,613,149   5,436,056 

(1)Based upon month-end stock price. At June 30, 2014,2015, the closing stock price was $67.71$52.37 per share.


Item 3.
Item 3.Defaults Upon Senior Securities

 
None

Item 4. Mine Safety Disclosures
N/A
Item 4.Mine Safety Disclosures

  N/A
40

Item 5.
Item 5.Other Information

(a)Information Not Previously Reported in a Report on Form 8-K

 
None

(b)Material Changes to the Procedures by Which Security Holders May Recommend Board Nominees.

There have been no material changes to the procedures enumerated in the Company'sCompany’s definitive proxy statement filed on Schedule 14A with the Securities and Exchange Commission on April 1, 2014March 27, 2015 with respect to the procedures by which security holders may recommend nominees to the Company'sCompany’s Board of Directors.

Item 6.
Item 6.Exhibits

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
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43

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date:  July 24, 2014
2015		CAMERON INTERNATIONAL CORPORATION
 (Registrant)
  
 By:
By:  /s/ Charles M. Sledge
  Charles M. Sledge
 
Senior Vice President and Chief Financial Officer
and authorized to sign on behalf of the Registrant
 
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44

EXHIBIT INDEX

Exhibit NumberDescription
31.1
Certification
31.2
Certification
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.
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Extension Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document






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