

Delaware	76-0451843
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

1333 West Loop South, Suite 1700, Houston, Texas	77027
(Address of Principal Executive Offices)	(Zip Code)

713/513-3300

(~~Registrant's~~Registrant’s Telephone Number, Including Area Code)

N/A

(Former Name, Former Address and Former Fiscal Year, if Changed Since LastReport)

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 Rþ No £o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes Rþ No £o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of ~~"large~~“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 Rþ Accelerated filer £o

Non-accelerated filer £o (Do not check if a smaller reporting company) Smaller reporting company £o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £o No Rþ

Number of shares outstanding of ~~issuer's~~issuer’s common stock as of October ~~16, 2014~~15, 2015 was ~~197,446,080.~~190,921,638.

TABLE OF CONTENTS



PART I — FINANCIAL INFORMATION		3 1

Item 1.	Financial Statements	3 1

Consolidated Condensed Statements of Comprehensive Income		3 1

Consolidated Condensed Balance Sheets		4 2

Consolidated Condensed Statements of Cash Flows		5 3

Consolidated Condensed Statement of Changes in Equity		6 4

Notes to Consolidated Condensed Financial Statements		7 5

Item 2. ~~Management's~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19 20

Item 3.	Quantitative and Qualitative Disclosures ~~About~~about Market Risk	39 40

Item 4.	Controls and Procedures	40 41

PART II — OTHER INFORMATION		40 42

Item 1.	Legal Proceedings	40 42

Item 1A.	Risk Factors	40 42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40 42

Item 3.	Defaults Upon Senior Securities	41 42

Item 4.	Mine Safety Disclosures	41 42

Item 5.	Other Information	41 42

Item 6.	Exhibits	42 43

SIGNATURES		43 44

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Cameron International Corporation

~~CAMERON INTERNATIONAL CORPORATION~~

~~CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME~~Consolidated Condensed Statements of Comprehensive Income

(dollars and shares in millions, except per share data)

Three Months Ended
September 30,

Nine Months Ended
September 30,

2014 2013 2014 2013
(unaudited)

REVENUES $ 2,678 $ 2,317 $ 7,577 $ 6,407
COSTS AND EXPENSES:
Cost of sales (exclusive of depreciation and amortization shown separately below)
1,915 1,649 5,456 4,547
Selling and administrative expenses 320 325 970 920
Depreciation and amortization 83 79 256 211
Interest, net 36 23 98 74
Other costs (see Note 3) 19 14 62 80
Total costs and expenses 2,373 2,090 6,842 5,832

Income from continuing operations before income taxes 305 227 735 575
Income tax provision (70 ) (49 ) (179 ) (136 )
Income from continuing operations 235 178 556 439
Income from discontinued operations, net of income taxes 3 14 31 42
Net income 238 192 587 481

Less: Net income attributable to noncontrolling interests 13 3 29 3
Net income attributable to Cameron stockholders $ 225 $ 189 $ 558 $ 478

Amounts attributable to Cameron stockholders:
Income from continuing operations $ 222 $ 175 $ 527 $ 436
Income from discontinued operations 3 14 31 42
Net income attributable to Cameron stockholders $ 225 $ 189 $ 558 $ 478

Earnings per common share attributable to Cameron stockholders:
Basic -
Continuing operations $ 1.11 $ .72 $ 2.55 $ 1.78
Discontinued operations .01 .06 .15 .17
Basic earnings per share $ 1.12 $ .78 $ 2.70 $ 1.95

Diluted -
Continuing operations $ 1.10 $ .72 $ 2.53 $ 1.77
Discontinued operations .01 .06 .15 .17
Diluted earnings per share $ 1.11 $ .78 $ 2.68 $ 1.94

Shares used in computing earnings per common share:

Basic 201 243 207 246
Diluted 203 244 208 247

Comprehensive income $ 29 $ 282 $ 389 $ 445

Less: Comprehensive income (loss) attributable to noncontrolling interests (40 ) 29 (17 ) 29
Comprehensive income attributable to Cameron stockholders $ 69 $ 253 $ 406 $ 416



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(unaudited)

REVENUES	$	2,208		$	2,678		$	6,703		$	7,577
COSTS AND EXPENSES:
Cost of sales (exclusive of depreciation and amortization shown separately below)	1,530			1,915			4,723			5,456
Selling and administrative expenses	256			320			821			970
Depreciation and amortization	86			83			264			256
Interest, net	34			36			105			98
Asset charges (see Note 4)	18			—			581			44
Other costs (gains), net (see Note 4)	26			19			77			18
Total costs and expenses	1,950			2,373			6,571			6,842

Income from continuing operations before income taxes	258			305			132			735
Income tax provision	(44		)	(70		)	(144		)	(179		)
Income (loss) from continuing operations	214			235			(12		)	556
Income (loss) from discontinued operations, net of income taxes	(1		)	3			431			31
Net income	213			238			419			587

Less: Net income attributable to noncontrolling interests	26			13			43			29
Net income attributable to Cameron stockholders	$	187		$	225		$	376		$	558

Amounts attributable to Cameron stockholders:
Income (loss) from continuing operations	$	188		$	222		$	(55	)	$	527
Income (loss) from discontinued operations	(1		)	3			431			31
Net income attributable to Cameron stockholders	$	187		$	225		$	376		$	558

Earnings (loss) per common share attributable to Cameron stockholders:
Basic -
Continuing operations	$	0.99		$	1.11		$	(0.29	)	$	2.55
Discontinued operations	(0.01		)	0.01			2.25			0.15
Basic earnings per share	$	0.98		$	1.12		$	1.96		$	2.70

Diluted -
Continuing operations	$	0.98		$	1.10		$	(0.29	)	2.53
Discontinued operations	(0.01		)	0.01			2.25			0.15
Diluted earnings per share	$	0.97		$	1.11		$	1.96		$	2.68
Shares used in computing earnings per common share:
Basic	191			201			192			207
Diluted	192			203			192			208

Comprehensive income (loss)	$	(8	)	$	29		$	14		$	389
Less: Comprehensive loss attributable to noncontrolling interests	(41		)	(40		)	(55		)	(17		)
Comprehensive income attributable to Cameron stockholders	$	33		$	69		$	69		$	406

The accompanying notes are an integral part of these statements.

Table of Contents

Cameron International Corporation

~~CAMERON INTERNATIONAL CORPORATION~~

~~CONSOLIDATED CONDENSED BALANCE SHEETS~~Consolidated Condensed Balance Sheets

(dollars in millions, except shares and per share data)


	September 30, 2014			December 31, 2013			September 30, 2015			December 31, 2014
	(unaudited)						(unaudited)
ASSETS
Cash and cash equivalents	$	1,058		$	1,813		$	1,627		$	1,513
Short-term investments		115			41		321			113
Receivables, net		2,580			2,719		2,088			2,389
Inventories, net		3,130			3,133		2,659			2,929
Other current assets		378			463		481			391
Assets of discontinued operations		235			–		—			217
Total current assets		7,496			8,169		7,176			7,552
Plant and equipment, net		1,941			2,037		1,733			1,964
Goodwill		2,607			2,925		1,796			2,461
Intangibles, net		817			904		613			728
Other assets		228			214		291			187
TOTAL ASSETS	$	13,089		$	14,249		$	11,609		$	12,892

LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt	$	403		$	297		$	38		$	263
Accounts payable and accrued liabilities		3,456			3,883		2,786			3,748
Accrued income taxes		97			80		342			168
Liabilities of discontinued operations		107			–		—			90
Total current liabilities		4,063			4,260		3,166			4,269
Long-term debt		2,809			2,563		2,794			2,819
Deferred income taxes		199			277		227			193
Other long-term liabilities		222			233		162			167
Total liabilities		7,293			7,333		6,349			7,448
Stockholders' Equity:
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at September 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 September 30, 2015 and December 31, 2014							3			3
Capital in excess of par value		3,244			3,207		3,253			3,255
Retained earnings		5,378			4,820		6,007			5,631
Accumulated other elements of comprehensive income (loss)		(232	)		(80	)	(847		)	(540		)
Less: Treasury stock, 64,808,073 shares at September 30, 2014 (41,683,164 shares at December 31, 2013)		(3,608	)		(2,098	)
Total Cameron stockholders' equity		4,785			5,852
Less: Treasury stock, 72,298,711 shares at September 30, 2015 (68,139,027 shares at December 31, 2014)							(3,987		)	(3,794		)
Total Cameron stockholders’ equity							4,429			4,555
Noncontrolling interests		1,011			1,064		831			889
Total equity		5,796			6,916		5,260			5,444
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	13,089		$	14,249
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY							$	11,609		$	12,892

The accompanying notes are an integral part of these statements.

Table of Contents

Cameron International Corporation

~~CAMERON INTERNATIONAL CORPORATION~~

~~CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS~~Consolidated Condensed Statements of Cash Flows

(dollars in millions)

Three Months Ended
September 30,

Nine Months Ended
September 30,

2014 2013 2014 2013
(unaudited)

Cash flows from operating activities:
Net income $ 238 $ 192 $ 587 $ 481
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of Reciprocating Compression business – – (95 ) –
Depreciation 74 62 217 177
Amortization 11 22 49 46
Non-cash stock compensation expense 13 13 43 41
Gain from remeasurement of prior interest in equity method investment – – (8 ) –
Deferred income taxes and tax benefit of  employee stock compensation plan transactions
(74 ) 19 (57 ) 30
Changes in assets and liabilities, net of translation, acquisitions and non-cash  items:

Receivables (69 ) (162 ) 42 (233 )
Inventories (55 ) (110 ) (283 ) (450 )
Accounts payable and accrued liabilities 152 211 (291 ) 219
Other assets and liabilities, net (74 ) (48 ) 51 (105 )
Net cash provided by operating  activities
216 199 255 206
Cash flows from investing activities:
Proceeds from sales and maturities of short-term investments 18 259 41 888
Purchases of short-term investments (78 ) (447 ) (115 ) (869 )
Capital expenditures (80 ) (123 ) (259 ) (306 )
Proceeds received from sale of Reciprocating Compression business, net - – 547 –
Other dispositions (acquisitions), net 10 (20 ) (7 ) (11 )
Proceeds received and cash acquired from
formation of OneSubsea
– – – 603
Proceeds from sales of plant and equipment 1 3 11 8
Net cash provided by (used for) investing activities (129 ) (328 ) 218 313
Cash flows from financing activities:
Issuance of senior notes – – 500 –
Debt issuance costs – – (4 ) –
Early retirement of senior notes (253 ) – (253 ) –
Short-term loan borrowings (repayments), net 94 32 104 41
Purchase of treasury stock (351 ) (433 ) (1,556 ) (558 )
Contributions from noncontrolling interest owners – 62 – 62
    Distribution to noncontrolling interest owners (40 ) – (40 ) –
Purchases of noncontrolling ownership interests – (7 ) – (7 )
Proceeds from stock option exercises, net of tax payments from stock compensation plan  transactions
14 1 39 30
Excess tax benefits from employee stock
compensation plan transactions
1 1 6 9
Principal payments on capital leases (6 ) (3 ) (15 ) (13 )
Net cash used for financing activities (541 ) (347 ) (1,219 ) (436 )
Effect of translation on cash (13 ) 15 (9 ) (12 )
Increase (decrease) in cash and cash equivalents (467 ) (461 ) (755 ) 71
Cash and cash equivalents, beginning of period 1,525 1,718 1,813 1,186
Cash and cash equivalents, end of period $ 1,058 $ 1,257 $ 1,058 $ 1,257



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(unaudited)

Cash flows from operating activities:
Net income	$	213		$	238		$	419		$	587
Adjustments to reconcile net income to net cash provided by operating activities:
Asset impairment and other charges	18			—			581			44
Loss on disposal of non-core assets	6			—			6			—
Pre-tax gain on sale of Compression businesses	—			—			(681		)	(95		)
Depreciation	74			74			226			217
Amortization	12			11			38			49
Non-cash stock compensation expense	13			13			35			43
Gain from remeasurement of prior interest in equity method investment	—			—			—			(8		)
Deferred income taxes and tax benefit of employee stock compensation plan transactions	(53		)	(74		)	(68		)	(57		)
Changes in assets and liabilities, net of translation, and non-cash items:
Receivables	(6		)	(69		)	245			42
Inventories	176			(55		)	106			(283		)
Accounts payable and accrued liabilities	(115		)	152			(869		)	(291		)
Other assets and liabilities, net	38			(74		)	173			7
Net cash provided by operating activities	376			216			211			255
Cash flows from investing activities:
Proceeds received from sale of Compression businesses, net	—			—			832			547
Proceeds from sales and maturities of short-term investments	274			18			674			41
Purchases of short-term investments	(159		)	(78		)	(883		)	(115		)
Capital expenditures	(60		)	(80		)	(190		)	(259		)
Other dispositions (acquisitions), net	—			10			—			(7		)
Proceeds from sales of plant and equipment	2			1			11			11
Net cash provided by (used for) investing activities	57			(129		)	444			218
Cash flows from financing activities:
Issuance of senior notes	—			—			—			500
Debt issuance costs	—			—			—			(4		)
Early retirement of senior notes	—			(253		)	—			(253		)
Short-term loan borrowings (repayments), net	(7		)	94			(220		)	104
Purchase of treasury stock	(45		)	(351		)	(240		)	(1,556		)
Contributions from (distributions to) noncontrolling interest owners, net	(21		)	(40		)	(3		)	(40		)
Proceeds from stock option exercises, net of tax payments from stock compensation plan transactions	10			14			5			39
Excess tax benefits from employee stock compensation plan transactions	—			1			1			6
Principal payments on capital leases	(6		)	(6		)	(15		)	(15		)
Net cash used for financing activities	(69		)	(541		)	(472		)	(1,219		)
Effect of translation on cash	(32		)	(13		)	(69		)	(9		)
Increase (decrease) in cash and cash equivalents	332			(467		)	114			(755		)
Cash and cash equivalents, beginning of period	1,295			1,525			1,513			1,813
Cash and cash equivalents, end of period	$	1,627		$	1,058		$	1,627		$	1,058

The accompanying notes are an integral part of these statements.

Table of Contents

Cameron International Corporation

~~CAMERON INTERNATIONAL CORPORATION~~

~~CONSOLIDATED CONDENSED STATEMENT OF CHANGES IN EQUITY~~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)																Cameron Stockholders
																	Common Stock		Capital in Excess of Par Value			Retained Earnings		Accumulated Other Elements of Comprehensive Income (Loss)			Treasury Stock			Noncontrolling Interests
Balance at December 31, 2013	$	3	$	3,207		$	4,820	$	(80	)	$	(2,098	)	$	1,064
																	(Unaudited)

Balance at December 31, 2014																	$	3	$	3,255		$	5,631	$	(540	)	$	(3,794	)	$	889
Net income		–		–			558		–			–			29		—		—			376		—			—			43
Other comprehensive income (loss), net of tax		–		–			–		(152	)		–			(46	)	—		—			—		(307		)	—			(98		)
Non-cash stock compensation expense		–		43			–		–			–			–		—		35			—		—			—			—
Purchase of treasury stock		–		–			–		–			(1,561	)		–		—		—			—		—			(236		)	—
Treasury stock issued under stock compensation plans		–		(12	)		–		–			51			–		—		(38		)	—		—			43			—
Tax benefit of stock compensation plan transactions		–		6			–		–			–			–		—		1			—		—			—			—
Purchase of noncontrolling ownership interests		–		–			–		–			–			4
Distribution to noncontrolling interest owners		–		–			–		–			–			(40	)

Balance at September 30, 2014	$	3	$	3,244		$	5,378	$	(232	)	$	(3,608	)	$	1,011
Contributions from noncontrolling interest owners																	—		—			—		—			—			18
Distributions to noncontrolling interest owners																	—		—			—		—			—			(21		)
Balance at September 30, 2015																	$	3	$	3,253		$	6,007	$	(847	)	$	(3,987	)	$	831

The accompanying notes are an integral part of these statements.

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Cameron International Corporation

~~CAMERON INTERNATIONAL CORPORATION~~

~~NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS~~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. ~~Normal~~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 includes the~~ Audited Consolidated Financial Statements and Notes ofthereto filed by the Company on Form 10-K for the year ended December 31, 2013. Those audited historical consolidated financial statements will be recast to include the Centrifugal Compression business as a discontinued operation when required to conform to the annual current full year presentation (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-type~~production 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: Merger of Cameron with Schlumberger

On August 26, 2015, Cameron and Schlumberger Limited "Schlumberger" announced that the companies had entered into an Agreement and Plan of Merger (the “Merger Agreement”) whereby a U.S. subsidiary of Schlumberger would acquire all of the issued and outstanding stock of Cameron. Under the terms of the agreement, Cameron shareholders will receive 0.716 shares of Schlumberger common stock and a cash payment of $14.44 in exchange for each Cameron common share. The Merger Agreement was unanimously approved by the board of directors of both companies. Consummation of the Merger is subject to customary closing conditions, including (a) approval by a majority of the Cameron stockholders of the Merger Agreement and (b) receipt of required regulatory consents and approvals. Schlumberger stockholders are not required to vote on the Merger Agreement. Should Cameron terminate the Merger Agreement in specified circumstances, the Company would be required to pay Schlumberger a termination fee equal to $321 million. This transaction is currently expected to close during the first quarter of 2016.

Note 2:3: Discontinued Operations

Effective June 1, 2014, the Company completed the sale of its Reciprocating Compression business, also a division of the PCS segment, to General Electric for net cash consideration of approximately $547 million.

On August 18, 2014, the Company announced that it had entered into a definitive agreement to sell its Centrifugal Compression business, a division of the Process and Compression Systems (PCS) segment, to Ingersoll Rand for cash consideration of $850 million, subject to closing adjustments. The ~~sale is expected to close prior to year end, subject to regulatory approvals. For the year ended December 31, 2013, the Centrifugal Compression business generated revenues of $398 million.~~

~~Both businesses are being reported as discontinued operations in the Company's results of operations. Summarized financial information relating to these businesses is shown below (in millions):~~

Nine Months Ended
September 30,

2014 2013

Results of Operations:
Revenues $ 348 $ 494
Income before income taxes $ 122
⁽¹⁾
$ 61

⁽¹⁾

^–Includes a pretax gain on the sale of the Reciprocating Compression business of $95 million, which remains subject to a final working capital settlement. The tax provision associated with this gain, approximately $85 million, was impacted by nondeductible goodwill of approximately $192 million included in the total net assets sold.

~~Table of Contents~~

Assets and liabilities of discontinued operations at September 30, 2014 included receivables, inventory and certain other current assets of $153 million; property, plant & equipment, goodwill and other assets of $82 million; and accounts payable, accruals and other liabilities of $107 million.

~~Note 3: Other Costs~~

~~Other costs, net of certain credits, consisted of the following (in millions):~~

Three Months Ended
September 30,

Nine Months Ended
September 30,

2014 2013 2014 2013

Goodwill impairment $ – $ – $ 40 $ –
Loss on disposal of non-core assets 10 – 10 –
Cost for early retirement of debt 3 – 3
OneSubsea formation and other acquisition and integration costs – 10 – 58
Gain from remeasurement of prior interest in equity method investment – – (8 ) –
Impairment of identifiable intangible assets – – 4 –
Mark-to-market impact on currency derivatives not designated as accounting hedges 4 1 4 1
Currency devaluation, severance, restructuring and other costs 2 3 9 21
Total other costs, net of credits $ 19 $ 14 $ 62 $ 80

~~As described further in Note 2 of the Notes to Consolidated Condensed Financial Statements, the~~ Company completed the sale of its Reciprocating Compression business to General Electric, effective June 1, ~~2014.~~2014, and the sale of its Centrifugal Compression business to Ingersoll Rand on January 1, 2015. The gross cash consideration from the sale of both businesses was $1.4 billion, subject to pending closing adjustments.

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Summarized financial information showing the results of operations of these discontinued operations was as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
(dollars in millions)	2015			2014			2015			2014

Revenues	$	—		$	64		$	—		$	348
Cost of sales (excluding depreciation and amortization)	—			(43		)	—			(246		)
All other (costs) gains	(1		)	(17		)	(2		)	(75		)
Gain on sale of Compression businesses, before tax	—			—			681			95

Income before income taxes	(1		)	4			679			122
Income tax provision	—			(1		)	(248		)	(91		)
Income from discontinued operations, net of income taxes	$	(1	)	$	3		$	431		$	31

The gain on the sale of the Compression businesses was determined as follows:



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

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

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Note 4: Asset Charges and Other Costs (Gains), Net

Asset charges and other costs (gains) consisted of the following:



	Three Months Ended September 30,				Nine Months Ended September 30,
(dollars in millions)	2015		2014		2015		2014

Asset charges -
Goodwill impairment	$	—	$	—	$	517	$	40
Other long-lived asset impairments	18		—		54		4
Accelerated depreciation on underutilized assets	—		—		10		—
Total	$	18	$	—	$	581	$	44

Other costs (gains) -
Loss on disposal of non-core assets	6		10		6		10
Facility closures and severance	10		2		43		10
Merger costs	6		—		6		—
Mark-to-market impact on currency derivatives not designated as accounting hedges	—		4		11		4
Net loss from currency devaluations	2		—		7		—
Gain from remeasurement of prior interest in equity method investment	—		—		—		(8		)
All other costs, net	2		3		4		2
Total	26		19		77		18
Total asset charges and other costs (gains), net	$	44	$	19	$	658	$	62

Asset charges

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 our 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 Process Systems reporting unit, leaving a remaining balance of goodwill in this reporting unit at September 30, 2015 of $52 million.

During the first quarter of 2014, goodwill totaling $40 million relating to the Company’s Process Systems and Equipment (PSE) ~~business~~reporting unit was considered to be fully impaired during the annual goodwill impairment test.

The Company also recognized impairment charges of $54 million during the nine months ended September 30, 2015 relating to certain underutilized facilities resulting from weak market conditions and the write-down of assets retained in the ~~Process~~agreement to sell the LeTourneau Offshore Products business, of which $18 million was recorded in the third quarter of 2015 (see further discussion below). Charges of $4 million were recognized during the first nine months of 2014 for impairment of certain intangible assets.

Loss on disposal of non-core assets

On August 27, 2015, Cameron entered into an agreement to sell the LeTourneau Offshore Products business within the Drilling Systems division to Keppel Offshore & ~~Reciprocating Compression reporting unit~~Marine USA, Inc. for $100 million. In connection with this transaction, the Company recorded an estimated pre-tax loss of $6 million during the third quarter of 2015 to write-down the carrying value of the business to its fair value including certain other accrued liabilities associated with the sale. This was in addition to the $18 million write-down of retained assets discussed above. The sale is currently expected to close during the second quarter of 2016.

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Assets and liabilities, including goodwill ~~impairment evaluation purposes.~~ associated with this business, totaling $105 million and $1 million, respectively, have been presented as held for sale and included in other current assets or accounts payable and accrued liabilities as of September 30, 2015.

All other costs (Gains)

As a result of current market conditions and the ~~classification~~impact on the Company’s operations, charges 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$53 million were recognized during the ~~first quarter~~nine months ended September 30, 2015 related to the impact of ~~2014. As a result of this review, the PSE goodwill amount, totaling approximately $40 million, was fully impaired at that time.~~accelerated depreciation on underutilized assets, pending facility closures and severance for workforce reductions.

~~As described further in Note 8 of the Notes~~Merger costs includes costs related directly to ~~Consolidated Condensed Financial Statements, in July 2014, the Company paid a make-whole premium~~activities to support and ~~wrote off certain unamortized debt issuance costs, totaling approximately $3 million, in connection~~facilitate Cameron's merger with ~~the early retirement of $250 million principal amount of 1.6% Senior Notes with an original maturity of April 30, 2015.~~

Schlumberger.

In May 2014, the Company increased its prior ownership interest in Cameron Services Middle East LLC from 49% to 90%, ~~at a cost of~~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 September 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 purchase price allocation will be completed no later than one year from the acquisition date. Preliminary goodwill recognized at September 30, 2014 was approximately $21 million, which is not deductible for tax purposes.entity.

~~Table of Contents~~

Note 4:5: Receivables

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

September 30,
2014

December 31,
2013

Trade receivables $ 2,078 $ 2,368
Costs and estimated earnings in excess of billings on uncompleted contracts 397 253
Other receivables 134 119
Allowance for doubtful accounts (29 ) (21 )
Total receivables $ 2,580 $ 2,719

following:



(dollars in millions)	September 30, 2015			December 31, 2014

Trade receivables	$	1,267		$	1,678
Costs and estimated earnings in excess of billings on uncompleted contracts	739			621
Other receivables	136			122
Allowance for doubtful accounts	(54		)	(32		)
Total receivables	$	2,088		$	2,389

Note 5:6: Inventories

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



(dollars in millions)	September 30, 2015			December 31, 2014

Raw materials	$	125		$	159
Work-in-process	688			827
Finished goods, including parts and subassemblies	2,022			2,150
Other	23			24
Total gross inventories	2,858			3,160
Excess of current standard costs over LIFO costs	(70		)	(86		)
Allowances	(129		)	(145		)
Total net inventories	$	2,659		$	2,929

September 30,
2014

December 31,
2013

Raw materials $ 203 $ 238
Work-in-process 897 894
Finished goods, including parts and subassemblies 2,216 2,208
Other 25 22
3,341 3,362
Excess of current standard costs over LIFO costs (87 ) (120 )
Allowances (124 ) (109 )
Total inventories $ 3,130 $ 3,133

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Note 6:7: Plant and Equipment and Goodwill

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

September 30,
2014

December 31,
2013

Plant and equipment, at cost $ 3,543 $ 3,670
Accumulated depreciation (1,602 ) (1,633 )
Total plant and equipment $ 1,941 $ 2,037



(dollars in millions)	September 30, 2015			December 31, 2014

Plant and equipment, at cost	$	3,478		$	3,580
Accumulated depreciation	(1,745		)	(1,616		)
Total plant and equipment	$	1,733		$	1,964

Changes in goodwill during thenine months ended September 30, ~~2014~~2015 were as follows ~~(in~~(dollars in millions):



Balance at December 31, 2014	$	2,461
Impairment of goodwill (Note 4)	(517		)
Goodwill associated with assets held for sale	(14		)
Adjustments to the purchase price allocation for prior year acquisitions	(12		)
Translation effect of currency changes and other	(122		)
Balance at September 30, 2015	$	1,796

Balance at December 31, 2013 $ 2,925
Discontinued operations (248 )
Impairment (See Note 3) (40 )
Acquisitions 21
Adjustments to the purchase price allocation for prior year acquisitions 20
Translation effect of currency changes and other (71 )
Balance at September 30, 2014 $ 2,607

~~Table of Contents~~

Note 7:8: Accounts Payable and Accrued Liabilities

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

September 30,
2014

December 31,
2013

Trade accounts payable and accruals $ 737 $ 1,184
Advances from customers 1,550 1,676
Other accruals 1,169 1,023
Total accounts payable and accrued liabilities $ 3,456 $ 3,883

~~Activity during the nine months ended September 30, 2014 associated with the Company's product warranty accruals was as follows (in millions):~~



(dollars in millions)	September 30, 2015		December 31, 2014

Trade accounts payable and accruals	$	521	$	1,084
Advances from customers	1,165		1,576
Other accruals	1,100		1,088
Total accounts payable and accrued liabilities	$	2,786	$	3,748

Balance
December 31,
2013

Net
warranty
provisions

Charges
against
accrual
Discontinued operations
Translation
and other

Balance
September 30,
2014

$ 46 $ 34 $ (24 ) $ (10 ) $ – $ 46

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Note 8:9: Debt

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

September 30,
2014

December 31,
2013

Commercial paper (0.32% weighted average rate) $ 350 $ –
Senior notes:
Floating rate notes due June 2, 2014 – 250
1.6% notes due April 30, 2015 – 250
1.15% notes due December 15, 2016 250 250
1.4% 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 61 57
Obligations under capital leases 58 60
3,212 2,860
Current maturities (403 ) (297 )
Long-term maturities $ 2,809 $ 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%.~~

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��



(dollars in millions)	September 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	27			67
Obligations under capital leases	62			71
	2,832			3,082
Current maturities	(38		)	(263		)
Long-term maturities	$	2,794		$	2,819

Commercial paper program

~~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~~Company has 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~~place 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.

~~During the first quarter of 2014, the Company's Board of Directors authorized the establishment of 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 upno more than 364 days.

Credit agreements and revolving credit facilities

In order to ~~364 days~~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 $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 Credit Agreement will be used to finance working capital needs and for other general corporate ~~purposes. The average term~~purposes, including acquisitions, capital expenditures, repurchases of ~~the outstanding commercial paper at~~common stock, repayment of debt and issuances of letters of credit. At September 30, ~~2014 was approximately 26 days.~~

~~On April 11, 2014,~~2015, no letters of credit had been issued under the ~~Company entered into a new~~Credit Agreement, leaving $750 million ~~three-year~~available for future use.

The Company also has a $750 million 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 September 30, 2014, no amounts had been borrowed under the $835 million Revolving Credit Facility.credit. The Company has issued letters of credit totaling ~~$72~~$36 million under the ~~new $750 million~~ Revolving Credit Facility, ~~and $25~~leaving $714 million ~~under the $40 million bi-lateral facility, leaving $678 million and $15 million, respectively,~~ available for future use at September 30, ~~2014.~~2015.

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Note 9:10: Income Taxes

The ~~Company's~~Company’s effective income tax rate on income from continuing operations for the first nine months of ~~2014~~2015 was ~~24.4%~~109.1% as compared to ~~23.7%~~24.4% for the first nine months of ~~2013.~~2014. The components of the effective tax rates for both periods were as ~~follows (dollars in millions):~~follows:

	Nine Months Ended September 30,
	2014						2013
	Tax Provision			Tax Rate			Tax Provision			Tax Rate			Nine Months Ended September 30,
													2015					2014
Forecasted tax expense by jurisdiction	$	167			22.7	%	$	134			23.3	%
(dollars in millions)													Tax Provision			Tax Rate		Tax Provision			Tax Rate

Provision (benefit) based on international income (loss) distribution													$	27		20.5	%	$	167		22.7	%
Adjustments to income tax provision:
Tax effect of goodwill impairment		9			1.3			–			–
Impairments with no tax benefit													113			86.0		9			1.3
Asset impairments													(5		)	(3.8	)	—			—
Finalization of prior year returns		4			0.5			6			1.0		—			—		4			0.5
Tax effects of changes in legislation		–			–			(9	)		(1.6	)
Changes in valuation allowances		3			0.4			5			1.0		8			6.3		3			0.4
Accrual adjustments and other		(4	)		(0.5	)		–			–		1			0.1		(4		)	(0.5	)
Tax provision	$	179			24.4	%	$	136			23.7	%	$	144		109.1	%	$	179		24.4	%

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Note ~~10:~~11: Business Segments

The ~~Company's~~Company’s operations are organized into ~~three~~four 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
September 30,

Nine Months Ended
September 30,

2014 2013 2014 2013
Revenues:
DPS $ 1,975 $ 1,637 $ 5,583 $ 4,344
V&M 552 502 1,580 1,558
PCS 151 178 414 505
$ 2,678 $ 2,317 $ 7,577 $ 6,407

Income (loss) from continuing operations before income taxes:
DPS $ 295 $ 216 $ 713 $ 566
V&M 103 98 304 320
PCS 9 13 9 18
Corporate & other (102 ) (100 ) (291 ) (329 )
$ 305 $ 227 $ 735 $ 575



	Three Months Ended September 30,						Nine Months Ended September 30,
(dollars in millions)	2015			2014			2015			2014

Revenues:
Subsea	$	758		$	779		$	2,047		$	2,195
Surface	446			600			1,499			1,751
Drilling	673			800			2,118			2,233
V&M	376			558			1,185			1,597
Elimination of intersegment revenues	(45		)	(59		)	(146		)	(199		)
Total revenues	$	2,208		$	2,678		$	6,703		$	7,577

Segment income before interest and income taxes:
Subsea	$	120		$	44		$	244		$	119
Surface	49			105			210			304
Drilling	146			159			400			323
V&M	58			104			147			312
Elimination of intersegment earnings	(9		)	(17		)	(32		)	(53		)
Segment income before interest and income taxes	364			395			969			1,005

Corporate items:
Corporate expenses	(28		)	(35		)	(74		)	(110		)
Interest, net	(34		)	(36		)	(105		)	(98		)
Other (costs) gains, net (see Note 4)	(44		)	(19		)	(658		)	(62		)
Income from continuing operations before income taxes	$	258		$	305		$	132		$	735

Corporate ~~& other includes~~items include governance expenses associated with the ~~Company's back~~Company’s corporate office, ~~support and public company costs,~~as well as all of the ~~Company's~~Company’s interest income and interest expense, goodwill and asset impairment charges, severance and restructuring expenses, the impact of currency devaluations, stock-based compensation, 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 3 of~~corporate items because cash equivalents, short-term investments and debt, including location, type, currency, etc., are managed on a worldwide basis by the ~~Notes to Consolidated Condensed Financial Statements.~~ corporate treasury department.

Note ~~11:~~12: 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
September 30,

Nine Months Ended
September 30,

2014 2013 2014 2013

Net income from continuing operations $ 235 $ 178 $ 556 $ 439
Net income attributable to noncontrolling interests 13 3 29 3
Net income from continuing operations attributable to Cameron 222 175 527 436
Income from discontinued operations, net of taxes 3 14 31 42
Net income attributable to Cameron $ 225 $ 189 $ 558 $ 478

Average shares outstanding (basic) 201 243 207 246
Common stock equivalents 2 1 1 1
Diluted shares 203 244 208 247

Basic earnings per share:
Continuing operations $ 1.11 $ .72 $ 2.55 $ 1.78
Discontinued operations .01 .06 .15 .17
Basic earnings per share $ 1.12 $ .78 $ 2.70 $ 1.95

Diluted earnings per share:
Continuing operations $ 1.10 $ .72 $ 2.53 $ 1.77
Discontinued operations .01 .06 .15 .17
Diluted earnings per share $ 1.11 $ .78 $ 2.68 $ 1.94

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	Three Months Ended September 30,					Nine Months Ended September 30,
(dollars and shares in millions, except per share amounts)	2015			2014		2015			2014

Net income (loss) from continuing operations	$	214		$	235	$	(12	)	$	556
Less: Net income attributable to noncontrolling interests	26			13		43			29
Net income (loss) from continuing operations attributable to Cameron	188			222		(55		)	527
Income (loss) from discontinued operations, net of taxes	(1		)	3		431			31
Net income attributable to Cameron	$	187		$	225	$	376		$	558

Average shares outstanding (basic)	191			201		192			207
Common stock equivalents	1			2		—			1
Diluted shares	192			203		192			208

Basic earnings (loss) per share:
Continuing operations	0.99			1.11		(0.29		)	2.55
Discontinued operations	(0.01		)	0.01		2.25			0.15
Basic earnings per share	0.98			1.12		1.96			2.70

Diluted earnings (loss) per share:
Continuing operations	0.98			1.10		(0.29		)	2.53
Discontinued operations	(0.01		)	0.01		2.25			0.15
Diluted earnings per share	0.97			1.11		1.96			2.68

Activity in the ~~Company's~~Company’s treasury shares were as follows:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2014 2013 2014 2013

Treasury shares at beginning of period 60,027,350 17,001,730 41,683,164 16,415,336
Purchases of treasury shares 4,915,044 7,677,282 24,588,815 9,790,737
Net change in treasury shares owned by participants in nonqualified deferred compensation plans (1,440 ) 3,052 36,708 55,159
Treasury shares issued in satisfaction of stock option exercises and vesting of restricted stock units (132,881 ) (60,537 ) (1,500,614 ) (1,639,705 )
Treasury shares at end of period
64,808,073
24,621,527 64,808,073 24,621,527

The average cost of treasury shares acquired for the three- and nine-month periods ended September 30, 2014 was $71.43 and $63.38, respectively. The average cost of treasury shares acquired for the three- and nine-month periods ended September 30, 2013 was $58.04 and $58.84, respectively.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014

Treasury shares at beginning of period	71,671,246			60,027,350			68,139,027			41,683,164
Purchases of treasury shares	905,100			4,915,044			5,130,334			24,588,815
Net change in treasury shares owned by participants in nonqualified deferred compensation plans	(1,920		)	(1,440		)	(2,652		)	36,708
Treasury shares issued in satisfaction of stock option exercises and vesting of restricted stock units	(275,715		)	(132,881		)	(967,998		)	(1,500,614		)
Treasury shares at end of period	72,298,711			64,808,073			72,298,711			64,808,073
Average cost per share	$	49.48		$	71.43		$	46.11		$	63.38

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 $3.8 billion since inception. At September 30, ~~2014,~~2015, the Company had remaining authority for future stock purchases totaling approximately ~~$665~~$240 million.

Note ~~12:~~13: 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 September 30, ~~2014~~2015 and ~~2013~~2014 were as ~~follows (in millions):~~follows:

Three Months Ended September 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
September 30, 2013

Beginning of period balance $ (43 ) $ (45 ) $ 12 $ (76 ) $ (156 )

Other comprehensive income (loss) before reclassifications:
Pre-tax (138 ) – (29 ) (167 ) 74
Tax effect – – 12 12 (9 )

Amounts reclassified from accumulated other comprehensive income to:
Revenues – – (2 ) (2 ) 1
Cost of sales – – 1 1 (4 )
Selling and administrative expense – – – – 2
Tax effect – – – – -
Net current period other comprehensive income (loss) (138 ) – (18 ) (156 ) 64
Balance at end of period $ (181 ) $ (45 ) $ (6 ) $ (232 ) $ (92 )

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	Three Months Ended September 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 September 30, 2014

Balance at beginning of period	$	(575	)	$	(78	)	$	(40	)	$	(693	)	$	(76	)

Other comprehensive income (loss) before reclassifications:
Pre-tax	(155		)	—			(18		)	(173		)	(167		)
Tax effect	—			—			8			8			12

Amounts reclassified from accumulated other comprehensive income to:
Revenues	—			—			9			9			(2		)
Cost of sales	—			—			8			8			1
Tax effect	—			—			(6		)	(6		)	—
Net current period other comprehensive income (loss)	(155		)	—			1			(154		)	(156		)
Balance at end of period	$	(730	)	$	(78	)	$	(39	)	$	(847	)	$	(232	)

The changes in the components of accumulated other elements of comprehensive income (loss) attributable to Cameron stockholders for the nine months ended September 30, ~~2014~~2015 and ~~2013~~2014 were as ~~follows (in millions):~~follows:

	Nine Months Ended September 30, 2014
	Accumulated Foreign Currency Translation Gain (Loss)			Prior Service Credits and Net Actuarial Losses			Accumulated Gain (Loss) on Cash Flow Hedge Derivatives			Total			Nine Months Ended September 30, 2013
Beginning of year balance	$	(49	)	$	(45	)	$	14		$	(80	)	$	(30	)
																Nine Months Ended September 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			Nine Months Ended September 30, 2014

Balance at beginning of period																$	(428	)	$	(78	)	$	(34	)	$	(540	)	$	(80	)

Other comprehensive income (loss) before reclassifications:
Pre-tax		(132	)		–			(25	)		(157	)		(58	)	(302		)	—			(61		)	(363		)	(157		)
Tax effect		–			–			10			10			(4	)	—			—			12			12			10

Amounts reclassified from accumulated other comprehensive income to:
Revenues		–			–			(7	)		(7	)		(1	)	—			—			38			38			(7		)
Cost of sales		–			–			(1	)		(1	)		(4	)	—			—			25			25			(1		)
Selling and administrative expense		–			–			–			–			5
Tax effect		–			–			3			3			-		—			—			(19		)	(19		)	3
Net current period other comprehensive income (loss)		(132	)		–			(20	)		(152	)		(62	)	(302		)	—			(5		)	(307		)	(152		)
Balance at end of period	$	(181	)	$	(45	)	$	(6	)	$	(232	)	$	(92	)	$	(730	)	$	(78	)	$	(39	)	$	(847	)	$	(232	)

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Note ~~13:~~14: 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 September 30, ~~2014,~~2015, the ~~Company's~~Company’s Consolidated Condensed Balance Sheet included a liability of approximately ~~$17~~$20 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 ~~over~~approximately 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's~~authority’s interpretation of the tax laws and regulations, the Company could be exposed to additional taxes.

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The Company has been assessed customs duties and penalties by the government of Brazil ~~totaling approximately $53 million at September 30, 2014, including interest accrued at local country rates,~~ following a customs audit for the years ~~2003-2010.~~2003-2010 totaling a U.S. dollar equivalent of approximately $34 million at September 30, 2015, including interest accrued at local country rates. 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 September 30, ~~2014~~2015 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 a landfill into which a predecessor of the Company’s former Reciprocating Compression operation in Grove City, Pennsylvania deposited 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 of~~through the settlement of a class action lawsuit ~~and is obligated~~which 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 September 30, ~~2014.~~

2015.

Additionally, the Company has ~~discontinued~~ceased 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 September 30, ~~2014,~~2015, the Company's Consolidated Condensed Balance Sheet included a noncurrent liability of ~~nearly~~approximately $3 million for these environmental matters.

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Note ~~14:~~15: Fair Value of Financial Instruments

Fair Value of Financial Instruments

The ~~Company's~~Company’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.

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Following is a summary of the ~~Company's~~Company’s financial instruments which have been valued at fair value in the ~~Company's~~Company’s Consolidated Balance Sheets at September 30, ~~2014~~2015 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
(in millions)	2014		2013		2014			2013		2014			2013

															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
(dollars in millions)															2015		2014		2015			2014			2015			2014

Cash and cash equivalents:
Cash	$	497	$	618	$	–		$	–	$	497		$	618	$	703	$	616	$	—		$	—		$	703		$	616
Money market funds		493		1,172		–			–		493			1,172	827		842		—			—			827			842
Commercial paper		–		–		21			4		21			4	—		—		48			13			48			13
U.S. Treasury securities															—		5		—			—			—			5
U.S. corporate obligations		11		–		–			–		11				10		4		—			—			10			4
Non-U.S. bank and other obligations		36		19		–			–		36			19	39		33		—			—			39			33
Short-term investments:
Commercial paper		–		–		9			–		9			–	—		—		96			11			96			11
U.S. Treasury securities		71		41		–			–		71			41	32		51		—			—			32			51
U.S. corporate obligations		35		–		–			–		35			–	140		51		—			—			140			51
U.S. non-governmental agency asset-backed securities															—		—		53			—			53			—
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	5		5		—			—			5			5
International equity funds		3		3		–			–		3			3	3		3		—			—			3			3
Blended equity funds		5		4		–			–		5			4	5		5		—			—			5			5
Common stock		2		2		–			–		2			2	2		2		—			—			2			2
Derivatives, net asset (liability):
Foreign currency contracts		–		–		(43	)		19		(43	)		19	—		—		(58		)	(99		)	(58		)	(99		)
	$	1,163	$	1,868	$	(13	)	$	23	$	1,150		$	1,891
Total															$	1,769	$	1,621	$	139		$	(75	)	$	1,908		$	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 both September 30, 2015 and December 31, 2014, the fair value of the ~~Company's~~Company’s fixed-rate debt (based on Level 1 quoted market rates) ~~was~~were approximately ~~$3.0~~$2.9 billion as compared to the ~~nearly $2.8~~$2.7 billion face value of the debt recorded, net of ~~original issue~~ discounts, in the ~~Company's~~Company’s Consolidated Condensed Balance Sheet. ~~At December 31, 2013, the fair value~~

Table of ~~the Company's fixed-rate debt (based on Level 1 quoted market rates) was approximately $2.7 billion as compared to the $2.5 billion face value of the debt.~~Contents

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 September 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 for accounting purposes with changes in the fair value of those contracts recorded in accumulated other comprehensive income (loss) in the period such change occurs. Certain other ~~forward and option~~ 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 ~~and option~~ contracts based on quoted exchange rates for the respective currencies applicable to similar instruments.

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~~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 September 30, ~~2014~~ 2015 was as ~~follows (in millions):~~follows:

   Notional Amount - Buy Notional Amount - Sell
   2014 2015 2016 2017 Total 2014 2015 2016 Total
Foreign exchange forward contracts -
Notional currency in:
Euro 103 79 14 – 196 (44 ) (5 ) (1 ) (50 )
Malaysian ringgit 46 260 3 – 309 – (20 ) – (20 )
Norwegian krone 293 675 103 4 1,075 (70 ) (69 ) – (139 )
Pound sterling 97 23 5 – 125 (52 ) (22 ) (1 ) (75 )
U.S. dollar 29 7 – – 36 (330 ) (456 ) (47 ) (833 )

Foreign exchange option contracts -
Notional currency in:
Euro 29 87 – – 116 – – – –



	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:
Euro	65	69	37	171	(23	)	(10	)	—		—		(33	)
Malaysian ringgit	143	76	—	219	(16	)	—		—		—		(16	)
Norwegian krone	187	598	32	817	(51	)	(74	)	(4	)	—		(129	)
Pound Sterling	94	22	2	118	(5	)	(1	)	—		—		(6	)
U.S. dollar	16	44	4	64	(282	)	(327	)	(101	)	(1	)	(711	)

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.~~position. The fair values of derivative financial instruments recorded in the ~~Company's~~Company’s Consolidated Condensed Balance Sheets at September 30, ~~2014~~ 2015 and December 31, ~~2013~~2014 were as ~~follows (in millions):~~follows:



	September 30, 2015				December 31, 2014
(dollars in millions)	Assets		Liabilities		Assets		Liabilities

Derivatives designated as hedging instruments:
Current	$	10	$	62	$	8	$	83
Non-current	4		4		1		12
Total derivatives designated as hedging instruments	14		66		9		95

Derivatives not designated as hedging instruments:
Current	—		6		1		14
Non-current	—		—		—		—
Total derivatives not designated as hedging instruments	—		6		1		14

Total derivatives	$	14	$	72	$	10	$	109

September 30, 2014 December 31, 2013
Assets Liabilities Assets Liabilities

Derivatives designated as hedging instruments:
Current $ 6 $ 34 $ 28 $ 10
Non-current 1 6 3 2
Total derivatives designated as hedging instruments 7 40 31 12

Derivatives not designated as hedging instruments:
Current 3 13 6 6
Non-current – – – –
Total derivatives not designated as hedging instruments 3 13 6 6

Total derivatives $ 10 $ 53 $ 37 $ 18

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The amount of pre-tax ~~gain (loss)~~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 Nine Months Ended
September 30, September 30,
2014 2013 2014 2013

Derivatives designated as hedging instruments -
Cost of sales $ (4 ) $ 3 $ (3 ) $ 2

Derivatives not designated as hedging instruments -
Cost of sales (6 ) 7 (4 ) 3
Other costs (4 ) (1 ) (4 ) (1 )
$ (14 ) $ 9 $ (11 ) $ 4



	Three Months Ended September 30,				Nine Months Ended September 30,
(dollars in millions)	2015		2014		2015		2014

Derivatives designated as hedging instruments -
Cost of sales	$	1	$	4	$	—	$	3

Derivatives not designated as hedging instruments -
Cost of sales	11		6		20		4
Other costs	—		4		11		4
Total pre-tax loss	$	12	$	14	$	31	$	11

Note ~~15:~~16: 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~~ (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. ~~Companies~~In 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 than~~beginning 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 of~~has begun evaluating the impact of the new standard on its business and ~~addressing~~will ultimately determine after further analysis whether it will select ~~either~~ the full retrospective or the modified retrospective implementation ~~method upon adoption in 2017.~~method.

Debt Issuance Costs

~~Discontinued operations~~

The FASB issued ~~Accounting Standards Update 2014-08,~~ ASU 2015-03, ~~Reporting Discontinued Operations and Disclosures~~Interest-Imputation of ~~Disposals~~Interest (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:~~

·	~~raises the threshold for disposals to qualify as discontinued operations,~~

·	~~allows companies to have significant continuing involvement and continuing cash flows with the discontinued operation, and~~

·	~~provides for new and additional disclosures of discontinued operations and individually material disposal transactions.~~

will align the presentation of debt issuance costs with that of debt discounts and premiums. Final guidance on this standard, issued as ASU 2015-15 in August 2015, includes an SEC staff announcement that the SEC staff will not object to an entity presenting the cost of securing a revolving line of credit as an asset, regardless of whether a balance is outstanding. The original standard, as issued, did not address revolving lines of credit, which may not have outstanding balances. The Company expects to adopt ~~the~~this new standard ~~when it becomes effective~~beginning 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 time of adoption of this new standard.

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Inventory

The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (ASU 2015-11) in July 2015. ASU 2015-11 requires companies to measure inventory at the lower of cost or net realizable value rather than at the lower of cost or market. Net realizable value is the estimated selling price in the ~~first quarter~~ordinary course of ~~2015.~~business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for the Company’s FIFO inventories beginning January 1, 2016. The Company does not currently anticipate a material impact on its consolidated financial statements at the time of adoption of this new standard.

Business Combinations

The FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16) in September 2015. This new standard specifies that an acquirer should recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined, eliminating the current requirement to retrospectively account for these adjustments. Additionally, the full effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts should be recognized in the same period as the adjustments to the provisional amounts. The Company expects to adopt this new standard beginning January 1, 2016.

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



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's~~Company’s actual results may differ materially from those described in any forward-looking statements. Any such statements are based on current expectations of the ~~Company's~~Company’s performance and are subject to a variety of factors, some of which are not under the control of the Company, which can affect the ~~Company's~~Company’s results of operations, liquidity or financial condition. Such factors may include overall demand for, and pricing of, the ~~Company's~~Company’s products; the size and timing of orders; the ~~Company's~~Company’s ability to successfully execute large subsea and drilling projects it has been awarded; the possibility of cancellations of orders in backlog; the ~~Company's~~Company’s ability to convert backlog into revenues on a timely and profitable basis; the impact of acquisitions the Company has made or may make; changes in the price of (and demand for) oil and gas in both domestic and international markets; raw material costs and availability; political and social issues affecting the countries in which the Company does business; 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's~~Company’s products and services. As a result, changes in oil and gas price expectations may impact the demand for the ~~Company's~~Company’s products and services and the ~~Company's~~Company’s financial results due to changes in cost structure, staffing and spending levels the Company makes in response thereto. See additional factors discussed in ~~"Factors~~“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's~~Company’s future performance. Additionally, the Company is not obligated to make public disclosure of such changes unless required under applicable disclosure rules and regulations.

Merger of Cameron with Schlumberger

On August 26, 2015, Cameron and Schlumberger Limited (Schlumberger) announced that the companies had entered into an Agreement and Plan of Merger (the “Merger Agreement”) whereby a U.S. subsidiary of Schlumberger would acquire all of the issued and outstanding stock of Cameron. Under the terms of the agreement, Cameron shareholders will receive 0.716 shares of Schlumberger common stock and a cash payment of $14.44 in exchange for each Cameron common share. The Merger Agreement was unanimously approved by the board of directors of both companies. Consummation of the Merger is subject to customary closing conditions, including (a) approval by a majority of the Cameron stockholders of the Merger Agreement and (b) receipt of required regulatory consents and approvals. Schlumberger stockholders are not required to vote on the Merger Agreement. Should Cameron terminate the Merger Agreement in specified circumstances, the Company would be required to pay Schlumberger a termination fee equal to $321 million. This transaction is currently expected to close during the first quarter of 2016.

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THIRD QUARTER ~~2014~~2015 COMPARED TO THIRD QUARTER ~~2013~~2014

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 ~~semi-submersibles~~semis under contract at the end of each period follows:

Three Months Ended
September 30,
Increase (Decrease)
2014 2013 Amount %
Drilling activity (average number of working rigs during period)⁽¹⁾:

United States 1,903 1,769 134 7.6 %
Canada 385 349 36 10.3 %
Rest of world 1,348 1,285 63 4.9 %
Global average rig count 3,636 3,403 233 6.8 %

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 $ 97.60 $ 105.82 $ (8.22 ) (7.8 )%
Henry Hub natural gas spot price per MMBtu in U.S. dollars $ 3.93 $ 3.56 $ 0.37 10.4 %
Twelve-month futures strip price (U.S. dollar amount at period end)⁽²⁾:

West Texas Intermediate Cushing, OK crude oil contract (per barrel) $ 88.68 $ 97.81 $ (9.13 ) (9.3 )%
Henry Hub natural gas contract (per MMBtu) $ 4.01 $ 3.80 $ 0.21 5.5 %

Contracted drillships and semi-submersibles by location at period-end⁽³⁾:

U.S. Gulf of Mexico 48 41 7 17.1 %
Central and South America 66 81 (15 ) (18.5 )%
Northwestern Europe 44 45 (1 ) (2.2 )%
West Africa 46 40 6 15.0 %
Southeast Asia and Australia 28 24 4 16.7 %
Other 51 49 2 4.1 %
Total 283 280 3 1.1 %

⁽¹⁾



	Three Months Ended September 30,				Increase (Decrease)
	2015		2014		Amount			%
Drilling activity (average number of working rigs during period)⁽¹⁾:
United States	866		1,903		(1,037		)	(54.5	)%
Canada	191		385		(194		)	(50.4	)%
Rest of world	1,132		1,348		(216		)	(16.0	)%
Global average rig count	2,189		3,636		(1,447		)	(39.8	)%

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)	$	46.48	$	97.60	$	(51.12	)	(52.4	)%
Brent crude oil spot price (per barrel)	$	54.57	$	104.30	$	(49.73	)	(47.7	)%
Henry Hub natural gas spot price (per MMBtu)	$	2.75	$	3.93	$	(1.18	)	(30.0	)%

Twelve-month futures strip price (U.S. dollar amount at period end)⁽²⁾:
West Texas Intermediate (WTI) Cushing, OK crude oil contract (per barrel)	$	47.83	$	88.68	$	(40.85	)	(46.1	)%
Brent crude oil contract (per barrel)	$	48.37	$	94.67	$	(46.30	)	(48.9	)%
Henry Hub natural gas contract (per MMBtu)	$	2.75	$	4.01	$	(1.26	)	(31.4	)%

Contracted drillships and semi-submersibles by location at period-end⁽³⁾:
U.S. Gulf of Mexico	46		48		(2		)	(4.2	)%
Central and South America	55		66		(11		)	(16.7	)%
Northwestern Europe	38		44		(6		)	(13.6	)%
West Africa	32		46		(14		)	(30.4	)%
Far East, Southeast Asia and Australia	28		39		(11		)	(28.2	)%
Indian Ocean	7		16		(9		)	(56.3	)%
Other	20		24		(4		)	(16.7	)%
Total	226		283		(57		)	(14.7	)%


⁽¹⁾	Based on average monthly rig count data from Baker Hughes


⁽²⁾	Source: Bloomberg


⁽³⁾	Source: IHS Energy – IHS Petrodata World Rig Forecast

Third quarter 2015 average worldwide rig 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 continued low commodity prices that began during the latter half of 2014 and (ii) the resulting 2015 capital spending cuts announced by many oil and gas production companies. Average worldwide working rig count levels for the month of September 2015 decreased approximately 39% from December 2014 but

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were approximately the same as during June 2015. The current worldwide working rig count levels continue to be at their lowest levels since mid-2009. Although the Company has a backlog of work that is scheduled to be executed during the remainder of 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 ~~average monthly rig count data from Baker Hughes~~

⁽²⁾~~Source: Bloomberg~~

⁽³⁾~~Source: ODS-Petrodata Ltd.~~the Company’s long history in the energy sector, we believe such declines in commodity prices and the level of demand 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 Company remains competitive. The Company cannot predict the duration or depth of this down cycle.

~~The increase in~~In the United States, the average ~~worldwide operating~~number of rigs drilling for oil during the third quarter of 2015 decreased approximately 59% from the same period in 2014 asand, at the end of September 2015, decreased approximately 2% from the end of the second quarter of 2015, to its lowest level since August 2010. Rigs drilling for oil accounted for approximately 77% of total U.S. rig count levels at the end of September 2015, compared to 82% at the ~~third quarter~~end of ~~2013 was primarily due to an increase in North American~~September 2014. The number of rigs drilling for ~~oil and higher activity levels~~gas in the ~~Middle East and Asia Pacific regions.~~

Crude oil prices (West Texas Intermediate, Cushing, OK) trended downward most of the quarter after reaching a high of $107.62 in late July before closing the period at $91.16 per barrel. On average, crude oil prices were almost 8% lowerUnited States during the third quarter of ~~2014 as compared to~~2015 was approximately 36% less than the third quarter of ~~2013. The twelve month futures price for crude oil at September 30, 2014 was slightly lower than spot prices near~~2014. Based on data from Baker Hughes, gas rig count levels in the ~~end of the quarter.~~ ~~Oil prices have continued to decline into the low-to-mid $80 range on the New York Mercantile Exchange~~United States during ~~the first half of October 2014. This decline, if continuing, could affect exploration and production activity levels and, therefore, demand for the Company's products and services.~~

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~~Natural gas (Henry Hub) prices were fairly consistent throughout~~ the third quarter of ~~2014, averaging $3.93 per MMBtu, which is~~2015 declined to their lowest levels in more than a ~~10% increase~~quarter of a century.

The decrease in the Canadian rig count during the third quarter of 2015 as compared to the same period in ~~2013.~~2014 was due largely to a decrease of approximately 61% in the number of rigs drilling for oil. Rigs drilling for gas decreased approximately 38% during those same periods.

Average crude oil and natural gas prices were significantly lower during the third quarter of 2015 as compared to the same period last year. Both WTI and Brent crude prices at the end of the third quarter of 2015 have declined approximately 51% and 46%, respectively, since September 30, 2014. The ~~12-month~~twelve-month futures price for WTI crude oil at September 30, 2015 was approximately 6% higher than spot prices at the end of the quarter. The twelve-month futures price for Brent crude oil at September 30, 2015 was approximately 7% lower than spot prices at the end of the third quarter.

Average natural gas prices during the third quarter of 2015 were down approximately 30% from the same period in 2014 and increased slightly when compared to average prices during the second quarter of 2015. Spot prices at the end of September 2015 were approximately 40% lower than at the end of September 2014. At September 30, 2015, the twelve-month futures strip price for natural gas at ~~September 30, 2014~~Henry Hub was ~~$4.01~~$2.75 per MMBtu, which ~~is comparable to~~was 10% higher than the spot price at ~~September 30, 2014.~~that date of $2.47 per MMBtu.

The total number of drillships and semi-submersibles ~~available for contract and~~ under contract ~~were generally consistent with the same period of prior year with some redeployment occurring away~~at September 30, 2015 was down from ~~Central and South America~~September 30, 2014 due to the ~~U.S. Gulf~~decline in commodity prices and drilling activity that began in the latter half of ~~Mexico~~2014. Based on data from IHS Energy, the contracted utilization rates for drillships was 75.8% in September 2015 compared to 92.7% in September 2014 and ~~certain other regions~~the contracted utilization rate for semi-submersibles was 70.2% in September 2015 compared to 81.9% in September 2014. At September 30, 2015, the supply of available semi-submersibles and drillships currently exceeds demand with additional supply expected to come on-line during the remainder of 2015 and beyond. Many of the ~~world.~~newbuild drillships and semi-submersibles that are currently on order, planned or under construction do not currently have contracts in place. In connection with this, and in response to current market conditions, certain drilling contractors are making efforts to defer delivery of newbuild units and have begun to cold stack or scrap certain older rigs in their existing portfolios.

Consolidated Results

Consolidated net income for the third quarter of 2014 totaled $238 million, compared to $192 million for the third quarter of 2013. These amounts included $3 million and $14 million, respectively, of net income from discontinued operations for the third quarters of 2014 and 2013. Discontinued operations include the Company's Reciprocating Compression business sold in June 2014 and the Centrifugal Compression business in which the Company entered into a definitive agreement in August 2014 to sell (see Note 2 of the Notes to Consolidated Condensed Financial Statements for further information). Consolidated net income also includes $13 million and $3 million, respectively, of net income attributable to noncontrolling interests for the third quarters of 2014 and 2013.

Net income attributable to Cameron stockholders for the third quarter of ~~2014~~2015 totaled ~~$225~~$187 million, compared to ~~$189~~$225 million for the ~~third quarter of 2013.~~same period in 2014. Earnings from continuing operations per diluted share totaled $0.98 for the third quarter of 2015, compared to $1.10 per diluted share for the same period in 2014. Included in the third quarter 2015 results were certain costs totaling $0.20 per diluted share, primarily associated with:

the estimated loss and asset write-downs of $24 million associated with the expected sale of the Company’s LeTourneau Offshore Products business, and

merger, severance and restructuring activities.

Included in the results for the third quarter of 2014 ~~compared to $0.72 per diluted share for the third quarter of 2013. Included in the third quarter 2014 results~~ were ~~certain~~after-tax costs, totaling $0.07 per diluted share, primarily ~~associated with:~~

related to a loss on disposal of non-core assets,

costs associated with the early retirement of certain Senior Notes ~~originally due in April 2015,~~ and

severance, restructuring and ~~certain~~various other costs.

~~The results for the third quarter~~Table of ~~2013 included after-tax charges of $0.03 per share, primarily related to the integration of OneSubsea and certain other acquisitions.~~Contents

~~Absent these costs, diluted earnings from continuing operations per share would have increased approximately 56% in the third quarter of 2014 as compared to the third quarter of 2013.~~

Total revenues for the Company ~~increased $361~~decreased $470 million, or ~~15.6%~~17.6%, during the three months ended September 30, ~~2014~~2015 as compared to the three months ended September 30, ~~2013. Nearly 94% of~~2014. Revenues declined in all reporting segments due to weak market conditions resulting from the ~~increase was attributable to higher revenues~~decrease in the Drilling & Production Systems (DPS) segment, reflecting improved performance across each major product line. Revenues in the Valves & Measurement (V&M) segment were up 10% compared to the same period last year, mainly as a result of increased sales of engineeredcommodity prices and ~~distributed valves, while PCS segment revenues, excluding discontinued operations, were down nearly 15%.~~activity levels described above.

~~As a percent of~~The Company’s margins (defined as revenues minus cost of sales, ~~(exclusive of~~excluding depreciation and ~~amortization)~~amortization, divided by revenues) increased ~~from 71.2%~~to 30.7% during the third quarter of ~~2013 to 71.5% for~~2015 from 28.5% during the ~~third quarter of~~same period in 2014 mainly as a result of ~~lower product margins~~continuing improvements in project execution coupled with favorable margin mix compared to prior year in the Subsea and Drilling segments partially offset by pricing pressures and volume declines in Surface and V&M ~~and PCS segments~~ as described further below under ~~"Segment Results"~~“Segment Results”.

Selling and administrative expenses decreased $5$64 million, or ~~1.5%~~20.0%, during the three months ended September 30, ~~2014~~2015 as compared to the three months ended September 30, ~~2013.~~2014. This decrease reflects the results of the Company’s internal transformation which began in 2014. The goal of this transformation effort is to permanently lower the Company’s operating cost structure. Selling and administrative expenses were ~~11.9%~~11.6% of revenues for the third quarter of ~~2014,~~2015, down from ~~14.0%~~11.9% for the third quarter of ~~2013, reflecting the impact of cost control efforts.~~

Depreciation and amortization expense totaled $83 million for the third quarter of 2014 as compared to $79 million during the third quarter of 2013, an increase of $4 million. The increase was due primarily to higher depreciation expense as a result of recent increased levels of capital spending, mainly in the Surface Systems and OneSubsea divisions, partially offset by a nearly $7 million decrease in intangible asset amortization in Drilling Systems.

~~Table of Contents~~

Net interest increased $13 million, from $23 million during the third quarter of 2013 to $36 million during the third quarter of 2014, mainly resulting from additional interest associated with (i) $750 million of new senior notes issued by the Company in December 2013, (ii) $500 million of new senior notes issued in June 2014, and (iii) increased interest associated with certain tax contingencies.2014.

Other costs totaled ~~$19~~$44 million for the three months ended September 30, ~~2014 as compared~~2015, largely related to the estimated loss and asset write-downs of $24 million associated with the expected sale of the Company’s LeTourneau Offshore Products business anticipated to close in the second quarter of 2016 and various acquisition and restructuring activities. The loss on disposal of certain non-core assets, costs associated with the early retirement of ~~$14 million~~certain Senior Notes and severance, restructuring and various other costs accounted for the ~~three months ended September 30, 2013.~~majority of the $19 million of costs recognized in the third quarter of 2014. See Note 34 of the Notes to Consolidated Condensed Financial Statements for further ~~information on the nature of these items.~~information.

The ~~Company's~~Company’s effective tax rate on income from continuing operations for the third quarter of ~~2014~~2015 was ~~23.0%~~16.9% compared to ~~21.5%~~23.0% for the third quarter of ~~2013.~~2014. The components of the effective tax rates for both periods were as ~~follows (dollars in millions):~~follows:

Three Months Ended September 30,
2014 2013
Tax Provision Tax Rate Tax Provision Tax Rate

Forecasted tax expense by jurisdiction $ 66 21.6 % $ 55 24.1 %
Adjustments to income tax provision:
Finalization of prior year returns 4 1.3 (4 ) (1.8 )
Changes in valuation allowances 3 1.0 – –
Accrual adjustments and other (3 ) (0.9 ) (2 ) (0.8 )
Tax provision $ 70 23.0 % $ 49 21.5 %



	Three Months Ended September 30,
	2015					2014
(dollars in millions)	Tax Provision			Tax Rate		Tax Provision			Tax Rate

Provision (benefit) based on international income (loss) distribution	$	43		16.7	%	$	66		21.6	%
Adjustments to income tax provision:
Asset impairments	(5		)	(2.0	)	—			—
Finalization of prior year returns	(2		)	(0.9	)	4			1.3
Changes in valuation allowances	8			2.9		3			1.0
Accrual adjustments and other	—			0.2		(3		)	(0.9	)
Tax provision	$	44		16.9	%	$	70		23.0	%

Segment Results

Segment 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 11 of the Notes to Consolidated Condensed Financial Statements included in this Quarterly Report on Form 10-Q.

~~DPS~~

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Subsea Segment –

Three Months Ended
September 30,
Increase (Decrease)
($ in millions) 2014 2013 $ %

Revenues $ 1,975 $ 1,637 $ 338 20.6 %
Income from continuing operations before income taxes $ 295 $ 216 $ 79 36.6 %
Income from continuing operations before income taxes as a percent of revenues 14.9 % 13.2 % N/A 1.7 %

Orders $ 1,874 $ 2,205 $ (331 ) (15.0 )%
Backlog (at period-end) $ 8,996 $ 9,162 $ (166 ) (1.8 )%



	Three Months Ended September 30,						Increase (Decrease)
(dollars in millions)	2015			2014			$			%

Revenues	$	758		$	779		$	(21	)	(2.7	)%
Segment operating income before interest and income taxes	$	120		$	44		$	76		172.7	%
Segment operating income before interest and income taxes as a percent of revenues	15.8		%	5.6		%	N/A			10.2 pts.

Orders	$	270		$	813		$	(543	)	(66.8	)%
Backlog (at period-end)	$	3,454		$	4,703		$	(1,249	)	(26.6	)%

Revenues

Increased shipments and higher manufacturing activity associated with high beginning-of-the-period backlog levels, as well as higher aftermarket revenues resulting from an increasing base of installed equipment, led to a 36% increaseRevenues decreased modestly in ~~drilling equipment revenues and a 15% increase in subsea equipment revenues during~~ the third quarter of ~~2014~~2015 as compared to the third quarter of ~~2013.~~2014, primarily as a result of lower shipments for a subsea project offshore West Africa, partially offset by increased processing system revenues, mainly associated with a large gas processing facility project in Malaysia.

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 significantly in the third quarter of 2015 as compared to the same period in 2014, due mainly to continued improvement in project execution, cost control efforts and favorable margin mix, which added 9.3 percentage-points to the ratio. Also contributing to the ~~improvement in segment revenues~~improved performance was ~~an 8% increase in surface equipment revenues, largely~~lower depreciation and amortization expense, as a result of ~~higher~~lower intangible asset amortization and capital spending constraints, which increased the ratio by 0.7 percentage-points.

Orders

Orders decreased significantly during the three months ended September 30, 2015 as compared to the same period in 2014, primarily due to the lack of new subsea tree awards, particularly in the Gulf of Mexico as compared to the third quarter of 2014, and lower demand for new processing equipment.

Backlog (at period-end)

Backlog in the Subsea segment continues to drop as changing market conditions during the last twelve months caused a slowdown in new subsea production and processing equipment project awards as customers significantly reduce their capital spending programs.

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Surface Segment –



	Three Months Ended September 30,						Increase (Decrease)
(dollars in millions)	2015			2014			$			%

Revenues	446			600			$	(154	)	(25.7	)%
Segment operating income before interest and income taxes	49			105			$	(56	)	(53.3	)%
Segment operating income before interest and income taxes as a percent of revenues	11.0		%	17.5		%	N/A			(6.5) pts.

Orders	$	453		$	665		$	(212	)	(31.9	)%
Backlog (at period-end)	$	942		$	1,202		$	(260	)	(21.6	)%

Revenues

The decline in revenues during the third quarter of 2015 as compared to the third quarter of 2014 was primarily due to weak market conditions in North America, which represented approximately 65% of the total decrease, as a result of a decline in demand and pricing for new equipment and services, particularly with regard to equipment and services used in the hydraulic fracturing process. Declines representing approximately 25% of the total decrease were also seen in the international markets in Europe and the Middle East as compared to prior year due to lower orders rates in 2015 due to reduced spending by customers in response to lower oil prices.

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

Selling and administrative costs and depreciation and amortization expense declined on a combined basis during the third quarter of 2015 as compared to the same period in the prior year. However, the rate of decline did not match the 26% decrease in revenues, resulting in a drop of 4.2 percentage points in the ratio of segment operating income before interest and income taxes as a percent of revenues. Lower margins contributed to an additional 2.2 percentage-point decline in the ratio as compared to the same period in the prior year, largely attributable to pricing pressures in the North America unconventional markets and lower new product sales in Europe and the Middle East.

Orders

Orders declined during the third quarter of 2015 as compared to the third quarter of 2014 as a result of reduced activity levels in the North American unconventional resource regions ~~of North America.~~and various international markets in response to declining commodity prices.

Backlog (at period-end)

The decrease in segment backlog at September 30, 2015 as compared to September 30, 2014 largely reflects weakness in demand for new equipment and services during the last twelve months due to current weak market conditions resulting from the recent decline in commodity prices.

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Drilling Segment –



	Three Months Ended September 30,						Increase (Decrease)
(dollars in millions)	2015			2014			$			%

Revenues	$	673		$	800		$	(127	)	(15.9	)%
Segment operating income before interest and income taxes	$	146		$	159		$	(13	)	(8.2	)%
Segment operating income before interest and income taxes as a percent of revenues	21.7		%	19.9		%	N/A			1.8 pts.

Orders	$	344		$	574		$	(230	)	(40.1	)%
Backlog (at period-end)	$	2,074		$	3,725		$	(1,651	)	(44.3	)%

Revenues

~~Income from continuing operations~~Segment revenues decreased in the third quarter of 2015 as compared to the third quarter of 2014 mainly due to lower backlog levels for projects and new rig equipment sales as a result of weak order rates in recent months, which represented approximately 55% of the total decrease, and a drop in services revenue (includes activities and products to support our existing customer installed base), which represented approximately 40% of the total decrease, reflecting (i) a decrease in our installed base as customers have elected to scrap older rigs and (ii) the deferral of customer spending on discretionary services.

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

The increase in ~~the ratio of~~segment operating income ~~from continuing operations~~ before interest and income taxes as a percent of revenues in the third quarter of 2015 as compared to the same period last year was due primarily ~~due to:~~

to (i) higher margin new equipment and project mix in 2015 compared to 2014 combined with continued improvement in project execution and (ii) cost control efforts, including a ~~0.4 percentage-point~~ decrease in selling and administrative expenses, which added 3.2 percentage-points to the ~~ratio~~ratio. Partially offsetting this was the impact of cost of sales to revenues resulting mainly from improved margins in the drilling equipment product line, largely related to growth in higher-margin land and jackup BOP activity and aftermarket business, as well as better cost recovery on rig projects,

~~a 0.4 percentage-point decrease in the ratio of~~higher depreciation and amortization expense, mainly associated with amortization of certain intangible assets, in relation to lower revenues ~~due mainly~~which resulted in a decline of ~~nearly $7 million in intangible asset amortization expense in Drilling Systems, and~~

~~a 1.0 percentage-point decrease~~1.3 percentage-points in the ~~ratio of selling and administrative expense to revenues as a result of the effects of cost control efforts in relation to the growth in revenues.~~

ratio.

Orders

~~The decrease in orders was due to:~~

a 40% decline in subsea equipment orders, largely associated with a third quarter 2013 award, totaling more than $500 million, that was received from Chevron for the Rosebank project in the UK North Sea, with no similar-size large project award received inOrder rates declined during the third quarter of ~~2014~~2015 as ~~customers continued~~compared to ~~evaluate project economics and field layout designs which has had an impact on~~ the ~~timing of new awards, and~~

~~a 9% decrease~~same period in ~~drilling equipment orders, mainly resulting from a softening in the market for newbuild jackup rigs and floaters.~~

These decreases were partially offset by a 37% increase in surface equipment orders reflecting continued high demand for new equipment, including rental equipment and other aftermarket parts and services, largely2014 as a result of ~~continued strong activity levels~~(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 ~~the unconventional resource regions~~demand for new rigs and (iii) a deferral of ~~North America and increased activity in the Middle East, particularly in Saudi Arabia and Oman.~~customer spending on discretionary services.

Backlog (at period-end)

~~The decline in backlog at September 30, 2014 as compared to September 30, 2013 was due mainly to:~~

~~a 7% decrease in drilling equipment backlog largely resulting from (i) the reversal of nearly $243 million in backlog~~Backlog in the ~~first quarter of 2014 as the result of a customer cancellation of a large drilling project award issued in 2012, and (ii) a softening in the market for newbuild jackup rigs and floaters, as well as~~

~~a 4% decrease in subsea equipment backlog, due~~Drilling segment continues to drop mainly ~~to the slower pace of large new project awards over the course of the first three quarters of 2014.~~

~~Partially offsetting these declines was a 28% increase in surface equipment backlog~~ due to ~~recent high order rates largely resulting from continued strong~~significantly lower activity levels in the ~~unconventional resource regions of North America~~new rig construction market, especially in relation to deepwater rigs. Service backlog (includes activities and ~~increased activity~~products to support our existing customer installed base) has also declined 28% as customer decisions to scrap older rigs have resulted in ~~recent periods~~a decrease in ~~the Middle East, particularly in Saudi Arabia~~our installed base and ~~Oman.~~as customers have elected to defer discretionary spending on services.

2326

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V&M Segment –

Three Months Ended
September 30,
Increase/(Decrease)
($ in millions) 2014 2013 $ %

Revenues $ 552 $ 502 $ 50 10.0 %
Income from continuing operations before income taxes $ 103 $ 98 $ 5 5.1 %
Income from continuing operations before income taxes as a percent of revenues 18.7 % 19.5 % N/A (0.8 )%

Orders $ 529 $ 497 $ 32 6.4 %
Backlog (at period-end) $ 954 $ 1,058 $ (104 ) (9.8 )%



	Three Months Ended September 30,						Increase (Decrease)
(dollars in millions)	2015			2014			$			%

Revenues	$	376		$	558		$	(182	)	(32.6	)%
Segment operating income before interest and income taxes	$	58		$	104		$	(46	)	(44.2	)%
Segment operating income before interest and income taxes as a percent of revenues	15.4		%	18.6		%	N/A			(3.2) pts.

Orders	$	346		$	529		$	(183	)	(34.6	)%
Backlog (at period-end)	$	763		$	954		$	(191	)	(20.0	)%

Revenues

~~Favorable North American market conditions and the impact of businesses acquired~~Segment revenues declined by 33% in ~~the last twelve months contributed to an increase of 15% in sales of distributed valves. Engineered valve sales increased 18% during~~ the third quarter of ~~2014~~2015 as compared to the third quarter of ~~2013,~~2014. Valve sales declined 33% and sales of measurement products were down 38%, due ~~primarily~~mainly to ~~weak market conditions during~~weakness in the North America upstream drilling and production markets. Also, impacting the third quarter results was a 7% decline in Services revenue as a result of ~~2013 which negatively impacted shipments during that period.~~lower activity levels in Asia Pacific.

~~Income from continuing operations~~Segment operating income before interest and income taxes as a percent of revenues

~~Income~~Lower product margins resulting from ~~continuing operations~~lower volumes and pricing pressures resulted in a 1.8 percentage-point decrease in segment operating income before interest and income taxes as a percent of revenues decreased primarily due to (i) a 1.6 percentage-point decrease in margins resulting from pricing pressures and the impact of higher costs, primarily for engineered valves, and (ii) a 0.3 percentage-point increase in the ~~ratio~~third quarter of depreciation and amortization expense to revenues due to higher depreciation from recent increased levels of capital spending, mainly in the engineered valve product line, and the impact of businesses acquired during the last twelve months.

~~Offsetting these cost increases was a 1.0 percentage-point decrease in the ratio of selling and administrative expenses to revenues~~2015 as ~~a result of the effects of cost control efforts in relation to the growth in revenues.~~

~~Orders~~

~~Overall, total segment orders increased slightly when~~ compared to the same period ~~last year. Distributed~~in 2014. An additional 1.2 percentage-point decline in the ratio was due to the impact of higher depreciation and amortization expense in relation to a 33% decrease in revenues during the third quarter of 2015.

Orders

Segment orders declined by 35% in the third quarter of 2015 as compared to the third quarter of 2014. Valve orders declined 34% due to lower demand from major distributors, as they reduced inventory levels, in response to the weakness in the North America upstream drilling and production activities. Additionally, valve ~~orders increased 23% reflecting higher~~demand for subsea activity, ~~levels~~globally, and midstream pipeline projects in North America ~~while certain large orders for metering equipment~~slowed as capex spend is reassessed. The weakness in the ~~current period~~North America upstream production market also led to a ~~13% increase~~39% decline in demand for ~~measurement~~Measurement products. ~~Partially offsetting these increases was a 13% decline in engineered valve orders due mainly to project timing delays.~~

Backlog (at period-end)

~~Backlog levels for the V&M segment~~Segment backlog decreased approximately 10% from September 30, 2013, as recent order rates for new engineered and process valves have not kept pace with recent deliveries. These decreases were partially offset by strong demand for distributed valves and measurement products reflecting continued strength20% in the ~~North American market.~~

~~Table~~third quarter of ~~Contents~~

~~PCS Segment –~~

Three Months Ended
September 30,
Increase (Decrease)
($ in millions)
2014⁽¹⁾

2013⁽¹⁾
$ %

Revenues $ 151 $ 178 $ (27 ) (15.2 )%
Income from continuing operations before income taxes $ 9 $ 13 $ (4 ) (30.8 )%
Income from continuing operations before income taxes as a percent of revenues 6.0 % 7.3 % N/A (1.3 )%

Orders $ 178 $ 206 $ (28 ) (13.6 )%
Backlog (at period-end) $ 634 $ 499 $ 135 27.1 %

⁽¹⁾~~Excluding discontinued operations~~

~~Revenues~~

~~The revenue decrease in the PCS segment was due primarily~~2015 as compared to the timing of manufacturing activity on large custom engineered processing equipment projects, particularly in Canada and the Asia Pacific region, and weaker demand from North American customers for midstream processing applications.

~~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:~~

~~lower product margins of 1.4 percentage-points, mainly due to low volumes and underabsorption of costs in the wellhead and midstream processing product line, and~~

~~a 0.9 percentage-point increase in the ratio of depreciation and amortization expense to revenues as a result of higher depreciation and amortization expense during~~ the third quarter of 2014, resulting from a decline in ~~relation~~upstream drilling and production activity levels in North America and Subsea activity, globally, accounted for over three-quarters of the decline. The majority of the remaining decline was due to lower ~~revenues as compared to the same period last year.~~midstream pipeline projects and downstream gas processing awards. Services backlog is up 11%.

~~Partially offsetting these cost increases was a 1.2 percentage-point decrease in the ratio of selling and administrative~~Corporate Expenses -

Corporate expenses ~~to revenues as a result of the effects of cost control efforts.~~

~~Orders~~

~~The decrease in segment orders was due mainly to a large award received in~~were $28 million for the third quarter of ~~2013 for~~2015, a CO₂ ~~separation system for a floating production storage and offloading (FPSO) vessel to be located offshore Brazil, with no similar-size custom engineered project award received during the third quarter~~decline of ~~2014, partially offset by a large award during the third quarter of 2014 for a new cryogenic gas processing system.~~

~~Backlog (at period-end)~~

Overall segment backlog was up 27% at September 30, 2014 as compared to September 30, 2013, largely as the result of a $250 million award received in the fourth quarter of 2013 for equipment to be provided for a gas processing facility in Malaysia.

~~Table of Contents~~

~~Corporate Segment –~~

~~The loss from continuing operations before income taxes in the Corporate segment increased $2~~$7 million from ~~$100 million in the third quarter of 2013 to $102~~$35 million in the third quarter of 2014. This ~~increase was due largely to:~~decrease reflects the results of the Company’s internal transformation which began in 2014. The goal of this transformation effort is to permanently lower the Company’s operating cost structure.

~~a $13 million increase in net interest, as described further in "Consolidated Results" above, and~~27

~~a $5 million increase in other costs, as described further in Note 3~~Table of ~~the Notes to Consolidated Condensed Financial Statements.~~Contents

~~Mostly offsetting these increases was a $16 million reduction in selling and administrative costs as a result of the effects of cost control efforts.~~

NINE MONTHS ENDED SEPTEMBER 30, ~~2014~~2015 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, ~~2013~~2014

Market Conditions

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

Nine Months Ended
September 30,
Increase
2014 2013 Amount %
Drilling activity (average number of working rigs during period)⁽¹⁾:

United States 1,845 1,763 82 4.7 %
Canada 371 347 24 6.9 %
Rest of world 1,344 1,288 56 4.3 %
Global average rig count 3,560 3,398 162 4.8 %

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 $ 99.77 $ 98.17 $ 1.60 1.6 %
Henry Hub natural gas spot price per MMBtu in U.S. dollars $ 4.57 $ 3.70 $ 0.87 23.5 %

⁽¹⁾~~Based on average monthly rig count data from Baker Hughes~~



	Nine Months Ended September 30,				Decrease
	2015		2014		Amount			%
Drilling activity (average number of working rigs during period)⁽¹⁾:
United States	1,052		1,845		(793		)	(43.0	)%
Canada	200		371		(171		)	(46.1	)%
Rest of world	1,187		1,344		(157		)	(11.7	)%
Global average rig count	2,439		3,560		(1,121		)	(31.5	)%

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)	$	50.94	$	99.77	$	(48.83	)	(48.9	)%
Brent crude oil spot price (per barrel)	$	60.19	$	105.59	$	(45.40	)	(43.0	)%
Henry Hub natural gas spot price (per MMBtu)	$	2.77	$	4.55	$	(1.78	)	(39.1	)%

^{(2)
⁽¹⁾ Source: Bloomberg

Based on average monthly rig count data from Baker Hughes
⁽²⁾ Source: Bloomberg
The increasedecrease in average worldwide operating rigs during the first nine 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 nine 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 during the first nine months of 2015 has decreased approximately 46% as compared to the same period in 2014, while the average number of rigs drilling for gas has decreased approximately 27% during the same period. In Canada, the average number of rigs drilling for oil during the first nine months of 2015 has decreased approximately 59% as compared to the first nine months of 2013 was driven primarily by higher North American oil drilling activity and higher activity levels in2014, while the Middle East and Asia Pacific regions and in 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 of rigs drilling for gas was down slightly in North America in the first nine months of 2014 as compared to the first nine months of 2013.

Crude oil prices (West Texas Intermediate, Cushing, OK) were relatively consistent throughout much of the first nine months of 2014 reaching a high of $107.62 per barrel in late July before closing the period at its lowest level since May 2013 of $91.16 per barrel. On average, crude oil prices were relatively flathas decreased approximately 28% during the first nine monthssame period. Internationally, the average number of 2014 as compared to the first nine months of 2013. Oil prices have continued to decline into the low-to-mid $80 range on the New York Mercantile Exchange during the first half of October 2014. This decline, if continuing, could affect exploration and production activity levels and, therefore, demand for the Company's products and services.

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In early February 2014, natural gas (Henry Hub) prices reached their highest levels since September 2011, before leveling off to close at $4.02 per MMBtu at September 30, 2014. On average, prices during the first nine months of 2014 were up almost 24%active working rigs declined as compared to the same period in 2013.

Consolidated Results2014 in all major regions of the world, except the Middle East.

Consolidated net income forAverage crude oil and natural gas prices were significantly lower during the first nine months of 2014 totaled $587 million,2015 as compared to $481 million forthe same period last year. WTI and Brent crude prices at the end of the first nine months of 2013. These amounts included $31 million2015 have declined approximately 18% and $42 million,20%, respectively, of net income from discontinued operations for the nine months ended September 30,since year end 2014 and 2013. Consolidated net income also includes $29 million and $3 million, respectively, of net income attributable to noncontrolling interests for the first nine months of 2014 and 2013.prices.

Consolidated Results
Net income attributable to Cameron stockholders for the nine months ended September 30, 20142015 totaled $558$376 million, compared to $478$558 million for the first nine months of 2013. Earnings2014. The Company had a loss from continuing operations for the first nine months of 2015 of $55 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 $431 million, which mainly represented the gain on the sale of the Company’s Centrifugal Compression business. The Company’s loss from continuing operations per diluted share totaled $2.53$0.29 for the first nine months of 2014,2015, compared to $1.77earnings from continuing operations per diluted share of $2.53 for the same period in 2014. The goodwill impairment charge described above, as well as the $24 million estimated loss and asset write-downs on the expected sale of the Company's LeTourneau Offshore Products business and various other asset impairment charges and other costs described further in Note 4 of the Notes to Consolidated Condensed Financial Statements totaled $3.20 per diluted share for the same period in 2013. Included in the results for thefirst nine months ended September 30, 2014 were charges, net of certain gains, totaling $0.26 per diluted share, primarily associated with:
a goodwill impairment charge related to the PSE business and an impairment of certain intangible assets,
a loss on disposal of non-core assets,
2015.

costs associated with the early retirement28
Table of Senior Notes originally due in April 2015,Contents

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

severance, restructuring, and certain other costs.

The results for the first nine months of 20132014 included after-tax charges of $0.36$0.26 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, a loss on disposal of non-core assets, as well as currency devaluation, severance, restructuring and other costs.

Absent these costs, in both periods, diluted earnings from continuing operations per share would have increased nearly 31% as compared to the first nine monthsnet of 2013.certain non-operating gains.

Total revenues for the Company increased nearly $1.2 billion, or 18.3%, during the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. Nearly 24% of the increase was attributable to businesses acquired since the beginning of 2013 with the remaining increase reflecting higher revenues in each major product line in the DPS segment. Revenues in the V&M segment were up modestly compared to the same period last year while PCS segment revenues, excluding discontinued operations, were down 18%.

As a percent of revenues, cost of sales (exclusive of depreciation and amortization) were 72.0% for the first nine months of 2014 as compared to 71.0% for the first nine months of 2013. The increase was mainly the result of higher costs in relation to revenues in each segment as described further below under "Segment Results".

Selling and administrative expenses increased $50decreased $874 million, or 5.4%11.5%, during the nine months ended September 30, 20142015 as compared to the same period in 2014. Revenues declined in each segment due to the impact of the weak market conditions resulting from the decrease in commodity prices and activity levels described above.

The Company’s margins (defined as revenues minus cost of sales, excluding depreciation and amortization, divided by revenues) increased to 29.5% during the first nine months of 2015 from 28.0% during the same period in 2014, mainly due to improvements in project execution coupled with favorable margin mix compared to prior year in the Subsea and Drilling segments partially offset by pricing pressures and volume declines in Surface and V&M as described further below under “Segment Results”.

Selling and administrative expenses decreased $149 million, or 15.4%, during the nine months ended September 30, 2013.2015 as compared to the same period in 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 12.8%12.2% of revenues for the first nine months of 2014,2015, down from 14.4%12.8% for the same period in 2013, reflecting the impact of cost control efforts in relation to the growth in revenues.2014.

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Depreciation and amortization expense totaled $256 million for the nine months ended September 30, 2014 as compared to $211 million for the nine months ended September 30, 2013, an increase of $45 million. The increase was due mainly to higher depreciation expense as a result of recentInterest, net increased levels of capital spending, primarily in the DPS segment, 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, partially offset by a $7 million, decrease in intangible asset amortization in Drilling Systems.

Net interest increased $24 million, from $74 million during the first nine months of 2013 to $98 million during the first nine months of 2014 to $105 million during the same period in 2015, mainly resulting from additional interest associated with (i) $750 millionas a result of new senior notes issued by the Company in December 2013 and (ii) $500 million of new senior notes issued in June 2014.2014 and higher interest on capital leases.

Other costs netwere $658 million in the first nine months of credits, totaled2015, largely associated with (i) the goodwill impairment for the Process Systems business described above, (ii) an estimated loss and asset write-downs of $24 million associated with the expected sale of the Company’s LeTourneau Offshore Products business, (iii) accelerated depreciation on underutilized assets, and (iv) pending facility closures and severance activities taken in response to current market conditions. Charges of $62 million forwere recognized during the first nine months ended September 30,of 2014 as comparedlargely related to $80 million for the nine months ended September 30, 2013, a decrease of $18 million.factors described above. See Note 34 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 nine months of 20142015 was 24.4%109.1% as compared to 23.7%24.4% for the first nine months of 2013.same period in 2014. The components of the effective tax rates for both periods were as follows (dollars in millions):

Nine Months Ended September 30,
2014 2013
Tax Provision Tax Rate Tax Provision Tax Rate

Forecasted tax expense by jurisdiction $ 167 22.7 % $ 134 23.3 %
Adjustments to income tax provision:
Tax effect of goodwill impairment 9 1.3 – –
Finalization of prior year returns 4 0.5 6 1.0
Tax effects of changes in legislation – – (9 ) (1.6 )
Changes in valuation allowances 3 0.4 5 1.0
Accrual adjustments and other (4 ) (0.5 ) – –
Tax provision $ 179 24.4 % $ 136 23.7 %
follows:

Nine Months Ended September 30,
2015 2014
(dollars in millions) Tax Provision Tax Rate Tax Provision Tax Rate

Provision (benefit) based on international income (loss) distribution $ 27
20.5 % $ 167
22.7 %
Adjustments to income tax provision:

Impairments with no tax benefit 113
86.0
9
1.3
Asset impairments (5 ) (3.8 ) —
—
Finalization of prior year returns —
—
4
0.5
Changes in valuation allowances 8
6.3
3
0.4
Accrual adjustments and other 1
0.1
(4 ) (0.5 )
Tax provision $ 144
109.1 % $ 179
24.4 %

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Segment Results

DPSSubsea Segment –

Nine Months Ended
September 30, Increase (Decrease)
($ in millions) 2014 2013 $ %

Revenues $ 5,583 $ 4,344 $ 1,239 28.5 %
Income from continuing operations before income taxes $ 713 $ 566 $ 147 26.0 %
Income from continuing operations before income taxes as a percent of revenues 12.8 % 13.0 % N/A (0.2 )%

Orders $ 5,323 $ 6,451 $ (1,128 ) (17.5 )%

Nine Months Ended September 30, Increase (Decrease)
(dollars in millions) 2015 2014 $ %

Revenues $ 2,047
$ 2,195
$ (148 ) (6.7 )%
Segment operating income before interest and income taxes $ 244
$ 119
$ 125
105.0 %
Segment operating income before interest and income taxes as a percent of revenues 11.9 % 5.4 % N/A
6.5 pts.

Orders $ 1,572
$ 1,838
$ (266 ) (14.5 )%
Revenues

Businesses acquired sinceRevenues decreased during the beginningfirst nine months of 2013 accounted for 21%2015 as compared to the same period in 2014, as a result of the revenue increase for the segment. Absent this impact, increaseddecreased subsea equipment shipments, and higher manufacturing activitylargely associated with high beginning-of-the-year backlog levels,the completion of projects offshore West Africa and in Asia. This was minimally offset by increased processing system revenues, mainly associated with a large gas processing facility project in Malaysia, and modest growth in the segment's services revenues (includes activities and products to support our existing customer installed base).

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

Segment operating income before interest and income taxes as higher aftermarketa percent of revenues resulting from an increasing baseimproved significantly in the first nine months of installed equipment, led2015 as compared to the same period in 2014, due mainly to continued improvement in project execution, cost control efforts and favorable margin mix, which added 6.1 percentage-points to the ratio. Also contributing to the improved performance was lower depreciation and amortization expense, mainly as a result of lower intangible asset amortization, which increased the ratio by 0.4 percentage-points.
Orders

Orders decreased during the nine months ended September 30, 2015 as compared to the same period in 2014, primarily due to a 37% increaselower number of new subsea tree awards and lower demand for new processing equipment. Demand for new future services (includes activities and products to support our existing customer installed base) was also down nearly 17%.

Surface Segment –
Nine Months Ended September 30, Increase (Decrease)
(dollars in millions) 2015 2014 $ %

Revenues $ 1,499
$ 1,751
$ (252 ) (14.4 )%
Segment operating income before interest and income taxes $ 210
$ 304
$ (94 ) (30.9 )%
Segment operating income before interest and income taxes as a percent of revenues 14.0 % 17.4 % N/A
(3.4) pts.

Orders $ 1,374
$ 1,920
$ (546 ) (28.4 )%

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Revenues

The decline in drilling equipment revenues and a 19% increase in subsea equipment revenues during the first nine months of 20142015 as compared to the first nine monthssame period in 2014 was primarily due to weak market conditions in North America, which represented approximately 75% of 2013.

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Also contributing to the improvement in segment revenues was a 10% increase in surface equipment revenues, largelytotal decrease, as a result of higher activity levelsa decline in demand and pricing for new equipment and services, particularly with regard to equipment and services used in the unconventional resource regions of North America as well as increased deliveries to customers operatinghydraulic fracturing process. Declines were also seen in the North Sea.international markets in Europe and the Middle East, which represented approximately 25% of the total decrease as compared to prior year due to lower orders rates in 2015 due to reduced spending by customers in response to lower oil prices.

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

The decrease in the ratio of income from continuing operations before income taxesAlthough, selling and administrative costs and depreciation and amortization expense as a percent of revenues was due primarily todeclined on a 0.6 percentage-point increase 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 surface equipment revenues, and

lower margins in the drilling equipment product line due to higher project costs, as well as higher warranty and inventory obsolescence costscombined basis during the first nine months of 20142015 as compared to the first nine monthssame period in 2014, the rate of 2013.

Mostly offsetting thisdecrease was less than the 14% decline in revenues. This impact accounted for almost 74% of the decline in segment operating income before interest and income taxes as a net reductionpercent of 0.4 percentage-pointsrevenues. Lower margins contributed to an additional 1.0 percentage-point decline in the combined ratios of depreciationratio, largely attributable to pricing pressures in the North America unconventional markets and amortization expenselower new product sales in Europe and selling and administrative expensesthe Middle East as compared to revenues, mainly as a result of the effects of cost controls on selling and administrative expenses in relation to the growth in revenues.prior year.

Orders

The decrease in total segment orders was primarily due to a 47% decrease in subsea orders, mainly as a result of certain large project awards receivedOrders declined during the first nine months of 2013, with no similar-sized large awards received2015 as compared to the same period in 2014 as a result of reduced activity levels in various North American unconventional resource regions in response to declining commodity prices, as well as lower demand for new products from customers in various international markets as compared to the levels experienced during the first nine months of 2014, including (i) an award received from Petrobras for subsea trees and associated equipment for use in Pre- and Post-Salt basins offshore Brazil, (ii) a large booking to supply subsea production systems to a project offshore Nigeria, and (iii) an award received from Chevron for the Rosebank project in the UK North Sea. During 2014, customers have continued to evaluate project economics and field layout designs which have had an impact on the timing of new awards.2014.

Partially offsetting the decline in subsea orders was:

an 8% increase in orders for surface equipment, primarily related to continued strength in activity levels in the unconventional resource regions in North America, and

a 3% increase in orders for drilling equipment reflecting several large rig project awards received early in 2014 and increased demand for aftermarket parts and services.

V&MDrilling Segment –

Nine Months Ended
September 30, Decrease
($ in millions) 2014 2013 $ %

Revenues $ 1,580 $ 1,558 $ 22 1.4 %
Income from continuing operations before income taxes $ 304 $ 320 $ (16 ) (5.0 )%
Income from continuing operations before income taxes as a percent of revenues 19.2 % 20.5 % N/A (1.3 )%

Orders $ 1,582 $ 1,560 $ 22 1.4 %

Nine Months Ended September 30, Increase (Decrease)
(dollars in millions) 2015 2014 $ %

Revenues $ 2,118
$ 2,233
$ (115 ) (5.2 )%
Segment operating income before interest and income taxes 400
323
$ 77
23.8 %
Segment operating income before interest and income taxes as a percent of revenues 18.9 % 14.5 % N/A
4.4 pts.

Orders $ 938
$ 2,030
$ (1,092 ) (53.8 )%
Revenues

Overall, segmentThe decline in revenues for the first nine months ended September 30,of 2015 as compared with the same period in 2014 were relatively flat whenmainly reflects a decline in services revenue (includes activities and products to support our existing customer installed base) which represented approximately 87% of the total decrease, as a result of (i) a decrease in our installed base as customers have elected to scrap older rigs and (ii) the deferral of customer spending on discretionary services. Project revenues are also lower as compared to the same period last year.   Sales of distributed valves and measurement products increased 10% and 15%, respectively, mainly as a result of continued strengthin prior year due to the decline in the North American market. Largely offsetting these increases were sales declines of 5%order rate.

Segment operating income before interest and 9% for engineered valves and process valves, respectively, due largely to project slippage, recent order weakness and delayed timing of valve deliveries due to various customer changes.
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Income before income taxes as a percent of revenues

The decreaseincrease 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 0.7 percentage-point increase in the ratio of cost of sales to revenues due mainly to pricing pressures and the impact of higher costs, primarily in engineered and process valves,

a 0.4 percentage-point increase in the ratio of depreciation and amortization expense to revenues due to higher depreciation from recent capital spending, mainly in the engineered valve product line and the impact of businesses acquired during the last twelvefirst nine months and

a 0.2 percentage-point increase in the ratio of selling and administrative costs to revenues, due mainly to higher employee-related costs in relation to revenues.

Orders

Overall, total segment orders were relatively flat when2015 as compared to the same period last year. Distributed valve orders increased 19%in 2014 was due primarily to (i) higher margin new equipment and project mix in 2015 and compared to 2014 combined with continued improvement in project execution (ii) cost control efforts, including a decrease in selling and administrative expenses, which added 4.9 percentage-points to the ratio. Partially offsetting this was the impact of higher depreciation and amortization expense, mainly associated with amortization of certain intangible assets, in relation to lower revenues which resulted in a decline in the ratio of 0.5 percentage-points.

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Orders

Order rates declined during the first nine months of 2015 as compared to the same period in 2014 as a result of higher North American activity levels. This was largely offset by declines(i) cyclical weakness and a significant industry-wide over-supply of approximately 11%drilling rigs which has led to the scrapping of older rigs, (ii) a sharp reduction in demand for new rigs and 15% in both engineered and process valve orders, respectively, due mainly to project slippage and lower new pipeline project activity levels in North America.(iii) the deferral of customer spending on discretionary services.

PCSV&M Segment –

Nine Months Ended
September 30, Decrease
($ in millions) 2014⁽¹⁾ 2013⁽¹⁾ $ %

Revenues $ 414 $ 505 $ (91 ) (18.0 )%
Income from continuing operations before income taxes $ 9 $ 18 $ (9 ) (50.0 )%
Income from continuing operations before income taxes as a percent of revenues 2.2 % 3.6 % N/A (1.4 )%

Orders $ 465 $ 533 $ (68 ) (12.8 )%
⁽¹⁾Excluding discontinued operations

Nine Months Ended September 30, Increase (Decrease)
(dollars in millions) 2015 2014 $ %

Revenues 1,185
1,597
$ (412 ) (25.8 )%
Segment operating income before interest and income taxes $ 147
$ 312
$ (165 ) (52.9 )%
Segment operating income before interest and income taxes as a percent of revenues 12.4 % 19.5 % N/A
(7.1) pts.

Orders $ 1,103
$ 1,582
$ (479 ) (30.3 )%
Revenues

The revenue decreaseSegment revenues declined by 26% for the first nine months of 2015 as compared with the same period in 2014. Valve sales declined 27% as our major distributors have significantly reduced their inventory levels in response to the weakness in the PCS segment was due primarilyNorth America upstream drilling and production markets.   Additionally, lower beginning of year backlog for valves used in midstream pipeline and critical service applications account for a 10% decline in sales in comparison to the timing of manufacturingprior year. Measurement sales declined 25%, due to significantly reduced activity on large international custom engineered processing equipment projects and weaker demand fromlevels in the North American customers for wellhead and midstream processing applications.upstream production markets. Services revenue declined 7% on lower activity in Asia Pacific.

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

TheLower product margins resulting from lower volumes, pricing pressures combined with higher obsolescence and warranty costs resulted in a 4.2 percentage-point decrease in the ratio ofsegment operating income from continuing operations before interest and income taxes as a percent of revenues was due primarily to:

a 1.7 percentage-point increase in the ratio of cost of sales to revenues resulting mainly from lower margins in the wellhead and midstream processing product line due mainly to low volumes and underabsorption of costs, and

a 1.2 percentage-point increase in the ratio of depreciation and amortization expense to revenues as a result of higher depreciation and amortization expense duringfor the first nine months of 2014 in relation to lower revenues2015 as compared to the same period last year.

This was partially offset byin 2014. On a decrease of 1.6 percentage-points in the ratio ofcombined basis, selling and administrative expenses to revenues as a result of cost reduction programs and cost control efforts, including the shutting down of certain facilities during the last twelve months.

Orders

The decrease in segment orders was due mainly to a large award receiveddepreciation and amortization declined in the first nine months of 20132015 as compared to the same period in 2014, however, the rate of decline was less than the rate of decline in revenues, which negatively impacted the ratio of segment operating income before interest and income taxes as a percent of revenues by 2.9 percentage-points.

Orders

Segment orders declined by 30% for a CO₂ separation system for a floating production storage and offloading (FPSO) vessel to be located offshore Brazil, with no similar-size custom engineered project award received during the first nine months of 2015 as compared with the same period in 2014. Valve orders declined 33% and Measurement orders decline 31%, due to lower demand for valves and measurement products in the upstream drilling, production and subsea markets. Furthermore, lower midstream and downstream project activity outside North America also negatively impacted demand for pipeline and gas processing products. Services orders are down 4% on lower activity levels in Asia Pacific.

Corporate Segment –Expenses -

The loss from continuing operations before income taxes in the Corporate segment decreased $38expenses were $74 million from $329 million infor the first nine months of 2013 to $2912015, a decline of $36 million from $110 million in the first nine months of 2014. This decrease was due largely to:reflects the results of the Company’s internal transformation which began in 2014. The goal of this transformation effort is to permanently lower the Company’s operating cost structure.

a combined $48 million decline in depreciation and amortization expense and in selling and administrative expenses, mainly reflecting the effects32
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an $18 million decrease in other costs, as described further in Note 3 of the Notes to Consolidated Condensed Financial Statements.

Partially offsetting these reductions was a $24 million increase in net interest, as described further in "Consolidated Results" above.

Liquidity and Capital Resources

Consolidated Condensed Statements of Cash Flows

During the first nine months of 2014,2015, net cash provided by operations totaled $255$211 million, an increasea decrease of $49$44 million from the $206$255 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 nine months of 2013. The 2014 amount was negatively impacted by approximately $95 million of tax payments made during2015 as compared to the third quarter associated with the pre-tax gain recognized on the sale of the Reciprocating Compression business.same period in 2014.

Cash totaling $532$518 million was used forto increase working capital during the first nine months of 20142015 compared to $464$532 million during the first nine monthssame period in 2014, a decrease of 2013, an increase of $68$14 million. During the first nine months of 2014, approximately $2832015, increased collections of receivables across mainly in the Drilling and Surface segments, added $245 million ofin cash was used to buildand inventory levels,reductions, primarily in the DPSDrilling segment, in order to meet the demands from the high backlog and activity levels in that business segment.increased cash by $106 million. The timing of payments to third parties and annual employee incentive payouts, as well as lowerthe consumption of customer advances received from customers, during the first nine months of 2014 alsoon projects largely contributed to a $869 million use of cash totaling $291 million for the period.

Cash provided by investing activities was $218$444 million for the first nine months of 2015 as compared to $218 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 $209 million of cash was used to increase the Company’s short term investments portfolio during the first nine months of 2014 totaled2015 as compared to $74 million for the same period in 2014. Capital spending for the nine months ended September 30, 2015 consumed $190 million, as compared to $259 million.million during the same period in 2014. Capital needs in the Subsea, Surface Systems and OneSubsea divisionsDrilling segments accounted for the majority of the DPS segment, along with continued development of the Company's enhanced business information systems, accounted for almost three-quarters of the 20142015 capital spending.

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Net cash used for financing activities totaled approximately $1.2 billion$472 million for the first nine months of 2015 as compared to $1.2 billion used for financing activities during the same period in 2014. ApproximatelyDuring the first nine months of 2015, the Company acquired over 5 million shares of treasury stock at a cash cost of $240 million. Nearly $1.6 billion of cash was used to acquire nearlyapproximately 25 million shares of treasury stock during the first nine months 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 $350had $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 as of September 30,at December 31, 2014 that was approximately 26 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. Duringrepaid during 2015. In 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. Additionally, the Companymaturities and, in July 2014, spentmade an early redemption of senior notes at a cash cost of $253 million, which included a make-whole premium plus accrued interest, to redeem early $250 million principal amount of 1.6% Senior Notes.

Also, in July 2014, OneSubsea paid a dividend of €75 million with Cameron's non-U.S. partnership receiving €45 million and Schlumberger receiving €30 million (approximately $40 million).million.

Future liquidity requirements

At September 30, 2014,2015, the Company had nearly $1.2$1.9 billion of cash, cash equivalents and short-term investments. Approximately $479$591 million of the Company'sCompany’s cash, cash equivalents and short-term investments at September 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 unanimous approval of the OneSubsea Board of Directors prior to payment. The venture partners made a combined cash contribution to OneSubsea totaling $50 million in June 2015.
Of the remaining cash, cash equivalents and short-term investments not held byin the OneSubsea $184venture, $677 million was located in the United States.

Total debt at September 30, 20142015 was nearly $3.2approximately $2.8 billion, most of which was in the United States. Excluding capital leases, approximately $890$976 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 20182021 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 approximately 4% fromat September 30, 2015 has declined $2.3 billion, or 22%, since December 31, 2013, mainly due2014 to the cancellation of a large drilling project award in the first quarter of 2014 totaling nearly $243 million, as well as weakness in current year-to-date order rates.  Ordersapproximately $7.2 billion at September 30, 2015. Additionally, orders during the first nine months of 20142015 were down nearly 14%approximately 32% from the same period in 2013 due mainly to certain large subsea project awards received in the first nine months of 2013 that did not repeat during the first nine months 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 2014 and 2013 average rig count and commodity price levels first nine months of 2015 and 2014 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 third quarter and year-to-date orders and September 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

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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 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 September 30, 2015, no letters of credit had been issued under the 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 approximately $425used for letters of credit. The Company has issued letters of credit totaling $36 million under the Revolving Credit Facility, leaving $714 million available for 2014, down from $520 million during 2013.future use at September 30, 2015.

TheDespite current market conditions, the Company believes, based on its current financial condition, existing backlog levels which are still at historically high 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 facility 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. At September 30, 2014, no amounts had been borrowed under the $835 million facility. The Company had issued letters of credit totaling $72 million under the new $750 million Revolving Credit Facility and $25 million under the $40 million bi-lateral facility, leaving $678 million and $15 million, respectively, available for future use. The Company also believes, based on its existing current credit standing, that it will be able to continue to refinance existing debt upon maturity, if desired.
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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 $3.8 billion since inception. At September 30, 2014, the Company had remaining authority for future stock purchases totaling approximately $665 million.

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 application of the discounted cash flow models, including, but not limited to, estimates of future cash flows and the selection of a discount rate.

As described further in Note 29 of the Notes to Consolidated Condensed Financial Statements, effective June 1, 2014,and any future credit facilities 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 in connection with the Company's annual goodwill impairment review conducted during the first quarter of 2014. As a result of this review, the PSE goodwill amount, totaling approximately $40 million, was fully impaired at that time.may enter into.

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'sCompany’s sales and profitability.

Demand for most of the Company'sCompany’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, orand could result in the cancellation, modification or rescheduling of existing orders. As examples,For example, oil prices began declining during the third quarter of 2014 and have continued to decline into the low-to-mid $80 range on the New York Mercantile Exchange during the first halfnine months of October2015. Average daily prices for West Texas Intermediate and Brent crude during the first nine months of 2015 were each down more than 40% from the first nine months of 2014. ThisSimilarly, natural gas prices declined from an average of $4.55 per MMBtu during the first nine months of 2014 to $2.77 per MMBtu for the first nine months of 2015. These declines in commodity prices began to impact the average number of working rigs which began declining in late 2014 and continued to decline if continuing, couldduring the first nine months of 2015. Globally, the average rig count for the first nine months of 2015 was down 32% from the first nine months of 2014, with even steeper declines occurring in the United States and Canada. These market conditions negatively affected our third quarter and year-to-date 2015 results and are expected to continue to significantly affect future exploration and production activity levels and, therefore, demand for the Company'sCompany’s products and services. Additionally, natural gas spot prices in the United States declined duringservices, as well as our customers' ability to pay. During the first halfnine months of 20122015 there have been numerous deepwater projects deferred and deepwater rigs idled. Efforts are also being made by drilling contractors to less than $2 per MMBtu,defer deliveries of new deepwater rigs currently under construction. In addition to a decline in future orders and revenues, the lowest level in the last decade. Although natural gas prices have subsequently increased, current rig countCompany expects to incur additional costs as it continues to adjust, as necessary, its commercial, manufacturing and support operations 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.meet expected future customer demand. See also the discussion in "Market Conditions" above.“Market Conditions” above for the third quarter of 2015 as compared to the third 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.
Cameron will be subject to business uncertainties and certain operating restrictions until completion of the merger with Schlumberger.

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In connection with the pending merger with Schlumberger, some of the suppliers and customers of Cameron may delay or defer sales and purchasing decisions, which could negatively impact revenues, earnings and cash flows regardless of whether the merger is completed. Additionally, Cameron has agreed in the merger agreement to refrain from taking certain actions with respect to our business and financial affairs during the pendency of the merger, which restrictions could be in place for an extended period of time if completion of the merger is delayed and could adversely impact Cameron’s ability to execute certain of our business strategies and their financial condition, results of operations or cash flows.
Cameron may be unable to attract and retain key employees during the pendency of the merger.

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Cameron may experienceuncertainty about their future roles with the combined company following the merger, which may materially adversely affect the ability of Cameron to attract and retain key personnel during the pendency of the merger. Key employees may depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company following the merger. Accordingly, no assurance can be given that Cameron will be able to attract and retain key employees to the same extent that Cameron has been able to in the past.

Failure to complete the merger with Schlumberger could negatively impact Cameron.

If the pending merger with Schlumberger is not completed, the ongoing businesses and the market price of the common stock of Cameron may be adversely affected and Cameron will be subject to several risks, including Cameron being required, under certain circumstances, to pay Schlumberger US a termination fee of $321 million; Cameron having to pay certain costs relating to the merger; and diverting the focus of Cameron management from pursuing other opportunities that could be beneficial to Cameron, in each case, without realizing any of the benefits which might have resulted had the pending merger been completed.
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 September 30, 2014, the Company's backlog was approximately $10.6 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 of delivery of product currently in backlog. Failure to deliver equipment in accordance with expectations could negatively impact the market price performance
Portions of the Company's common stockbacklog for our Subsea and other publicly-traded financial instruments.Drilling segments are subject to heightened execution risk.

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 available to customersCameron is involved in oil and gas drilling activities. These acquisitions brought large drilling rig construction projects not previously offered and a record backlog at that time. As a result of both, the complexity of execution within this business has increased from that of the past. Also, the Company had previously struggled to increase production capacity to deliver this backlog.

Large drilling rig projects are accounted for using accounting rules for production-type and construction-type contracts. In accordanceprovide customers 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 drillingdeepwater stacks and associated equipment to customers, (ii) are larger in financial scopecomplete drilling packages for jackup rigs 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.

Cameron, 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 $3.2 billion for subsea systems projectsits total backlog at September 30, 2014.2015, the Company’s Drilling segment had projects fitting this risk profile that amounted to approximately $741 million. As a subset of its total backlog at September 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, the Company'sCompany’s earnings or liquidity could be negatively impacted. 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 5.7%9% and 14%, respectively, of total revenues infor the first nine months of 2014.2015.

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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.Company’s process systems and compression businesses. Since then, other businesses and business functions have been migrated in stages. Effective October 1, 2014,As of September 30, 2015, nearly all businesses within the V&M segment, the Surface Systems division,segment, the Company'sDrilling segment, the Company’s worldwide engineering and human resource functions, as well as other corporate office activities are now operating inon the upgraded system. The Drilling Systems divisionOneSubsea business is scheduled to be migrated in 2015 and OneSubseabegin using the upgraded system in 2016. The Drilling Systems divisionsegment and the 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 to the Company'sCompany’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

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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 1415 of the Notes to Consolidated Condensed Financial Statements.
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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 poses 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 September 30, 2014, approximately 1% of the Company's backlog from continuing operations related to future deliveries to customers doing business in Russia. For the nine months ended September 30, 2014, customer sales by the Company's continuing operations into Russia totaled less than 1% of the Company's sales during that 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;
• 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
• 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's in-country investments and on-going business activities supporting Iraq's oil and gas production infrastructure. At September 30, 2014, less than 1% of the Company's backlog related to future deliveries to customers doing business in Iraq. Additionally, less than 1% of the Company's property, plant and equipment were located in 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 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.
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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 various manufacturing and aftermarket operations in Venezuela that contributed $54 million in revenuesgovernment of Angola devalued its currency during the first nine months of 2014. The economy2015, resulting in Venezuela is highly inflationary.   As a result, the Company's operations in Venezuela are accounted for as U.S. dollar functional currency entities andloss of $9 million being recorded by the Company considerson its earnings in Venezuela to be permanently reinvested. Since the 2013 devaluation of the Venezuelan bolivar, 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. During 2014, the Venezuelan government began using other auction rates (SICAD rates) for activities involving the exchange of bolivars and dollars. At September 30, 2014, the published SICAD I rate was 12.0 bolivars to the U.S. dollar and the published SICAD II rate was approximately 49.99 bolivars to the U.S. dollar. The Company does not currently expect a material loss or a material decline in operating cash flows to occur should these expanded auction rates result in a change in the payment practices of its primary customer or in a further devaluation of the Venezuelan currency. These factors however, along with recent civil unrest, create political and economic uncertainty with regard to their impact on the Company's continued operations in this country.

kwanza-denominated net assets.
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.

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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 4% of the Company’s consolidated revenues during the first nine months of 2015, and 5% the first nine 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.
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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

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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.
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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 1314 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.

39
Table of Contents

Item 3. Quantitative and Qualitative Disclosures about Market Risk
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.

39
TableIn order to mitigate the effect of Contents

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 September 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 September 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:
Euro 65
69
37
171
(23 ) (10 ) —
—
(33 )
Malaysian ringgit 143
76
—
219
(16 ) —
—
—
(16 )
Norwegian krone 187
598
32
817
(51 ) (74 ) (4 ) —
(129 )
Pound Sterling 94
22
2
118
(5 ) (1 ) —
—
(6 )
U.S. dollar 16
44
4
64
(282 ) (327 ) (101 ) (1 ) (711 )

40
Table of Contents

Item 4. Controls and Procedures
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 September 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 September 30, 2014.2015.

41
Table of Contents

PART II — OTHER INFORMATION
Item 1. Legal Proceedings
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 September 30, 2014,2015, the Company'sCompany’s Consolidated Condensed Balance Sheet included a liability of approximately $17$20 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. Risk Factors
Item 1A. Risk Factors
The information set forth under the caption "Factors“Factors That May Affect Financial Condition and Future Results"Results” on pages 3334 – 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 $3.8 billion since inception. At September 30, 2014,2015, the Company had remaining authority for future stock purchases totaling approximately $665$240 million.

40
Table However, such stock purchases are currently prohibited under the Merger Agreement (see Note 2 of Contents
the Notes to Consolidated Condensed Financial Statements for further information).
Shares of common stock purchased and placed in treasury during the ninethree months ended September 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⁾
7/1/14 – 7/31/14 349,754 $ 68.64 47,440,948 6,093,280
8/1/14 – 8/31/14 2,110,618 $ 72.44 49,551,566 11,290,042
9/1/14 – 9/30/14 2,454,672 $ 70.97 52,006,238 10,017,866
Total 4,915,044 $ 71.43 52,006,238 10,017,866

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⁾
7/1/15 – 7/30/15 803,700
$ 49.51
60,416,849
4,853,308
8/1/15 – 8/31/15 101,400
$ 49.31
60,518,249
3,676,599
9/1/15 – 9/30/15 —
$ —
60,518,249
3,912,232
Total 905,100
$ 49.48
60,518,249
3,912,232
⁽¹⁾ Based upon month-end stock price. At September 30, 2014,2015, the closing stock price was $66.38$61.32 per share.

Item 3. Defaults Upon Senior Securities

Item 3. Defaults Upon Senior Securities
None

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

Item 5. Other Information
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.

42
Table of Contents

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.

41
Table of Contents

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–

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

4243
Table of Contents

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: October 23, 201422, 2015 CAMERON INTERNATIONAL CORPORATION
(Registrant)

By: /s/ Charles M. Sledge
Charles M. Sledge
Charles M. Sledge
Senior Vice President and Chief Financial Officer
and authorized to sign on behalf of the Registrant

4344
Table of Contents

EXHIBIT INDEX

Exhibit Number Description

31.1 Certification
31.2
31.1 Certification
32.1
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

45

44}



(Mark One)
Rþ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended September 30, ~~2014~~2015
OR
£o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

Balance December 31, 2013		Net warranty provisions		Charges against accrual			Discontinued operations			Translation and other		Balance September 30, 2014

$	46	$	34	$	(24	)	$	(10	)	$	–	$	46

	September 30, 2014			December 31, 2013

Commercial paper (0.32% weighted average rate)	$	350		$	–
Senior notes:
Floating rate notes due June 2, 2014		–			250
1.6% notes due April 30, 2015		–			250
1.15% notes due December 15, 2016		250			250
1.4% 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		61			57
Obligations under capital leases		58			60
		3,212			2,860
Current maturities		(403	)		(297	)
Long-term maturities	$	2,809		$	2,563

	September 30, 2014				December 31, 2013
	Assets		Liabilities		Assets		Liabilities

Derivatives designated as hedging instruments:
Current	$	6	$	34	$	28	$	10
Non-current		1		6		3		2
Total derivatives designated as hedging instruments		7		40		31		12

Derivatives not designated as hedging instruments:
Current		3		13		6		6
Non-current		–		–		–		–
Total derivatives not designated as hedging instruments		3		13		6		6

Total derivatives	$	10	$	53	$	37	$	18

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013

Derivatives designated as hedging instruments -
Cost of sales	$	(4	)	$	3		$	(3	)	$	2

Derivatives not designated as hedging instruments -
Cost of sales		(6	)		7			(4	)		3
Other costs		(4	)		(1	)		(4	)		(1	)
	$	(14	)	$	9		$	(11	)	$	4

	Three Months Ended September 30,						Increase (Decrease)
($ in millions)	2014			2013			$			%

Revenues	$	1,975		$	1,637		$	338		20.6	%
Income from continuing operations before income taxes	$	295		$	216		$	79		36.6	%
Income from continuing operations before income taxes as a percent of revenues		14.9	%		13.2	%		N/A		1.7	%

Orders	$	1,874		$	2,205		$	(331	)	(15.0	)%
Backlog (at period-end)	$	8,996		$	9,162		$	(166	)	(1.8	)%

	Three Months Ended September 30,						Increase/(Decrease)
($ in millions)	2014			2013			$			%

Revenues	$	552		$	502		$	50		10.0	%
Income from continuing operations before income taxes	$	103		$	98		$	5		5.1	%
Income from continuing operations before income taxes as a percent of revenues		18.7	%		19.5	%		N/A		(0.8	)%

Orders	$	529		$	497		$	32		6.4	%
Backlog (at period-end)	$	954		$	1,058		$	(104	)	(9.8	)%

	Nine Months Ended September 30,				Increase
	2014		2013		Amount		%
Drilling activity (average number of working rigs during period)⁽¹⁾:
United States		1,845		1,763		82		4.7	%
Canada		371		347		24		6.9	%
Rest of world		1,344		1,288		56		4.3	%
Global average rig count		3,560		3,398		162		4.8	%

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	$	99.77	$	98.17	$	1.60		1.6	%
Henry Hub natural gas spot price per MMBtu in U.S. dollars	$	4.57	$	3.70	$	0.87		23.5	%


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

•	~~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
•	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.

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⁾
7/1/14 – 7/31/14		349,754	$	68.64		47,440,948		6,093,280
8/1/14 – 8/31/14		2,110,618	$	72.44		49,551,566		11,290,042
9/1/14 – 9/30/14		2,454,672	$	70.97		52,006,238		10,017,866
Total		4,915,044	$	71.43		52,006,238		10,017,866


⁽¹⁾	Based upon month-end stock price. At September 30, ~~2014,~~2015, the closing stock price was ~~$66.38~~$61.32 per share.


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


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



Date: October ~~23, 2014~~22, 2015	CAMERON INTERNATIONAL CORPORATION
	(Registrant)

	By:	/s/ ~~Charles M. Sledge~~
	Charles M. Sledge
		Charles M. Sledge
		Senior Vice President and Chief Financial Officer and authorized to sign on behalf of the Registrant



Exhibit Number		Description

~~31.1~~	~~Certification~~
~~31.2~~ 31.1		Certification
~~32.1~~
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