UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549



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

Commission File Number 1-13884

Cameron International Corporation

(Exact Name of Registrant as Specified in its Charter)



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

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

713/513-3300

(Registrant’s Telephone Number, Including Area Code)

N/A

(Former Name, Former Address and Former Fiscal Year, if Changed Since 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 accelerated filer”, “accelerated filer” and “smaller reporting 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 common stock as of ~~July~~October 15, 2015 was ~~191,514,291.~~

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 Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40

Item 4.	Controls and Procedures	41

PART II — OTHER INFORMATION		42

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	42

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

Item 3.	Defaults Upon Senior Securities	42

Item 4.	Mine Safety Disclosures	42

Item 5.	Other Information	43 42

Item 6.	Exhibits	43

SIGNATURES		44

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Cameron International Corporation

Consolidated Condensed Statements of Comprehensive Income

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

Three Months Ended
June 30,

Six Months Ended
June 30,

2015 2014 2015 2014
(unaudited)

REVENUES $ 2,222 $ 2,570 $ 4,495 $ 4,899
COSTS AND EXPENSES:
Cost of sales (exclusive of depreciation and amortization shown separately below) 1,585 1,850
3,193
3,540
Selling and administrative expenses 279 333 565 651
Depreciation and amortization 89 88 178 173
Interest, net 33 30 71 62
Other costs (gains), net (see Note 3) 37 (6 ) 614 43
Total costs and expenses 2,023 2,295 4,621 4,469

Income (loss) from continuing operations before income taxes 199 275 (126 ) 430
Income tax provision (47 ) (65 ) (100 ) (110 )
Income (loss) from continuing operations 152 210 (226 ) 320
Income from discontinued operations, net of income taxes 3 23 432 28
Net income 155 233 206 348

Less: Net income attributable to noncontrolling interests 15 12 17 16
Net income attributable to Cameron stockholders $ 140 $ 221 $ 189 $ 332

Amounts attributable to Cameron stockholders:
Income (loss) from continuing operations $ 137 $ 198 $ (243 ) $ 304
Income from discontinued operations 3 23 432 28
Net income attributable to Cameron stockholders $ 140 $ 221 $ 189 $ 332

Earnings (loss) per common share attributable to Cameron stockholders:
Basic -
Continuing operations $ 0.71 $ 0.97 $ (1.27 ) $ 1.46
Discontinued operations 0.02 0.11 2.25 0.13
Basic earnings per share $ 0.73 $ 1.08 $ 0.98 $ 1.59

Diluted -
Continuing operations $ 0.71 $ 0.97 $ (1.27 ) $ 1.44
Discontinued operations 0.02 0.11 2.25 0.13
Diluted earnings per share $ 0.73 $ 1.08 $ 0.98 $ 1.57
Shares used in computing earnings per common share:
Basic 191 204 192 209
Diluted 192 205 192 211

Comprehensive income $ 261 $ 218 $ 22 $ 359
Less: Comprehensive income (loss) attributable to noncontrolling interests 49 4 (14 ) 23
Comprehensive income attributable to Cameron stockholders $ 212 $ 214 $ 36 $ 336



	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.

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Cameron International Corporation

Consolidated Condensed Balance Sheets

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

June 30,
2015

December 31,
2014

(unaudited)
ASSETS
Cash and cash equivalents $ 1,295 $ 1,513
Short-term investments 436 113
Receivables, net 2,096 2,389
Inventories, net 2,938 2,929
Other current assets 390 391
Assets of discontinued operations – 217
Total current assets 7,155 7,552
Plant and equipment, net 1,814 1,964
Goodwill 1,880 2,461
Intangibles, net 683 728
Other assets 200 187
TOTAL ASSETS $ 11,732 $ 12,892

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt $ 31 $ 263
Accounts payable and accrued liabilities 2,933 3,748
Accrued income taxes 298 168
Liabilities of discontinued operations – 90
Total current liabilities 3,262 4,269
Long-term debt 2,813 2,819
Deferred income taxes 180 193
Other long-term liabilities 167 167
Total liabilities 6,422 7,448
Stockholders’ Equity:
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at June 30, 2015 and December 31, 2014 3 3
Capital in excess of par value 3,242 3,255
Retained earnings 5,820 5,631
Accumulated other elements of comprehensive income (loss) (693 ) (540 )
Less: Treasury stock, 71,671,246 shares at June 30, 2015 (68,139,027 shares at December 31, 2014) (3,955 ) (3,794 )
Total Cameron stockholders’ equity 4,417 4,555
Noncontrolling interests 893 889
Total equity 5,310 5,444
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 11,732 $ 12,892



	September 30, 2015			December 31, 2014
	(unaudited)
ASSETS
Cash and cash equivalents	$	1,627		$	1,513
Short-term investments	321			113
Receivables, net	2,088			2,389
Inventories, net	2,659			2,929
Other current assets	481			391
Assets of discontinued operations	—			217
Total current assets	7,176			7,552
Plant and equipment, net	1,733			1,964
Goodwill	1,796			2,461
Intangibles, net	613			728
Other assets	291			187
TOTAL ASSETS	$	11,609		$	12,892

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt	$	38		$	263
Accounts payable and accrued liabilities	2,786			3,748
Accrued income taxes	342			168
Liabilities of discontinued operations	—			90
Total current liabilities	3,166			4,269
Long-term debt	2,794			2,819
Deferred income taxes	227			193
Other long-term liabilities	162			167
Total liabilities	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, 2015 and December 31, 2014	3			3
Capital in excess of par value	3,253			3,255
Retained earnings	6,007			5,631
Accumulated other elements of comprehensive income (loss)	(847		)	(540		)
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	831			889
Total equity	5,260			5,444
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	11,609		$	12,892

The accompanying notes are an integral part of these statements.

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Cameron International Corporation

Consolidated Condensed Statements of Cash Flows

(dollars in millions)

Three Months Ended
June 30,

Six Months Ended
June 30,

2015 2014 2015 2014
(unaudited)

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



	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.

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Cameron International Corporation

Consolidated Condensed Statement of Changes in Equity

(dollars in millions)

Cameron Stockholders
Common Stock Capital in Excess of Par Value Retained Earnings
Accumulated Other
Elements of Comprehensive Income (Loss)
Treasury Stock Noncontrolling Interests
(Unaudited)

Balance at December 31, 2014 $ 3 $ 3,255 $ 5,631 $ (540 ) $ (3,794 ) $ 889
Net income – – 189 – – 17
Other comprehensive income (loss), net of tax – – – (153 ) – (31 )
Non-cash stock compensation expense – 23 – – – –
Purchase of treasury stock – – – – (191 ) –
Treasury stock issued under stock compensation plans – (35 ) – – 30 –
Tax benefit of stock compensation plan transactions – (1 ) – – – –
Contributions from noncontrolling interest owners – – – – – 18
Balance at June 30, 2015 $ 3 $ 3,242 $ 5,820 $ (693 ) $ (3,955 ) $ 893



	Cameron Stockholders
	Common Stock		Capital in Excess of Par Value			Retained Earnings		Accumulated Other Elements of Comprehensive Income (Loss)			Treasury Stock			Noncontrolling Interests
	(Unaudited)

Balance at December 31, 2014	$	3	$	3,255		$	5,631	$	(540	)	$	(3,794	)	$	889
Net income	—		—			376		—			—			43
Other comprehensive income (loss), net of tax	—		—			—		(307		)	—			(98		)
Non-cash stock compensation expense	—		35			—		—			—			—
Purchase of treasury stock	—		—			—		—			(236		)	—
Treasury stock issued under stock compensation plans	—		(38		)	—		—			43			—
Tax benefit of stock compensation plan transactions	—		1			—		—			—			—
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

Notes to Consolidated Condensed Financial Statements

Unaudited

Note 1: Basis of Presentation

The accompanying Unaudited Consolidated Condensed Financial Statements of Cameron International Corporation (the Company) have been prepared in accordance with Rule 10-01 of Regulation S-X and do not include all the information and footnotes required by U.S. generally accepted accounting principles for complete financial statements. Those adjustments, consisting of normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the financial information for the interim periods, have been made. The results of operations for such interim periods are not necessarily indicative of the results of operations for a full year. The Unaudited Consolidated Condensed Financial Statements should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto filed by the Company on Form 10-K for the year ended December 31, 2014.

Preparation of the financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include, but are not limited to, estimates of total contract profit or loss on certain long-term production contracts, estimated losses on accounts receivable, estimated realizable value on excess and obsolete inventory, contingencies (including tax contingencies, estimated liabilities for litigation exposures and liquidated damages), estimated warranty costs, estimates related to pension accounting, estimates 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 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

The Company completed the sale of its Reciprocating Compression business to General Electric, effective June 1, 2014, and the sale of its Centrifugal Compression business to Ingersoll Rand on January 1, 2015. The gross cash consideration from the sale of 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
June 30,

Six Months Ended
June 30,

(dollars in millions) 2015 2014 2015 2014

Revenues $ – $ 134 $ – $ 284
Cost of sales (excluding depreciation and amortization) – (93 ) – (203 )
All other (costs) gains⁽¹⁾
4 (25 ) (1 ) (58 )
Gain on sale of Compression businesses, before tax – 95 681 95

Income before income taxes 4 111 680 118
Income tax provision (1 ) (88 ) (248 ) (90 )
Income from discontinued operations, net of income taxes $ 3 $ 23 $ 432 $ 28

⁽¹⁾

~~– Includes post-closing adjustments during the three months ended June 30, 2015.~~

~~Table of Contents~~



	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 business was impacted by nondeductible goodwill of approximately $192 million included in the total net assets sold.

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Note 3:4: Asset Charges and Other Costs (Gains), Net

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

Three Months Ended
June 30,

Six Months Ended
June 30,

(dollars in millions) 2015 2014 2015 2014

Asset charges -
Goodwill impairment $ – $ – $ 517 $ 40
Other long-lived asset impairments – 4 36 4
Accelerated depreciation on underutilized assets 10 – 10 –
Total $ 10 $ 4 $ 563 $ 44

Other costs (gains) -
Facility closures and severance 17 3 33 8
Mark-to-market impact on currency derivatives not designated as accounting hedges (1 ) – 11 –
Gain from Venezuela currency devaluation – – (4 ) –
Gain from remeasurement of prior interest in equity method investment – (8 ) – (8 )
Loss from Angola currency devaluation 9 – 9 –
All other costs, net 2 (5 ) 2 (1 )
Total 27 (10 ) 51 (1 )
Total other costs (gains),net $ 37 $ (6 ) $ 614 $ (43 )



	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 ~~impairment~~ 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 ~~June~~September 30, 2015 of ~~$53~~$52 million.

~~Table~~During the first quarter of ~~Contents~~

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

test.

The Company also recognized impairment charges of ~~$36~~$54 million during the ~~six~~nine months ended ~~June~~September 30, 2015 relating to certain underutilized facilities resulting from weak market ~~conditions.~~conditions and the write-down of assets retained in the 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 ~~six~~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 & 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 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 impact on the Company’s operations, charges of ~~$43~~$53 million were recognized during the ~~six~~nine months ended ~~June~~September 30, 2015 related to the impact of ~~pending facility closures~~, accelerated depreciation on underutilized assets, pending facility closures and severance for workforce reductions.

~~Gain from Venezuela currency devaluation~~

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

~~Gain from remeasurement of prior interest in equity method investment~~

facilitate Cameron's merger with Schlumberger.

In May 2014, the Company increased its prior ownership interest in Cameron Services Middle East LLC from 49% to 90%, for approximately $18 million. The Company recognized a pre-tax gain of nearly $8 million as a result of remeasuring its prior interest, which had been accounted for under the equity method, to fair value upon obtaining control of this ~~entity during the second quarter of 2014.~~entity.

Note 4:5: Receivables

Receivables consisted of the following:

(dollars in millions)
June 30,
2015

December 31,
2014

Trade receivables $ 1,359 $ 1,678
Costs and estimated earnings in excess of billings on uncompleted contracts 632 621
Other receivables 150 122
Allowance for doubtful accounts (45 ) (32 )
Total receivables $ 2,096 $ 2,389



(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:

(dollars in millions)
June 30,
2015

December 31,
2014

Raw materials $ 153 $ 159
Work-in-process 786 827
Finished goods, including parts and subassemblies 2,226 2,150
Other 23 24
Total gross inventories 3,188 3,160
Excess of current standard costs over LIFO costs (73 ) (86 )
Allowances (177 ) (145 )
Total net inventories $ 2,938 $ 2,929



(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

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Note 6:7: Plant and Equipment and Goodwill

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

(dollars in millions)
June 30,
2015

December 31,
2014

Plant and equipment, at cost $ 3,523 $ 3,580
Accumulated depreciation (1,709 ) (1,616 )
Total plant and equipment $ 1,814 $ 1,964



(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 the ~~six~~nine months ended ~~June~~September 30, ~~2014~~2015 were as follows (dollars in millions):

Balance at December 31, 2014 $ 2,461
Impairment of goodwill (Note 3) (517 )
Adjustments to the purchase price allocation for prior year acquisitions (12 )
Translation effect of currency changes and other (52 )
Balance at June 30, 2015 $ 1,880



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

Note 7:8: Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following:



(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

(dollars in millions)
June 30,
2015

December 31,
2014

Trade accounts payable and accruals $ 520 $ 1,084
Advances from customers 1,352 1,576
Other accruals 1,061 1,088
Total accounts payable and accrued liabilities $ 2,933 $ 3,748

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Note 8:9: Debt

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

(dollars in millions)
June 30,
2015

December 31,
2014

Commercial paper (0.49% weighted average rate at December 31, 2014) $ – $ 201
Senior notes:
1.15% notes due December 15, 2016 250 250
1.40% notes due June 15, 2017 250 250
6.375% notes due July 15, 2018 450 450
4.5% notes due June 1, 2021 250 250
3.6% notes due April 30, 2022 250 250
4.0% notes due December 15, 2023 250 250
3.7% notes due June 15, 2024 250 250
7.0% notes due July 15, 2038 300 300
5.95% notes due June 1, 2041 250 250
5.125% notes due December 15, 2043 250 250
Unamortized original issue discount (7 ) (7 )
Other debt 35 67
Obligations under capital leases 66 71
2,844 3,082
Current maturities (31 ) (263 )
Long-term maturities $ 2,813 $ 2,819

~~Table of Contents~~



(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

The Company has in place a commercial paper program for general corporate purposes which allows for issuances of up to $500 million of commercial paper with maturities of no more than 364 days. ~~This program is used for general corporate purposes.~~

Credit agreements and revolving credit facilities

In order to extend the length of its currently available credit facilities, the Company, including certain of its subsidiaries, entered into an amended and restated multi-currency credit agreement (the “Credit Agreement”) with various banks and other financial institutions on May 14, 2015. The 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, including acquisitions, capital expenditures, repurchases of common stock, repayment of debt and issuances of letters of credit. At ~~June~~September 30, 2015, no letters of credit had been issued under the Credit Agreement, leaving $750 million 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 facility may be used for letters of credit. The Company has issued letters of credit totaling ~~$44~~$36 million under the Revolving Credit Facility, leaving ~~$706~~$714 million available for future use at ~~June~~September 30, 2015.

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Note 9:10: Income Taxes

The Company’s effective income tax rate on income from continuing operations for the first ~~six~~nine months of 2015 was ~~a negative 79.2%~~109.1% as compared to ~~25.2%~~24.4% for the first ~~six~~nine months of 2014. The components of the effective tax rates for both periods were as follows:

Six Month Ended June 30,
2015 2014
(dollars in millions) Tax Provision Tax Rate Tax Provision Tax Rate

Provision (benefit) based on international income (loss) distribution $ (29 ) 23.0 % $ 101 23.5 %
Adjustments to income tax provision:
Asset impairments with no tax benefit 127 (100.5 ) 10 2.2
Other asset impairments (1 ) 0.9 – –
Finalization of prior year returns 2 (2.0 ) 2 0.4
Changes in valuation allowances 1 (0.6 ) 1 0.1
Accrual adjustments and other – – (4 ) (1.0 )
Tax provision $ 100 (79.2 )% $ 110 25.2 %



	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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Note ~~10:~~11: Business Segments

The Company’s operations are organized into four separate business segments – Subsea, Surface, Drilling and Valves and Measurement (V&M). Summary financial data by segment follows:

Three Months Ended
June 30,

Six Month Ended
June 30,

(dollars in millions) 2015 2014 2015 2014
Revenues:
Subsea $ 658 $ 735 $ 1,289 $ 1,416
Surface 510 613 1,053 1,151
Drilling 719 766 1,445 1,433
   V&M 381 539 809 1,039
Elimination of intersegment revenues (46 ) (83 ) (101 ) (140 )
Total revenues $ 2,222 $ 2,570 $ 4,495 $ 4,899

Segment income before interest and income taxes:
Subsea $ 67 $ 46 $ 124 $ 75
Surface 69 108 161 199
Drilling 119 97 254 164
   V&M 44 110 89 208
Elimination of intersegment earning (7 ) (24 ) (23 ) (36 )
Segment income before interest and income taxes 292 337 605 610

Corporate items:
Corporate expenses (23 ) (38 ) (46 ) (75 )
Interest, net (33 ) (30 ) (71 ) (62 )
Other (costs) gains, net (see Note 3)
(37 ) 6 (614 ) (43 )
Income (loss) from continuing operations before income taxes $ 199 $ 275 $ (126 ) $ 430



	Three Months Ended 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 items include governance expenses associated with the Company’s corporate office, as well as all of the 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 corporate items because cash equivalents, short-term investments and debt, including location, type, currency, etc., are managed on a worldwide basis by the corporate treasury department.

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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):

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Three Months Ended
June 30,

Six Months Ended
June 30,

(dollars and shares in millions, except per share amounts) 2015 2014 2015 2014

Net income (loss) from continuing operations $ 152 $ 210 $ (226 ) $ 320
Less: Net income attributable to noncontrolling interests
15 12 17 16
Net income (loss) from continuing operations attributable to Cameron 137 198 (243 ) 304
Income from discontinued operations, net of taxes 3 23 432 28
Net income attributable to Cameron $ 140 $ 221 $ 189 $ 332

Average shares outstanding (basic) 191 204 192 209
Common stock equivalents 1 1 – 2
Diluted shares 192 205 192 211

Basic earnings (loss) per share:
Continuing operations $ 0.71 $ 0.97 $ (1.27 ) $ 1.46
Discontinued operations 0.02 0.11 2.25 0.13
Basic earnings per share $ 0.73 $ 1.08 $ 0.98 $ 1.59

Diluted earnings (loss) per share:
Continuing operations $ 0.71 $ 0.97 $ (1.27 ) $ 1.44
Discontinued operations 0.02 0.11 2.25 0.13
Diluted earnings per share $ 0.73 $ 1.08 $ 0.98 $ 1.57



	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 treasury shares were as follows:

Three Months Ended
June 30,

Six Months Ended
June 30,

2015 2014 2015 2014

Treasury shares at beginning of period 71,543,192 56,109,636 68,139,027 41,683,164
Purchases of treasury shares 278,700 4,516,668 4,225,234 19,673,771
Net change in treasury shares owned by participants in nonqualified deferred compensation plans (599 ) (1,614 ) (732 ) 38,148
Treasury shares issued in satisfaction of stock option exercises and vesting of restricted stock units (150,047 ) (597,340 ) (692,283 ) (1,367,733 )
Treasury shares at end of period 71,671,246 60,027,350 71,671,246 60,027,350
Average cost per share $ 46.35 $ 63.00 $ 45.38 $ 61.37



	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

At ~~June~~September 30, 2015, the Company had remaining authority for future stock purchases totaling approximately ~~$285~~$240 million.

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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 ~~June~~September 30, 2015 and 2014 were as follows:

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Three Months Ended June 30, 2015
(dollars in millions)
Accumulated Foreign Currency Translation
Gain (Loss)
Prior Service Credits and Net Actuarial Losses Accumulated Gain (Loss) on Cash Flow Hedge Derivatives Total Three Months Ended June 30, 2014

Balance at beginning of period $ (625 ) $ (78 ) $ (62 ) $ (765 ) $ (69 )

Other comprehensive income (loss) before reclassifications:
Pre-tax 50 – 15 65 (6 )
Tax effect – – (12 ) (12 ) 1

Amounts reclassified from accumulated other comprehensive income to:
Revenues – – 18 18 (2 )
Cost of sales – – 9 9 (2 )
Tax effect – – (8 ) (8 ) 2
Net current period other comprehensive income (loss) 50 – 22 72 (7 )
Balance at end of period $ (575 ) $ (78 ) $ (40 ) $ (693 ) $ (76 )



	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 ~~six~~nine months ended ~~June~~September 30, 2015 and 2014 were as follows:

Six Months Ended June 30, 2015
(dollars in millions)
Accumulated Foreign Currency Translation
Gain (Loss)
Prior Service Credits and Net Actuarial Losses Accumulated Gain (Loss) on Cash Flow Hedge Derivatives Total Six Months Ended June 30, 2014

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

Other comprehensive income (loss) before reclassifications:
Pre-tax (147 ) – (43 ) (190 ) 10
Tax effect – – 4 4 (2 )

Amounts reclassified from accumulated other comprehensive income to:
Revenues – – 29 29 (5 )
Cost of sales – – 17 17 (2 )
Tax effect – – (13 ) (13 ) 3
Net current period other comprehensive income (loss) (147 ) – (6 ) (153 ) 4
Balance at end of period $ (575 ) $ (78 ) $ (40 ) $ (693 ) $ (76 )



	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	(302		)	—			(61		)	(363		)	(157		)
Tax effect	—			—			12			12			10

Amounts reclassified from accumulated other comprehensive income to:
Revenues	—			—			38			38			(7		)
Cost of sales	—			—			25			25			(1		)
Tax effect	—			—			(19		)	(19		)	3
Net current period other comprehensive income (loss)	(302		)	—			(5		)	(307		)	(152		)
Balance at end of period	$	(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 ~~June~~September 30, 2015, the Company’s Consolidated Condensed Balance Sheet included a liability of approximately ~~$18~~$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 ~~nearly~~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, 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 interpretation of the tax laws and regulations, the Company could be exposed to additional taxes.

The Company has been assessed customs duties and penalties by the government of Brazil following a customs audit for the years 2003-2010 totaling a U.S. dollar equivalent of ~~almost $42~~approximately $34 million at ~~June~~September 30, 2015, including interest accrued at local country ~~rates, following a customs audit for the years 2003-2010.~~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 ~~June~~September 30, 2015 as no loss is 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. In 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 of the underground water contamination and its public disclosure on property values led to a number of claims by homeowners. The Company settled these claims, primarily through the settlement of a class action lawsuit 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 ~~June~~September 30, 2015.

~~Table of Contents~~

Additionally, the Company has 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 ~~June~~September 30, 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 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.

Following is a summary of the Company’s financial instruments which have been valued at fair value in the Company’s Consolidated Balance Sheets at ~~June~~September 30, 2015 and December 31, 2014:

Fair Value Based on Quoted Prices in Active Markets for Identical Assets

Fair Value Based on Significant Other Observable Inputs

Fair values for financial instruments utilizing level 2 inputs were determined from information obtained from third party pricing sources, broker quotes or calculations involving the use of market indices.

At ~~June~~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 ~~$2.8~~$2.9 billion as compared to the $2.7 billion face value of the debt recorded, net of discounts, in the Company’s Consolidated Condensed Balance Sheet. ~~At December 31, 2014, the fair value~~

Derivative Contracts

In order to mitigate the effect of exchange rate changes, the Company will often structure sales contracts to provide for collections from customers in the currency in which the Company incurs its manufacturing costs. In certain instances, the Company will enter into foreign currency forward contracts to hedge specific large anticipated receipts or disbursements in currencies for which the Company does not expect to have fully offsetting local currency expenditures or receipts. The Company was party to a number of short- and long-term foreign currency forward contracts at ~~June~~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. 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 contracts, many of which are centrally managed, are intended to offset other foreign currency exposures but have not been designated as hedges for accounting purposes and, therefore, any change in the fair value of those contracts is reflected in earnings in the period such change occurs. The Company determines the fair value of its outstanding foreign currency forward contracts based on quoted exchange rates for the respective currencies applicable to similar instruments.

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

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 Consolidated Condensed Balance Sheets at ~~June~~September 30, 2015 and December 31, 2014 were as follows:

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:

Note ~~15:~~16: Recently Issued Accounting Pronouncements

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. In order to comply with this new standard, companies will need to:

allocate the transaction price to each separate performance obligation.

ASU 2014-09, as amended, will be effective for Cameron beginning in the first quarter of 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 has begun evaluating the impact of the new standard on its business and will ultimately determine after further analysis whether it will select the full retrospective or the modified retrospective implementation method.

The FASB issued ASU 2015-03, ~~Interest—Imputation~~Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03) in April 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 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 this new standard 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.

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 ordinary course of 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.

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 actual results may differ materially from those described in any forward-looking statements. Any such statements are based on current expectations of the Company’s performance and are subject to a variety of factors, some of which are not under the control of the Company, which can affect the Company’s results of operations, liquidity or financial condition. Such factors may include overall demand for, and pricing of, the Company’s products; the size and timing of orders; the Company’s ability to successfully execute large subsea and drilling projects it has been awarded; the possibility of cancellations of orders in backlog; the Company’s ability to convert backlog into revenues on a timely and profitable basis; the impact of acquisitions the Company has made or may make; changes in the price of (and demand for) oil and gas in both domestic and international markets; raw material costs and availability; political and social issues affecting the countries in which the Company does business; fluctuations in currency markets worldwide; and variations in global economic activity. In particular, current and projected oil and gas prices historically have generally directly affected customers’ spending levels and their related purchases of the Company’s products and services. As a result, changes in oil and gas price expectations may impact the demand for the Company’s products and services and the Company’s financial results due to changes in cost structure, staffing and spending levels the Company makes in response thereto. See additional factors discussed in “Factors That May Affect Financial Condition and Future Results” contained herein.

Because the information herein is based solely on data currently available, it is subject to change as a result of, among other things, changes in conditions over which the Company has no control or influence, and should not therefore be viewed as assurance regarding the Company’s future performance. Additionally, the Company is not obligated to make public disclosure of such changes unless required under applicable disclosure rules and regulations.

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.

~~SECOND~~THIRD QUARTER 2015 COMPARED TO ~~SECOND~~THIRD QUARTER 2014

Information related to a measure of drilling activity and certain commodity spot and futures prices during each quarter and the number of deepwater floaters and semis under contract at the end of each period follows:

Drilling activity (average number of working rigs during period)⁽¹⁾:

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)

Brent crude oil spot price (per barrel)

Henry Hub natural gas spot price (per MMBtu)

Twelve-month futures strip price (U.S. dollar amount at period end)⁽²⁾:

West Texas Intermediate (WTI) Cushing, OK crude oil contract (per barrel)

Brent crude oil contract (per barrel)

Henry Hub natural gas contract (per MMBtu)

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


⁽²⁾	Source: Bloomberg


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

~~Second~~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 ~~sharp drop in~~continued low commodity prices that began during the latter half of 2014 and (ii) the resulting 2015 capital spending cuts announced by many ~~of the largest~~ oil and gas production companies. Average worldwide working rig count levels for the month of ~~June~~September 2015 ~~were down 40%~~decreased approximately 39% from December 2014 ~~and more than 16% from March 2015 and~~ but

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 ~~substantial~~ 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 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.

In the United States, the average number of rigs drilling for oil during the ~~second~~third quarter of 2015 ~~was down 55%~~decreased approximately 59% from the ~~second quarter of~~same period in 2014 and, at the end of ~~June~~September 2015, ~~was down 23%~~decreased approximately 2% from the end of the ~~first~~second quarter of 2015, to its lowest level since August 2010. Rigs drilling for oil accounted for approximately ~~73%~~77% of total U.S. rig count levels at the end of ~~June~~September 2015, compared to ~~83%~~82% at the end of ~~June~~September 2014. The number of rigs drilling for gas in the United States during the ~~second~~third quarter of 2015 was ~~30% lower~~approximately 36% less than the ~~second~~third quarter of 2014. Based on data from Baker Hughes, gas rig count levels in the United States during the ~~second~~third quarter of 2015 declined to their lowest levels in more than a quarter of a century.

The decrease in the Canadian rig count during the ~~second~~third quarter of 2015 as compared to the ~~second quarter of~~same period in 2014 was due largely to a decrease of ~~63%~~approximately 61% in the number of rigs drilling for oil. Rigs drilling for gas ~~were also down over~~decreased approximately 38% during those same periods. ~~Based on data from Baker Hughes, the number of rigs drilling for oil in Canada declined to a six-year low during the second quarter of 2015.~~

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

Average crude oil and natural gas prices were significantly lower during the ~~second~~third quarter of 2015 as compared to the same period last year. Both WTI and Brent crude prices at the end of the ~~second~~third quarter of 2015 have declined ~~over 40%~~approximately 51% and 46%, respectively, since ~~mid-2014 levels, although average daily crude oil prices increased during the second quarter of 2015 as compared to the first quarter of 2015.~~September 30, 2014. The twelve-month futures price for WTI crude oil at ~~June~~September 30, 2015 was approximately 3%6% higher than spot prices at the end of the quarter. The twelve-month futures price for Brent crude oil at ~~June~~September 30, 2015 was approximately 3%7% lower than spot prices at the end of the third quarter.

Average natural gas prices during the ~~second~~third quarter of 2015 were down ~~over 40%~~approximately 30% from the same period in 2014 and ~~continued~~increased slightly when compared to ~~decline slightly from~~ average prices during ~~the first quarter of 2015, although prices did recover somewhat near the end of~~ the second quarter of 2015. Spot prices at the end of ~~June~~September 2015 were ~~almost 6% higher~~approximately 40% lower than at the end of ~~March 2015. The~~September 2014. At September 30, 2015, the twelve-month futures strip price for natural gas at ~~June 30, 2015~~Henry Hub was ~~$3.05~~$2.75 per MMBtu, ~~at Henry Hub,~~ which was 10% higher than the spot price at that date of ~~$2.77.~~$2.47 per MMBtu.

The total number of drillships and semi-submersibles under contract at ~~June~~September 30, 2015 was down from ~~June~~September 30, 2014 due to the decline in commodity prices and drilling activity that began in the latter half of 2014. Based on data from IHS Energy, the contracted utilization rates for drillships was ~~87.5%~~75.8% in ~~June~~September 2015 compared to ~~96.2%~~92.7% in ~~June~~September 2014 and the contracted utilization rate for semi-submersibles was ~~85.4%~~70.2% in ~~June~~September 2015 compared to ~~92.0%~~81.9% in ~~June~~September 2014. At ~~June~~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 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

Net income attributable to Cameron stockholders for the ~~second~~third quarter of 2015 totaled ~~$140~~$187 million, compared to ~~$221~~$225 million for the same period in 2014. Earnings from continuing operations per diluted share totaled ~~$0.71~~$0.98 for the ~~second~~third quarter of 2015, compared to ~~$0.97~~$1.10 per diluted share for the same period in 2014. Included in the ~~second~~third quarter 2015 results were certain costs totaling ~~$0.12~~$0.20 per diluted share, primarily associated with:

Included in the results for the ~~second~~third quarter of 2014 were after-tax ~~gains, net of~~ costs, totaling ~~$0.02~~$0.07 per diluted share, primarily related to a ~~gain from remeasurement~~loss on disposal of ~~a prior interest in an equity method investment, partially offset by~~non-core assets, costs associated with the early retirement of certain ~~long-lived asset impairment charges.~~Senior Notes and severance, restructuring and various other costs.

~~Absent these unusual amounts, diluted earnings from continuing operations per share would have decreased nearly 13% in the second quarter~~

Table of ~~2015 as compared to the second quarter of 2014.~~Contents

Total revenues for the Company decreased ~~$348~~$470 million, or ~~13.5%~~17.6%, during the three months ended ~~June~~September 30, 2015 as compared to the three months ended ~~June~~September 30, ~~2014~~.2014. Revenues declined in all reporting segments due to weak market conditions resulting from the decrease in commodity prices and activity levels described above.

The Company’s ~~gross product~~ margins ~~(revenues~~(defined as revenues minus cost of sales, excluding depreciation and amortization, divided by revenues) increased to ~~28.7%~~30.7% during the ~~second~~third quarter of 2015 from ~~28.0%~~28.5% during the same period in 2014 mainly as a result of 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 as described further below under “Segment Results”.

Selling and administrative expenses decreased ~~$54~~$64 million, or ~~16.2%~~20.0%, during the three months ended ~~June~~September 30, 2015 as compared to the three months ended ~~June~~September 30, 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 ~~12.6%~~11.6% of revenues for the ~~second~~third quarter of 2015, down from ~~13.0%~~11.9% for the ~~second~~third quarter of 2014.

Other costs totaled ~~$37~~$44 million for the three months ended ~~June~~September 30, 2015, largely related to ~~pending~~ ~~facility closures~~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 certain Senior Notes and severance, ~~activities taken in response to current market conditions, accelerated depreciation on underutilized assets,~~restructuring and ~~a devaluation of the Angolan currency.~~ ~~Certain non-operating gains~~various other costs accounted for the majority of the ~~net~~ ~~gain~~$19 million of $6 ~~million~~costs recognized in the ~~second~~third quarter of 2014. See Note 34 of the Notes to Consolidated Condensed Financial Statements for further information.

The Company’s effective tax rate on income from continuing operations for the ~~second~~third quarter of 2015 was ~~23.5%~~16.9% compared to 23.0% for the ~~second~~third quarter of 2014. The components of the effective tax rates for both periods were as follows:

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 1011 of the Notes to Consolidated Condensed Financial Statements included in this Quarterly Report on Form 10-Q.

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

Revenues decreased modestly in the ~~second~~third quarter of 2015 as compared to the ~~second~~third quarter of 2014, primarily as a result of ~~a slowdown in~~lower shipments for a subsea project offshore West ~~Africa.~~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 ~~second~~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 ~~mix.~~margin mix, which added 9.3 percentage-points to the ratio. Also contributing to the improved performance was lower depreciation and amortization expense, as a result of lower intangible asset amortization and capital spending constraints, which increased the ratio by 0.7 percentage-points.

Orders ~~increased~~decreased significantly during the three months ended ~~June~~September 30, 2015 as compared to the same period in 2014, primarily due to the ~~favorable impact~~lack of ~~a $330 million award received for a~~new subsea ~~production system offshore North Africa and a significant award for subsea boosting~~tree awards, particularly in the Gulf of ~~Mexico.~~Mexico as compared to the third quarter of 2014, and lower demand for new processing equipment.

Backlog (at period-end)

~~The main drivers for~~Backlog in the ~~reduction in backlog levels at June 30, 2015 as compared~~Subsea segment continues to ~~June 30, 2014 were weak order rates in relation to revenues~~drop as changing market conditions during the ~~latter part of 2014 and the first quarter of 2015~~last twelve months caused a slowdown in new subsea production and processing equipment project awards ~~from customers.~~as customers significantly reduce their capital spending programs.

~~Surface Segment –~~

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

The ~~majority of the~~ decline in revenues during the ~~second~~third quarter of 2015 as compared to the ~~second~~third quarter of 2014 was primarily due to weak market conditions in North ~~America. Other contributing factors included lower activity levels~~America, which represented approximately 65% of the total decrease, as a result of a decline in ~~Latin America,~~demand and pricing for new equipment and services, particularly ~~Mexico~~with regard to equipment and ~~Venezuela, as well as lower shipments~~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 ~~weakness~~lower orders rates in ~~recent order levels.~~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

~~Nearly one-half~~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 was attributable~~revenues. Lower margins contributed to ~~lower product margins due to pricing pressures and~~an additional 2.2 percentage-point decline in the ~~unfavorable impact of lower utilization of rental equipment combined with modestly higher depreciation and amortization expense during the second quarter of 2015~~ratio as compared to the same period in ~~2014.~~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 declined during the ~~second~~third quarter of 2015 as compared to the ~~second~~third quarter of 2014 as a result of reduced activity levels in ~~various~~the North American unconventional resource regions and various international markets in response to declining commodity ~~prices, as well as lower demand for new products from customers in Saudi Arabia.~~prices.

Backlog (at period-end)

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

Drilling Segment –

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

Segment revenues decreased in the ~~second~~third quarter of 2015 as compared to the ~~second~~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 ~~service~~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 segment operating income before interest and income taxes as a percent of revenues in the ~~second~~third quarter of 2015 as compared to the same period last year was due primarily 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 decrease in selling and administrative ~~expenses.~~expenses, which added 3.2 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 of 1.3 percentage-points in the ratio.

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

Backlog (at period-end)

Backlog in the Drilling segment continues to drop mainly due to significantly lower activity levels in the new rig construction market, especially in relation to deepwater rigs. Service backlog (includes activities and products to support our existing customer installed base) has also declined 28% as customer decisions to scrap older rigs have resulted in a decrease in our installed base and as customers have elected to defer discretionary spending on services.

Segment revenues declined by 33% in the third quarter of 2015 as compared to the third quarter of 2014. Valve sales declined 33% and sales of measurement products were down 38%, due mainly to 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 lower activity levels in Asia Pacific.

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

Lower product margins resulting from 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 in the third quarter of 2015 as compared to the same period 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.

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 demand for subsea activity, globally, and midstream pipeline projects in North America slowed as capex spend is reassessed. The weakness in the North America upstream production market also led to a 39% decline in demand for Measurement products.

Backlog (at period-end)

Segment backlog decreased 20% in the third quarter of 2015 as compared to the third quarter of 2014, resulting from a decline in 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 midstream pipeline projects and downstream gas processing awards. Services backlog is up 11%.

Corporate Expenses -

Corporate expenses were $28 million for the third quarter of 2015, a decline of $7 million from $35 million in the third quarter of 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.

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

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

West Texas Intermediate (WTI) Cushing, OK crude spot price (per barrel)

Brent crude oil spot price (per barrel)

Henry Hub natural gas spot price (per MMBtu)

The decrease 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 2014, while the average number of rigs drilling for gas has decreased approximately 28% during the same period. Internationally, the average number of active working rigs declined as compared to the same period in 2014 in all major regions of the world, except the Middle East.

Average crude oil and natural gas prices were significantly lower during the first nine months of 2015 as compared to the same period last year. WTI and Brent crude prices at the end of the first nine months of 2015 have declined approximately 18% and 20%, respectively, since year end 2014 prices.

Consolidated Results

Net income attributable to Cameron stockholders for the nine months ended September 30, 2015 totaled $376 million, compared to $558 million for the first nine months of 2014. 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 $0.29 for the first nine months of 2015, compared to earnings 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 first nine months of 2015.

The results for the first nine months of 2014 included after-tax charges of $0.26 per share, primarily related to a goodwill impairment charge in the Process Systems and Equipment (PSE) business, a loss on disposal of non-core assets, as well as severance, restructuring and other costs, net of certain non-operating gains.

Total revenues for the Company decreased $874 million, or 11.5%, during the nine months ended September 30, 2015 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, 2015 as compared to the same period in 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 12.2% of revenues for the first nine months of 2015, down from 12.8% for the same period in 2014.

Interest, net increased $7 million, from $98 million during the first nine months of 2014 to $105 million during the same period in 2015, mainly as a result of $500 million of new senior notes issued in June 2014 and higher interest on capital leases.

Other costs were $658 million in the first nine months of 2015, 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 were recognized during the first nine months of 2014 largely related to the factors described above. See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information.

The Company’s effective income tax rate on income from continuing operations for the first nine months of 2015 was 109.1% as compared to 24.4% for the same period in 2014. The components of the effective tax rates for both periods were as follows:

Revenues decreased during the first nine months of 2015 as compared to the same period in 2014, as a result of decreased subsea equipment shipments, largely associated with 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 a percent of revenues

Segment operating income before interest and income taxes as a percent of revenues improved significantly in the first nine months 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 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 decreased during the nine months ended September 30, 2015 as compared to the same period in 2014, primarily due to a lower 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%.

The decline in revenues during the first nine months of 2015 as compared to the same period in 2014 was primarily due to weak market conditions in North America, which represented approximately 75% 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 were also seen in the 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.

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

Although, selling and administrative costs and depreciation and amortization expense as a percent of revenues declined on a combined basis during the first nine months of 2015 as compared to the same period in 2014, the rate of decrease 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 percent of revenues. Lower margins contributed to an additional 1.0 percentage-point decline in the ratio, largely attributable to pricing pressures in the North America unconventional markets and lower new product sales in Europe and the Middle East as compared to prior year.

Orders declined during the first nine months of 2015 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.

Drilling Segment –

The decline in revenues for the first nine months of 2015 as compared with the same period in 2014 mainly 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 in prior year due to the decline in the order rate.

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

The increase in segment operating income before interest and income taxes as a percent of revenues during the first nine months of 2015 as compared to the same period 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.

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

~~Backlog (at period-end)~~

~~Backlog at June 30, 2015 decreased from June 30, 2014 mainly due to the lack of meaningful activity in the new rig construction market, especially in relation to deepwater rigs. Service backlog~~ ~~(includes activities and products to support our existing customer installed base) has~~ ~~also declined as customer decisions to scrap older rigs have resulted in a decrease in our installed base and as customers have elected to defer discretionary spending on services.~~

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

Segment revenues declined inby 26% for the ~~second quarter~~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 ~~second quarter of 2014, as lower~~weakness in the North America upstream ~~activity levels, caused by a decline in commodity prices, resulted in lower sales of valves~~drilling and ~~measurement products.~~production markets. Additionally, lower beginning of year backlog ~~levels~~ for ~~engineered and process~~ valves ~~for use~~used in midstream pipeline and ~~downstream~~critical service applications ~~have also negatively impacted current shipment levels~~account for a 10% decline in sales in comparison to the prior ~~year quarter.~~year. Measurement sales declined 25%, due to significantly reduced activity levels in the North American upstream production markets. Services revenue declined 7% on lower activity in Asia Pacific.

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

~~The~~Lower product margins resulting from lower volumes, pricing pressures combined with higher obsolescence and warranty costs resulted in a 4.2 percentage-point decrease in segment operating income before interest and income taxes as a percent of revenues for the first nine months of 2015 as compared to the same period in 2014. On a combined basis, selling and administrative expenses and depreciation and amortization declined in the first nine months of 2015 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 declined sharply in the second quarter of 2015 as compared to the second quarter of 2014, primarily due to lower North America valve and measurement product margins resulting from pricing pressures and higher costs, as well as higher depreciation and amortization expense on lower volumes. Although selling and administrative expenses declined in the second quarter of 2015 as compared to the second quarter of 2014, the rate of decline was less than the rate of decline in revenues.by 2.9 percentage-points.

~~Orders~~Segment orders declined by 30% for the ~~second quarter~~first nine months of 2015 ~~reflected a significant~~as compared with the same period in 2014. Valve orders declined 33% and Measurement orders decline ~~when compared~~31%, due to ~~the second quarter of 2014. Lower North America upstream activity levels and high distributor inventory levels reduced~~lower demand for ~~valve~~valves and measurement ~~products. Additionally, current weakness~~products in the upstream drilling, production and subsea markets. Furthermore, lower midstream and downstream project activity ~~levels has~~outside North America also negatively impacted demand for ~~valves for new midstream~~pipeline and ~~downstream projects.~~gas processing products. Services orders are down 4% on lower activity levels in Asia Pacific.

~~Backlog (at period-end)~~

Backlog levels for the V&M segment decreased from June 30, 2014 to June 30, 2015, as order rates during the last twelve months for custom valve and measurement products have not kept pace with recent deliveries.

Corporate expenses were ~~$23~~$74 million for the ~~second quarter~~first nine months of 2015, a decline of ~~$15~~$36 million from ~~$38~~$110 million in the ~~second quarter of 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.

~~SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO SIX MONTHS ENDED JUNE 30, 2014~~

~~Market Conditions~~

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

Drilling activity (average number of working rigs during period)⁽¹⁾:

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)

Brent crude oil spot price (per barrel)

Henry Hub natural gas spot price (per MMBtu)

⁽¹⁾

~~Based on average monthly rig count data from Baker Hughes~~

⁽²⁾

~~Source: Bloomberg~~

The decrease in average worldwide operating rigs during the first six months of 2015 as compared to the same period in 2014 reflects a significant decline in activity levels, particularly in the United States and Canada, which began at the end of 2014 and continued throughout the first six months of 2015. This drop in activity levels was in response to a significant decline in commodity prices which began during the last six months of 2014. In the United States, the average number of rigs drilling for oil has decreased almost 40% during the first six months of 2015 as compared to the same period in 2014, while rigs drilling for gas have declined 23% during the same period. In Canada, the average number of rigs drilling for oil was down 58% during the first six months of 2015 as compared to the first six months of 2014, while rigs drilling for gas were down 21%. Internationally, the average number of active working rigs declined in all major regions of the world, except the Middle East.

Average crude oil and natural gas prices were significantly lower during the first six months of 2015 as compared to the same period last year. Both WTI and Brent crude prices at the end of the first six months of 2015 have declined over 40% since mid-2014 levels, although average daily crude oil prices did increase during the second quarter of 2015 as compared to the first quarter of 2015.

While average natural gas prices during the first six months of 2015 were down significantly from the first six months of 2014, prices did begin to recover somewhat near the end of the first half of 2015 as compared to earlier in 2015.

~~Consolidated Results~~

Net income attributable to Cameron stockholders for the six months ended June 30, 2015 totaled $189 million, compared to $332 million for the first six months of 2014. The Company had a loss from continuing operations for the first six months of 2015 of $243 million, largely resulting from a goodwill impairment charge in the Process Systems business totaling $517 million. Offsetting this loss was income from discontinued operations of $432 million, which represented the gain on the sale of the Company’s Centrifugal Compression business. The Company’s loss from continuing operations per diluted share totaled $1.27 for the first six months of 2015, compared to earnings from continuing operations per diluted share of $1.44 for the same period in 2014. The goodwill impairment charge described above, as well as other asset impairment charges and certain other costs described further in Note 3 of the Notes to Consolidated Condensed Financial Statements totaled $3.01 per diluted share for the first six months of 2015.

The results for the first six months of 2014 included after-tax charges of $0.19 per share, primarily related to a goodwill impairment charge in the Process Systems and Equipment (PSE) business, an impairment of certain intangible assets, as well as severance, restructuring and other costs, net of certain non-operating gains.

~~Absent these costs in both periods, diluted earnings from continuing operations per share would have increased approximately 7% as compared to the first half of 2014.~~

~~Total revenues for the Company decreased $404 million, or 8.2%, during the six months ended~~ ~~June 30, 2015~~ ~~as compared to the same period in~~ ~~2014. Revenues declined in each segment except Drilling due to the impact of the weak market conditions resulting from the decrease in commodity prices and activity levels described above.~~

The Company’s gross product margins (revenues minus cost of sales, excluding depreciation and amortization, divided by revenues) increased to 29.0% during the first six months of 2015 from 27.7% during the same period in 2014, mainly due to improvements in project execution in the Subsea and Drilling segments as described further below under “Segment Results”.

~~Selling and administrative expenses decreased $86 million, or 13.2%, during the six months ended June 30, 2015 as compared to the same period in~~ 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 12.6% of revenues for the first six months of 2015, down from 13.3% for the same period in 2014.~~

Net interest increased $9 million, from $62 million during the first half of 2014 to $71 million during the first half of 2015, mainly as a result of $500 million of new senior notes issued in June 2014 and higher interest on capital leases.

~~Other costs~~ ~~were $614~~ ~~million in the first six months of 2015, largely associated with~~ ~~(i)~~ ~~the goodwill impairment for the Process Systems business described above, (ii)~~ ~~impairment of certain underutilized facilities, (iii) pending facility closures and severance activities taken in response to current market conditions, (iv) accelerated depreciation on underutilized assets, and (v)~~ a ~~devaluation~~ of ~~the Venezuelan and Angolan currencies.~~ ~~Charges of $~~43 ~~million were recognized during the first six months of 2014~~ ~~primarily~~ ~~for a goodwill impairment in the PSE business and impairment of certain intangible assets.~~

~~See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information.~~

The Company’s effective income tax rate on income from continuing operations for the first six months of 2015 was a negative 79.2% as compared to 25.2% for the same period in 2014. The components of the effective tax rates for both periods were as follows:

~~Subsea Segment –~~

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

Revenues decreased in the first half of 2015 as compared to the same period in 2014, primarily as a result of a slowdown in new product shipments, largely associated with projects offshore West Africa and in Asia. This was partially offset by modest growth in the segment’s Services business ~~(includes activities and products to support our existing customer installed base).~~

~~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 first six months of 2015 as compared to the same period in 2014, due mainly to continued improvement in execution, cost control efforts and favorable mix.

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

~~Surface Segment –~~

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

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

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

Nearly three quarters of the decline in the ratio of segment operating income before interest and income taxes as a percent of revenues was attributable to higher depreciation and amortization expense during the first six months of 2015 as compared to the same period in 2014 ~~due to investment in rental assets in 2014.~~ ~~Although selling and administrative expenses declined in the first six months of 2015 as compared to the same period in 2014, the rate of decline was less than the rate of decline in revenues.~~

Orders declined during the first six months of 2015 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 Saudi Arabia as compared to the levels experienced during the first six months of 2014.

~~Drilling Segment –~~

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

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

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

The substantial increase in segment operating income before interest and income taxes as a percent of revenues in the first six months of 2015 as compared to the same period in 2014 was due primarily to (i) continued improvement in project execution and (ii) cost control efforts, including a decrease in selling and administrative expenses as compared to the first six months of 2014.

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

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

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

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

The ratio of segment operating income before interest and income taxes as a percent of revenues declined sharply in the first half of 2015 as compared to the first half of 2014, primarily due to lower North America valve and measurement product margins resulting from pricing pressures and higher costs. Although selling and administrative expenses declined in the first half of 2015 as compared to the first half of 2014, the rate of decline was less than half the rate of decline in revenues. Also contributing to the lower ratio was higher depreciation and amortization expense on lower volumes.

Orders for the first six months of 2015 reflected a significant decline when compared to the same period in 2014. Lower North America upstream activity levels and high distributor inventory levels reduced demand for valve and measurement products. Additionally, current weakness in activity levels has also negatively impacted demand for valves for new midstream and downstream projects.

~~Corporate Expenses -~~

~~Corporate expenses were $46 million for the first six months of 2015, a decline of $29 million from $75 million in the first six months of 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.

Liquidity and Capital Resources

Consolidated Condensed Statements of Cash Flows

During the first ~~six~~nine months of 2015, net cash ~~used for~~provided by operations totaled ~~$165~~$211 million, a decrease of ~~$204~~$44 million from the ~~$39~~$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 ~~six~~nine months of 2015 as compared to the same period in 2014. ~~Additionally, a targeted reduction in the Company’s inventory has been slowed by the lengthy nature of many supply chains and the reduced pace of manufacturing activity.~~

Cash totaling ~~$573~~$518 million was used to increase working capital during the first ~~six~~nine months of 2015 compared to ~~$588~~$532 million during the same period in 2014, a decrease of ~~$15~~$14 million. During the first ~~six~~nine months of 2015, increased collections of receivables across ~~all~~mainly in the Drilling and Surface segments, added ~~$252~~$245 million in ~~cash. Offsetting this was $70 million of~~ cash ~~used as~~and inventory ~~levels continued to increase~~reductions, primarily in ~~each~~the Drilling segment, ~~other than Drilling.~~increased cash by $106 million. The timing of payments to third parties and the consumption of customer advances on projects ~~and annual employee incentive payouts made in the first half of 2015 also~~largely contributed to a $869 million use of cash ~~totaling $755 million~~ for the period.

Cash provided by investing activities was ~~$386~~$444 million for the first ~~six~~nine months of 2015 as compared to ~~$346~~$218 million during the same period in 2014. In 2015, 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, net of transaction costs, from the sale of the Reciprocating Compression business to General Electric. Approximately ~~$323~~$209 million of cash was used to increase the Company’s short term investments portfolio during the first ~~six~~nine months of 2015 ~~and capital~~as compared to $74 million for the same period in 2014. Capital spending ~~during~~for the ~~period~~nine months ended September 30, 2015 consumed ~~an additional $130~~$190 million, as compared to ~~capital spending of $178~~$259 million during the same period in 2014. Capital needs in the Subsea, Surface and Drilling segments accounted for the majority of the 2015 capital spending.

Net cash used for financing activities totaled ~~$402~~$472 million for the first ~~six~~nine months of 2015 as compared to ~~$677 million~~$1.2 billion used for financing activities during the same period in 2014. During the first ~~half~~nine months of 2015, the Company acquired over 45 million shares of treasury stock at a cash cost of ~~$195~~$240 million. ~~Approximately $1.2~~Nearly $1.6 billion of cash was used to acquire ~~nearly 20~~approximately 25 million shares of treasury stock during the first ~~half~~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 had $201 million of outstanding commercial paper at December 31, 2014 that was repaid during ~~the first six months of~~ 2015. Contributions from noncontrolling interest owners also added $18 million during the first six months of 2015, primarily relating to their share of a capital contribution made to OneSubsea in June 2015. Additionally, duringIn June 2014, the Company issued a total of $500 million of new senior notes split equally between 3- and 10-year ~~maturities.~~maturities and, in July 2014, made an early redemption of senior notes at a cash cost of $253 million.

Future liquidity requirements

At ~~June~~September 30, 2015, the Company had ~~$1.7~~$1.9 billion of cash, cash equivalents and short-term investments. Approximately ~~$635~~$591 million of the Company’s cash, cash equivalents and short-term investments at ~~June~~September 30, 2015 were in the OneSubsea venture. Dividends of available cash from OneSubsea to the venture partners 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 in the OneSubsea venture, ~~$333~~$677 million was located in the United States. Total debt at ~~June~~September 30, 2015 was ~~nearly~~approximately $2.8 billion, most of which was in the United States. Excluding capital leases, approximately ~~$518~~$976 million of the debt obligations have maturities within the next three-year period. The remainder of the Company’s long-term debt is due in varying amounts between ~~the last half of 2018~~2021 and 2043.

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(unaudited)

REVENUES	$	2,222		$	2,570		$	4,495		$	4,899
COSTS AND EXPENSES:
Cost of sales (exclusive of depreciation and amortization shown separately below)		1,585			1,850			3,193			3,540
Selling and administrative expenses		279			333			565			651
Depreciation and amortization		89			88			178			173
Interest, net		33			30			71			62
Other costs (gains), net (see Note 3)		37			(6	)		614			43
Total costs and expenses		2,023			2,295			4,621			4,469

Income (loss) from continuing operations before income taxes		199			275			(126	)		430
Income tax provision		(47	)		(65	)		(100	)		(110	)
Income (loss) from continuing operations		152			210			(226	)		320
Income from discontinued operations, net of income taxes		3			23			432			28
Net income		155			233			206			348

Less: Net income attributable to noncontrolling interests		15			12			17			16
Net income attributable to Cameron stockholders	$	140		$	221		$	189		$	332

Amounts attributable to Cameron stockholders:
Income (loss) from continuing operations	$	137		$	198		$	(243	)	$	304
Income from discontinued operations		3			23			432			28
Net income attributable to Cameron stockholders	$	140		$	221		$	189		$	332

Earnings (loss) per common share attributable to Cameron stockholders:
Basic -
Continuing operations	$	0.71		$	0.97		$	(1.27	)	$	1.46
Discontinued operations		0.02			0.11			2.25			0.13
Basic earnings per share	$	0.73		$	1.08		$	0.98		$	1.59

Diluted -
Continuing operations	$	0.71		$	0.97		$	(1.27	)	$	1.44
Discontinued operations		0.02			0.11			2.25			0.13
Diluted earnings per share	$	0.73		$	1.08		$	0.98		$	1.57
Shares used in computing earnings per common share:
Basic		191			204			192			209
Diluted		192			205			192			211

Comprehensive income	$	261		$	218		$	22		$	359
Less: Comprehensive income (loss) attributable to noncontrolling interests		49			4			(14	)		23
Comprehensive income attributable to Cameron stockholders	$	212		$	214		$	36		$	336

	June 30, 2015			December 31, 2014
	(unaudited)
ASSETS
Cash and cash equivalents	$	1,295		$	1,513
Short-term investments		436			113
Receivables, net		2,096			2,389
Inventories, net		2,938			2,929
Other current assets		390			391
Assets of discontinued operations		–			217
Total current assets		7,155			7,552
Plant and equipment, net		1,814			1,964
Goodwill		1,880			2,461
Intangibles, net		683			728
Other assets		200			187
TOTAL ASSETS	$	11,732		$	12,892

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt	$	31		$	263
Accounts payable and accrued liabilities		2,933			3,748
Accrued income taxes		298			168
Liabilities of discontinued operations		–			90
Total current liabilities		3,262			4,269
Long-term debt		2,813			2,819
Deferred income taxes		180			193
Other long-term liabilities		167			167
Total liabilities		6,422			7,448
Stockholders’ Equity:
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at June 30, 2015 and December 31, 2014		3			3
Capital in excess of par value		3,242			3,255
Retained earnings		5,820			5,631
Accumulated other elements of comprehensive income (loss)		(693	)		(540	)
Less: Treasury stock, 71,671,246 shares at June 30, 2015 (68,139,027 shares at December 31, 2014)		(3,955	)		(3,794	)
Total Cameron stockholders’ equity		4,417			4,555
Noncontrolling interests		893			889
Total equity		5,310			5,444
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	11,732		$	12,892

Balance at December 31, 2014	$	2,461
Impairment of goodwill (Note 3)		(517	)
Adjustments to the purchase price allocation for prior year acquisitions		(12	)
Translation effect of currency changes and other		(52	)
Balance at June 30, 2015	$	1,880

	Six Month Ended June 30,
	2015						2014
(dollars in millions)	Tax Provision			Tax Rate			Tax Provision			Tax Rate

Provision (benefit) based on international income (loss) distribution	$	(29	)		23.0	%	$	101			23.5	%
Adjustments to income tax provision:
Asset impairments with no tax benefit		127			(100.5	)		10			2.2
Other asset impairments		(1	)		0.9			–			–
Finalization of prior year returns		2			(2.0	)		2			0.4
Changes in valuation allowances		1			(0.6	)		1			0.1
Accrual adjustments and other		–			–			(4	)		(1.0	)
Tax provision	$	100			(79.2	)%	$	110			25.2	%

	Three Months Ended June 30,						Six Month Ended June 30,
(dollars in millions)	2015			2014			2015			2014
Revenues:
Subsea	$	658		$	735		$	1,289		$	1,416
Surface		510			613			1,053			1,151
Drilling		719			766			1,445			1,433
V&M		381			539			809			1,039
Elimination of intersegment revenues		(46	)		(83	)		(101	)		(140	)
Total revenues	$	2,222		$	2,570		$	4,495		$	4,899

Segment income before interest and income taxes:
Subsea	$	67		$	46		$	124		$	75
Surface		69			108			161			199
Drilling		119			97			254			164
V&M		44			110			89			208
Elimination of intersegment earning		(7	)		(24	)		(23	)		(36	)
Segment income before interest and income taxes		292			337			605			610

Corporate items:
Corporate expenses		(23	)		(38	)		(46	)		(75	)
Interest, net		(33	)		(30	)		(71	)		(62	)
Other (costs) gains, net (see Note 3)		(37	)		6			(614	)		(43	)
Income (loss) from continuing operations before income taxes	$	199		$	275		$	(126	)	$	430

	Three Months Ended June 30, 2015
(dollars in millions)	Accumulated Foreign Currency Translation Gain (Loss)			Prior Service Credits and Net Actuarial Losses			Accumulated Gain (Loss) on Cash Flow Hedge Derivatives			Total			Three Months Ended June 30, 2014

Balance at beginning of period	$	(625	)	$	(78	)	$	(62	)	$	(765	)	$	(69	)

Other comprehensive income (loss) before reclassifications:
Pre-tax		50			–			15			65			(6	)
Tax effect		–			–			(12	)		(12	)		1

Amounts reclassified from accumulated other comprehensive income to:
Revenues		–			–			18			18			(2	)
Cost of sales		–			–			9			9			(2	)
Tax effect		–			–			(8	)		(8	)		2
Net current period other comprehensive income (loss)		50			–			22			72			(7	)
Balance at end of period	$	(575	)	$	(78	)	$	(40	)	$	(693	)	$	(76	)

	Six Months Ended June 30, 2015
(dollars in millions)	Accumulated Foreign Currency Translation Gain (Loss)			Prior Service Credits and Net Actuarial Losses			Accumulated Gain (Loss) on Cash Flow Hedge Derivatives			Total			Six Months Ended June 30, 2014

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

Other comprehensive income (loss) before reclassifications:
Pre-tax		(147	)		–			(43	)		(190	)		10
Tax effect		–			–			4			4			(2	)

Amounts reclassified from accumulated other comprehensive income to:
Revenues		–			–			29			29			(5	)
Cost of sales		–			–			17			17			(2	)
Tax effect		–			–			(13	)		(13	)		3
Net current period other comprehensive income (loss)		(147	)		–			(6	)		(153	)		4
Balance at end of period	$	(575	)	$	(78	)	$	(40	)	$	(693	)	$	(76	)

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



	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

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

Derivatives designated as hedging instruments:
Current	$	15	$	67	$	8	$	83
Non-current		5		8		1		12
Total derivatives designated as hedging instruments		20		75		9		95

Derivatives not designated as hedging instruments:
Current		10		5		1		14
Non-current		–		–		–		–
Total derivatives not designated as hedging instruments		10		5		1		14

Total derivatives	$	30	$	80	$	10	$	109


	Three Months Ended June 30,				Increase (Decrease)						Three Months Ended September 30,				Increase (Decrease)
	2015		2014		Amount			%			2015		2014		Amount			%
Drilling activity (average number of working rigs during period)⁽¹⁾:
United States		909		1,852		(943	)		(50.9	)%	866		1,903		(1,037		)	(54.5	)%
Canada		100		202		(102	)		(50.5	)%	191		385		(194		)	(50.4	)%
Rest of world		1,169		1,348		(179	)		(13.3	)%	1,132		1,348		(216		)	(16.0	)%
Global average rig count		2,178		3,402		(1,224	)		(36.0	)%	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)	$	57.85	$	103.06	$	(45.21	)		(43.9	)%	$	46.48	$	97.60	$	(51.12	)	(52.4	)%
Brent crude oil spot price (per barrel)	$	66.22	$	106.96	$	(40.74	)		(38.1	)%	$	54.57	$	104.30	$	(49.73	)	(47.7	)%
Henry Hub natural gas spot price (per MMBtu)	$	2.73	$	4.59	$	(1.86	)		(40.5	)%	$	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)	$	60.97	$	101.10	$	(40.13	)		(39.7	)%	$	47.83	$	88.68	$	(40.85	)	(46.1	)%
Brent crude oil contract (per barrel)	$	63.59	$	112.36	$	(48.77	)		(43.4	)%	$	48.37	$	94.67	$	(46.30	)	(48.9	)%
Henry Hub natural gas contract (per MMBtu)	$	3.05	$	4.35	$	(1.30	)		(29.9	)%	$	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		49		(3	)		(6.1	)%	46		48		(2		)	(4.2	)%
Central and South America		60		76		(16	)		(21.1	)%	55		66		(11		)	(16.7	)%
Northwestern Europe		41		46		(5	)		(10.9	)%	38		44		(6		)	(13.6	)%
West Africa		36		45		(9	)		(20.0	)%	32		46		(14		)	(30.4	)%
Far East, Southeast Asia and Australia		29		26		3			11.5	%	28		39		(11		)	(28.2	)%
Indian Ocean		10		16		(6	)		(37.5	)%	7		16		(9		)	(56.3	)%
Other		22		28		(6	)		(21.4	)%	20		24		(4		)	(16.7	)%
Total		244		286		(42	)		(14.7	)%	226		283		(57		)	(14.7	)%


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

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

Provision based on international income distribution	$	46			23.0	%	$	65			23.5	%
Adjustments to income tax provision:
Other asset impairments		(1	)		(0.6	)		–			–
Finalization of prior year returns		1			0.7			–			–
Changes in valuation allowances		1			0.4			1			0.1
Accrual adjustments and other		–			–			(1	)		(0.6	)
Tax provision	$	47			23.5	%	$	65			23.0	%

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

Revenues	$	510		$	613		$	(103	)		(16.8	)%
Segment operating income before interest and income taxes	$	69		$	108		$	(39	)		(36.1	)%
Segment operating income before interest and income taxes as a percent of revenues		13.5	%		17.6	%		N/A		(4.1) pts.

Orders	$	471		$	619		$	(148	)		(23.9	)%
Backlog (at period-end)	$	970		$	1,146		$	(176	)		(15.4	)%

Period	Total number of shares purchased during the period		Average price paid per share		Cumulative number of shares purchased as part of repurchase program		Maximum number of shares that may yet be purchased under repurchase program⁽¹⁾
4/1/15 – 4/30/15		278,700	$	46.35		59,613,149		5,193,109
5/1/15 – 5/31/15		–	$	–		59,613,149		5,546,196
6/1/15 – 6/30/15		–	$	–		59,613,149		5,436,056
Total		278,700	$	46.35		59,613,149		5,436,056


⁽¹⁾	Based upon month-end stock price. At ~~June~~September 30, 2015, the closing stock price was ~~$52.37~~$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: ~~July 24,~~October 22, 2015	CAMERON INTERNATIONAL CORPORATION
	(Registrant)

	By:	/s/ 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		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