·	~~$250 million principal amount of 3.7% Senior Notes due June 15, 2024, sold at an offering price of 99.769%.~~

��

~~Interest on the notes~~The Company has in place a commercial paper program which will ~~be payable semiannually on June 15 and December 15~~allow for issuances of ~~each year, beginning December 15, 2014. The notes may be redeemed in whole or in part by the Company prior~~up to maturity, as provided for in the terms of each note, for an amount equal to the principal amount of the notes redeemed plus a specified make-whole premium. All of the Company's senior notes rank equally with the Company's other existing unsecured and unsubordinated debt.

Utilizing proceeds from these notes, on July 21, 2014, the Company paid approximately $253 million, which included a make-whole premium plus accrued interest, to redeem early its $250 million principal amount of 1.6% Senior Notes.

~~During the first quarter of 2014, the Company's Board of Directors authorized the establishment of a~~ $500 million ~~commercial paper program. This program allows for issuances~~ of commercial paper with maturities of ~~up to~~no more than 364 ~~days to be~~days. This program is used for general corporate purposes. ~~The average term of the outstanding commercial paper at September 30, 2014 was approximately 26 days.~~

~~On April 11, 2014,~~At March 31, 2015, the Company ~~entered into~~had no amounts outstanding under its $835 million Amended Credit Agreement, which matures on June 6, 2016.

The Company also has a ~~new~~ $750 million ~~three-year~~ multi-currency syndicated Revolving Credit Facility expiring April 11, 2017. Up to $200 million of ~~this new facility~~the Revolving Credit Facility may also be used for letters of credit and $92 million of letters of credit issued and outstanding under a previously existing $170 million bi-lateral facility were transferred to the new Revolving Credit Facility at close and concurrently the $170 million bi-lateral facility was amended to reduce its capacity to $40 million. The new Revolving Credit Facility contains covenants and terms consistent with the Company's existing $835 million five-year multi-currency Revolving Credit Facility, which matures on June 6, 2016, and it serves as the primary backstop to the commercial paper program. At September 30, 2014, no amounts had been borrowed under the $835 million Revolving Credit Facility.credit. The Company has issued letters of credit totaling ~~$72~~$45 million under the ~~new $750 million~~ Revolving Credit Facility, ~~and $25~~leaving $705 million ~~under the $40 million bi-lateral facility, leaving $678 million and $15 million, respectively,~~ available for future use at ~~September 30, 2014.~~March 31, 2015.

Note 9: Income Taxes

The Company's effective tax rate on income (loss) from continuing operations before income taxes for the first ~~nine months~~quarter of ~~2014~~2015 was ~~24.4%~~a negative 16.3% compared to ~~23.7%~~29.0% for the ~~nine months~~first quarter of ~~2013.~~2014. The components of the effective tax rates for both periods were as ~~follows (dollars in millions):~~follows:

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

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


	Three Months Ended March 31,
	2015						2014
(dollars in millions)	Tax Provision			Tax Rate			Tax Provision			Tax Rate
Provision (benefit) based on international income (loss) distribution	$	(75	)		23.0	%	$	37			23.9	%
Adjustments to income tax provision (benefit):
Asset impairments with no tax benefit		127			(39.2	)		10			6.4
Finalization of prior year returns		–			–			(3	)		(1.9	)
Accrual adjustments and other		1			(0.1	)		1			0.6
Tax provision	$	53			(16.3	)%	$	45			29.0	%

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Note 10: Business Segments

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

Three Months Ended
September 30,

Nine Months Ended
September 30,

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

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

	Three Months Ended March 31,
(dollars in millions)	2015			2014
Revenues:
Subsea	$	631		$	681
Surface		543			538
Drilling		726			667
V&M		428			500
Elimination of intersegment revenues		(55	)		(57	)
Total revenues	$	2,273		$	2,329

Segment Income before Interest and Income Taxes:
Subsea	$	57		$	29
Surface		92			91
Drilling		135			67
V&M		45			98
Elimination of intersegment earnings		(16	)		(12	)
Segment income before interest and income taxes		313			273

Corporate Items:
Corporate expense		(23	)		(37	)
Interest, net		(38	)		(32	)
Asset impairment charges		(553	)		(40	)
Other costs		(24	)		(9	)
Consolidated income (loss) from continuing operations before income taxes	$	(325	)	$	155

Corporate ~~& other includes~~items include governance expenses associated with the Company's ~~back~~corporate office, ~~support and public company costs,~~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, 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 that are not considered a component of segment operating income. Consolidated interest income and expense are treated as ~~described further in Note 3~~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.

Table of ~~the Notes to Consolidated Condensed Financial Statements.~~ Contents

Note 11: Earnings (Loss) Per Share

The calculation of basic and diluted earnings (loss) per share for each period presented was as follows (dollars and shares in millions, except per share amounts):

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
(dollars and shares in millions, except per share amounts)									2015			2014
	2014		2013		2014		2013

Net income from continuing operations	$	235	$	178	$	556	$	439
Net income attributable to noncontrolling interests		13		3		29		3
Net income from continuing operations attributable to Cameron		222		175		527		436
Net income (loss) from continuing operations									$	(378	)	$	110
Less: Net income attributable to noncontrolling interests										2			4
Net income (loss) from continuing operations attributable to Cameron										(380	)		106
Income from discontinued operations, net of taxes		3		14		31		42		429			5
Net income attributable to Cameron	$	225	$	189	$	558	$	478
Net income attributable to Cameron stockholders									$	49		$	111

Average shares outstanding (basic)		201		243		207		246		193			215
Common stock equivalents		2		1		1		1		–			1
Diluted shares		203		244		208		247		193			216

Basic earnings per share:
Basic earnings (loss) per share attributable to Cameron stockholders:
Continuing operations	$	1.11	$	.72	$	2.55	$	1.78	$	(1.97	)	$	0.49
Discontinued operations		.01		.06		.15		.17		2.22			0.02
Basic earnings per share	$	1.12	$	.78	$	2.70	$	1.95	$	0.25		$	0.51

Diluted earnings per share:
Diluted earnings (loss) per share attributable to Cameron stockholders:
Continuing operations	$	1.10	$	.72	$	2.53	$	1.77	$	(1.97	)	$	0.49
Discontinued operations		.01		.06		.15		.17		2.22			0.02
Diluted earnings per share	$	1.11	$	.78	$	2.68	$	1.94	$	0.25		$	0.51

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

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2014			2013			2015			2014

Treasury shares at beginning of period		60,027,350			17,001,730			41,683,164			16,415,336			68,139,027			41,683,164
Purchases of treasury shares		4,915,044			7,677,282			24,588,815			9,790,737			3,946,534			15,157,103
Net change in treasury shares owned by participants in nonqualified deferred compensation plans		(1,440	)		3,052			36,708			55,159			(133	)		39,762
Treasury shares issued in satisfaction of stock option exercises and vesting of restricted stock units		(132,881	)		(60,537	)		(1,500,614	)		(1,639,705	)		(542,236	)		(770,393	)
Treasury shares at end of period		64,808,073			24,621,527			64,808,073			24,621,527			71,543,192			56,109,636

The average cost of treasury shares acquired for the ~~three- and nine-month~~three-month periods ended ~~September 30,~~March 31, 2015 and 2014 was ~~$71.43~~$45.31 and ~~$63.38, respectively. The average cost of treasury shares acquired for the three- and nine-month periods ended September 30, 2013 was $58.04 and $58.84,~~$60.91, respectively.

The Company has an authorized stock repurchase program whereby the Company may purchase shares directly or indirectly by way of open market transactions or structured programs, including the use of derivatives, for the Company's own account or through commercial banks or financial institutions. The program, initiated in October 2011, has had a series of authorizations by the Board of Directors totaling $3.8 billion since inception. At ~~September 30, 2014,~~March 31, 2015, the Company had remaining authority for future treasury stock purchases totaling approximately ~~$665~~$298 million.

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Note 12: Accumulated Other Comprehensive Income (Loss)

The changes in the components of accumulated other elements of comprehensive income (loss) for the three months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~ were as ~~follows (in millions):~~follows:

Three Months Ended September 30, 2014

Accumulated Foreign Currency Translation
Gain (Loss)
Prior Service Credits and Net Actuarial Losses Accumulated Gain (Loss) on Cash Flow Hedge Derivatives Total
Three Months Ended
September 30, 2013

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

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

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

~~Table of Contents~~

	Three Months Ended March 31, 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 March 31, 2014

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

Other comprehensive income (loss) before reclassifications:
Pre-tax		(197	)		–			(58	)		(255	)		16
Tax effect		–			–			16			16			(3	)

Amounts reclassified from accumulated other comprehensive income to:
Revenues		–			–			11			11			(3	)
Cost of sales		–			–			8			8			–
Selling and administrative expense		–			–			–			–			–
Tax effect		–			–			(5	)		(5	)		1

Net current period other comprehensive income		(197	)		–			(28	)		(225	)		11

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

~~The changes in~~Other comprehensive loss associated with noncontrolling interests totaled approximately $65 million during the ~~components of accumulated other elements of comprehensive income (loss) for the nine~~three months ended ~~September 30, 2014 and 2013 were as follows (in millions):~~March 31, 2015, the majority of which was attributable to accumulated foreign currency translation losses.

Nine Months Ended September 30, 2014

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

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

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

Note 13: Contingencies

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

Litigation

The Company has been and continues to be named as a defendant in a number of multi-defendant, multi-plaintiff tort lawsuits. At ~~September 30, 2014,~~March 31, 2015, the Company's Consolidated Condensed Balance Sheet included a liability of approximately ~~$17~~$18 million for such cases. The Company believes, based on its review of the facts and law, that the potential exposure from these suits will not have a material adverse effect on its consolidated results of operations, financial condition or liquidity.

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Tax and Other Contingencies

The Company has legal entities in ~~over~~nearly 50 countries. As a result, the Company is subject to various tax filing requirements in these countries. The Company prepares its tax filings in a manner which it believes is consistent with such filing requirements. However, ~~some of~~ the tax laws and regulations to which the Company is subject often require interpretation and/or the application of judgment. Although the Company believes the tax liabilities for periods ending on or before the balance sheet date have been adequately provided for in the financial statements, to the extent a taxing authority believes the Company has not prepared its tax filings in accordance with the authority's interpretation of the tax laws and regulations, the Company could be exposed to additional taxes.

~~Table of Contents~~

The Company has been assessed customs duties and penalties by the government of Brazil totaling ~~approximately $53~~a U.S. dollar equivalent of almost $40 million at ~~September 30, 2014,~~March 31, 2015, including interest accrued at local country rates, following a customs audit for the years 2003-2010. The Company filed an administrative appeal and believes a majority of this assessment will ultimately be proven to be incorrect because of numerous errors in the assessment, and because the government has not provided appropriate supporting documentation for the assessment. As a result, the Company currently expects no material adverse impact on its results of operations or cash flows as a result of the ultimate resolution of this matter. No amounts have been accrued for this assessment as of ~~September 30, 2014~~March 31, 2015 as no loss is currently determinable nor considered probable.

Environmental Matters

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

The Company is engaged in site cleanup under the Voluntary Cleanup Plan of the Texas Commission on Environmental Quality ("TCEQ") at a former manufacturing location in Houston, Texas and had been engaged in one at a former manufacturing location in Missouri City, Texas. With respect to the Missouri City site, the Company ~~was notified in 2014 by~~received a Certificate of Completion from the TCEQ ~~that it may discontinue and decommission the ground-water treatment system there in preparation for site closure.~~on February 17, 2015. With respect to the Houston site, 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 on property values of the underground water contamination and its public disclosure led to a number of claims by homeowners. The Company has settled these claims, primarily as a result of the settlement of a class action lawsuit, and is obligated to reimburse approximately 190 homeowners for any diminution in value of their property due to contamination concerns at the time of the property's sale. Test results of monitoring wells on the southeastern border of the plume indicate that the plume is moving in a new direction, likely as a result of a ground water drainage system completed as part of an interstate highway improvement project. As a result, the Company notified 39 additional homeowners, and may provide notice to additional homeowners, whose property is adjacent to the class area that their property may be affected. The Company continues to monitor the situation to determine whether additional remedial measures would be appropriate. The Company believes, based on its review of the facts and law, that any potential exposure from existing agreements as well as any possible new claims that may be filed with respect to this underground water contamination will not have a material adverse effect on its financial position or results of operations. The Company's Consolidated Condensed Balance Sheet included a noncurrent liability of approximately $7 million for these matters as of ~~September 30, 2014.~~March 31, 2015.

Additionally, the Company has ~~discontinued~~ceased operations at a number of other sites which had been active for many years and which may have yet undiscovered contamination. The Company does not believe, based upon information currently available, that there are any material environmental liabilities existing at these locations. At ~~September 30, 2014,~~March 31, 2015, the Company's Consolidated Condensed Balance Sheet included a noncurrent liability of nearly $3 million for these environmental matters.

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Note 14: 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, non-qualified benefit plan assets, trade payables, derivative instruments and debt instruments. ~~The~~Due to the short-term nature of each, the book values of trade receivables, trade payables and ~~floating-rate debt instruments~~commercial paper are considered to be representative of their respective fair values.

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 ~~September 30,~~both March 31, 2015 and December 31, 2014, the fair value of the Company's fixed-rate debt (based on Level 1 quoted market rates) was approximately ~~$3.0~~$2.9 billion as compared to the ~~nearly $2.8~~$2.7 billion face value of the debt recorded, net of original issue discounts, in the Company's Consolidated Condensed Balance Sheet. ~~At December 31, 2013, the fair value of the Company's fixed-rate debt (based on Level 1 quoted market rates) was approximately $2.7 billion as compared to the $2.5 billion face value of the debt.~~

Derivative Contracts

In order to mitigate the effect of exchange rate changes, the Company will often attempt to structure sales contracts to provide for collections from customers in the currency in which the Company incurs its manufacturing costs. In certain instances, the Company will enter into foreign currency forward contracts to hedge specific large anticipated receipts or disbursements in currencies for which the Company does not ~~expect to~~ have fully offsetting local currency expenditures or receipts. The Company was party to a number of ~~short- and~~ long-term foreign currency forward contracts at ~~September 30, 2014.~~March 31, 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.~~projects. Many of these contracts have been designated as and are accounted for as cash flow hedges with changes in the fair value of those contracts recorded in accumulated other elements of comprehensive income (loss) in the period such change occurs. Certain other ~~forward and option~~ contracts, many of which are centrally managed, are intended to offset other foreign currency exposures but have not been designated as hedges for accounting purposes and, therefore, any change in the fair value of those contracts isare reflected in earnings in the period such change occurs. The Company determines the fair value of its outstanding foreign currency forward ~~and option~~ contracts based on quoted exchange rates for the respective currencies applicable to similar instruments.

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The Company manages its debt portfolio to achieve an overall desired position of fixed and floating rates and employs from time to time interest rate swaps as a tool to achieve that goal.

Total gross volume bought (sold) by notional currency and maturity date on open derivative contracts at ~~September 30, 2014~~March 31, 2015 was as ~~follows (in millions):~~follows:

	Notional Amount - Buy										Notional Amount - Sell												Notional Amount - Buy								Notional Amount - Sell
	2014		2015		2016		2017		Total		2014			2015			2016			Total
(amounts in millions)																							2015		2016		2017		Total		2015			2016			Total
Foreign exchange forward contracts -
Notional currency in:
Euro		103		79		14		–		196		(44	)		(5	)		(1	)		(50	)		236		14		–		250		(51	)		–			(51	)
Malaysian ringgit		46		260		3		–		309		–			(20	)		–			(20	)		319		51		–		370		(47	)		–			(47	)
Norwegian krone		293		675		103		4		1,075		(70	)		(69	)		–			(139	)		580		184		4		768		(63	)		(54	)		(117	)
Pound sterling		97		23		5		–		125		(52	)		(22	)		(1	)		(75	)
Pound Sterling																								150		9		–		159		(28	)		(1	)		(29	)
U.S. dollar		29		7		–		–		36		(330	)		(456	)		(47	)		(833	)		61		–		–		61		(481	)		(137	)		(618	)

Foreign exchange option contracts -
Notional currency in:
Euro		29		87		–		–		116		–			–			–			–
U.S. dollar																								13		–		–		13		–			–			–

While the Company ~~reports~~ and ~~generally settles~~ its ~~individual~~counterparties have the right to offset gains and losses on different derivative ~~financial instruments~~contracts under certain circumstances, the Company's policy is to record its derivative contracts 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.basis. The fair values of derivative financial instruments recorded in the Company's Consolidated Condensed Balance Sheets at ~~September 30, 2014~~ ~~and December 31, 2013~~ were as ~~follows (in millions):~~follows:

	September 30, 2014				December 31, 2013
	Assets		Liabilities		Assets		Liabilities		March 31, 2015				December 31, 2014

(dollars in millions)									Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments:
Current	$	6	$	34	$	28	$	10	$	12	$	104	$	8	$	83
Non-current		1		6		3		2		1		13		1		12
Total derivatives designated as hedging instruments		7		40		31		12
Derivatives designated as hedges										13		117		9		95

Derivatives not designated as hedging instruments:
Current		3		13		6		6		–		15		1		14
Non-current		–		–		–		–		–		–		–		–
Total derivatives not designated as hedging instruments		3		13		6		6
Derivatives not designated as hedges										–		15		1		14

Total derivatives	$	10	$	53	$	37	$	18	$	13	$	132	$	10	$	109

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

	Three Months Ended						Nine Months Ended						Three Months Ended March 31,
	September 30,						September 30,
	2014			2013			2014			2013

(dollars in millions)													2015			2014
Derivatives designated as hedging instruments -
Cost of sales	$	(4	)	$	3		$	(3	)	$	2		$	(3	)	$	1

Derivatives not designated as hedging instruments -
Cost of sales		(6	)		7			(4	)		3			(19	)		2
Other costs		(4	)		(1	)		(4	)		(1	)		(12	)		–
	$	(14	)	$	9		$	(11	)	$	4		$	(34	)	$	3

Note 15: Recently Issued Accounting Pronouncements

~~Revenue~~

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

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

·•	identify performance obligations in each contract,

·•	estimate the amount of variable consideration to include in the transaction price, and

·•	allocate the transaction price to each separate performance obligation.

ASU 2014-09 ~~will~~was initially scheduled to be effective for Cameron no earlier than the first quarter of ~~2017.~~2017, however, on April 1, 2015, the FASB voted to propose to defer the effective date by one year. It is expected the proposed rule to defer the effective date will be finalized during the second quarter of 2015. The Company is beginning the process of evaluating the impact of the new standard on its business and addressing whether it will select either the full retrospective or the modified retrospective implementation method upon the expected adoption ~~in 2017.~~date of January 1, 2018.

~~Discontinued operations~~

~~The FASB issued Accounting Standards Update 2014-08,~~ ~~Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity~~ ~~(ASU 2014-08) in April 2014.~~

~~This new standard:~~

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

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

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

~~The Company expects to adopt the new standard when it becomes effective in the first quarter of 2015.~~

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

In addition to the historical data contained herein, this ~~document includes~~Quarterly Report, including the information set forth in the Company's Management's Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report, may include 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, but 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; warranty and product liability claims; the impact of acquisitions the Company has made or may make; the potential impairment of goodwill related to such acquisitions; 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.~~results. 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.

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

Market Conditions

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

	Three Months Ended September 30,				Increase (Decrease)						Three Months Ended March 31,				Increase (Decrease)
	2014		2013		Amount			%			2015		2014		Amount			%
Drilling activity (average number of working rigs during period)⁽¹⁾:
Drilling activity (average number of working rigs during period)⁽¹⁾:
United States		1,903		1,769		134			7.6	%		1,380		1,780		(400	)		(22.5	)%
Canada		385		349		36			10.3	%		309		526		(217	)		(41.3	)%
Rest of world		1,348		1,285		63			4.9	%		1,261		1,337		(76	)		(5.7	)%
Global average rig count		3,636		3,403		233			6.8	%		2,950		3,643		(693	)		(19.0	)%

Commodity prices (average of daily U.S. dollar prices per unit during period)⁽²⁾:
West Texas Intermediate Cushing, OK crude spot price per barrel in U.S. dollars	$	97.60	$	105.82	$	(8.22	)		(7.8	)%
Henry Hub natural gas spot price per MMBtu in U.S. dollars	$	3.93	$	3.56	$	0.37			10.4	%
Twelve-month futures strip price (U.S. dollar amount at period end)⁽²⁾:
West Texas Intermediate Cushing, OK crude oil contract (per barrel)	$	88.68	$	97.81	$	(9.13	)		(9.3	)%
Henry Hub natural gas contract (per MMBtu)	$	4.01	$	3.80	$	0.21			5.5	%

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)											$	48.49	$	98.65	$	(50.16	)		(50.8	)%
Brent crude oil spot price (per barrel)											$	59.87	$	105.54	$	(45.67	)		(43.3	)%
Henry Hub natural gas spot price (per MMBtu)											$	2.87	$	5.16	$	(2.29	)		(44.4	)%
Twelve-month futures strip price (U.S. dollar amount at period end)⁽²⁾:
West Texas Intermediate (WTI) Cushing, OK crude oil contract (per barrel)											$	53.30	$	96.71	$	(43.41	)		(44.9	)%
Brent crude oil contract (per barrel)											$	55.11	$	107.76	$	(52.65	)		(48.9	)%
Henry Hub Natural Gas contract (per MMBtu)											$	2.91	$	4.46	$	(1.55	)		(34.8	)%
Contracted drillships and semi-submersibles by location at period-end⁽³⁾:
U.S. Gulf of Mexico		48		41		7			17.1	%		48		45		3			6.7	%
Central and South America		66		81		(15	)		(18.5	)%		66		72		(6	)		(8.3	)%
Northwestern Europe		44		45		(1	)		(2.2	)%		42		46		(4	)		(8.7	)%
West Africa		46		40		6			15.0	%		36		44		(8	)		(18.2	)%
Southeast Asia and Australia		28		24		4			16.7	%
Far East, Southeast Asia and Australia												33		38		(5	)		(13.2	)%
Indian Ocean												14		16		(2	)		(12.5	)%
Other		51		49		2			4.1	%		25		20		5			25.0	%
Total		283		280		3			1.1	%		264		281		(17	)		(6.0	)%

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

⁽²⁾ Source: Bloomberg

⁽³⁾ Source: ~~ODS-Petrodata Ltd.~~IHS Energy - IHS Petrodata World Rig Forecast

~~The increase~~Worldwide drilling activity declined significantly in ~~average worldwide operating rigs during~~most major regions of the ~~third quarter of 2014 as compared to the third quarter of 2013 was primarily due to an increase in North American rigs drilling for oil and higher activity levels in~~world, except the Middle East, ~~and Asia Pacific regions.~~

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

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~~Natural gas (Henry Hub) prices were fairly consistent throughout the third quarter of 2014, averaging $3.93 per MMBtu, which is a 10% increase~~2015, as compared to the same period in ~~2013.~~2014, as well as from the end of the fourth quarter of 2014, mainly as a result of the sharp drop in commodity prices that began during the latter half of 2014 and continued into the first quarter of 2015, and the resulting 2015 capital spending cuts announced by many of the largest oil and gas production companies. Average worldwide working rig levels at the end of the first quarter of 2015 were down 28% from December 2014 and were at their lowest levels in the last six years. Although the Company has a substantial backlog of work that is scheduled to be executed during 2015, these declines in commodity prices and drilling activity levels have already had and will continue to have a negative impact on future demand for our products and services and our future revenues and earnings. Based on the 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 ~~12-month~~Company cannot predict the duration or depth of this down cycle.

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In the United States, rigs drilling for oil in the first quarter of 2015 were down 24% from the first quarter of 2014, down 46% at quarter-end from year-end 2014 rig count levels, and, at the end of the quarter, were at their lowest levels since the first quarter of 2011. The number of rigs drilling for gas in the United States during the first quarter of 2015 was 16% lower than the first quarter of 2014 and, at quarter-end, was down 31% from year-end 2014 levels. Gas rig count levels in the United States at the end of the first quarter of 2015 were at their lowest levels in the last quarter of a century.

The decrease in the Canadian rig count during the first quarter of 2015 as compared to the first quarter of 2014 was due largely to a decrease of 57% in the number of rigs drilling for oil. Rigs drilling for gas were also down 13% during those same periods. At the end of the first quarter of 2015, the number of rigs drilling for oil in Canada was at a six-year low.

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 and the Asia Pacific region.

Crude oil and natural gas prices continued moving downward during the first quarter of 2015 as a result of weak demand and excess supply, among other factors. WTI prices at the end of the first quarter of 2015 have declined 56% since their high of over $107 per barrel in July 2014, including a drop of nearly 11% since year-end 2014. The twelve-month futures price for WTI crude oil at March 31, 2015, however, was approximately 12% higher than spot prices at the end of the quarter.

Brent crude prices reached a high of almost $112 per barrel in June 2014 before dropping nearly 47% by the end of the first quarter of 2015, including a drop of 4% since year-end 2014. The twelve-month futures price for Brent crude as of March 31, 2015 was 7% lower than the closing spot price on that date of $59.51.

Natural gas prices as of the end of the first quarter of 2015 have declined 49% from an average of $5.16 per MMBtu during the first three months of 2014. This includes a 12% drop in the spot price since the end of 2014. The twelve-month futures strip price for natural gas at ~~September 30, 2014~~March 31, 2015 was ~~$4.01~~$2.91 per MMBtu at Henry Hub, which ~~is comparable to~~was 11% higher than the spot price at ~~September 30, 2014.~~that date of $2.62.

The total number of drillships and semi-submersibles ~~available for contract and~~ under contract ~~were generally consistent with~~at March 31, 2015 was down from the ~~same period of~~ prior year ~~with some redeployment occurring away from Central and South America~~due to the ~~U.S. Gulf~~decline in commodity prices and drilling activity that began in the latter half of ~~Mexico and certain other regions~~2014. The utilization of the ~~world.~~

~~Consolidated Results~~

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

Net income attributable to Cameron stockholders for the third quarter of 2014 totaled $225 million, compared to $189 million for the third quarter of 2013. Earnings from continuing operations per diluted share totaled $1.10 for the third quarter of 2014, compared to $0.72 per diluted share for the third quarter of 2013. Included in the third quarter 2014 results were certain costs, totaling $0.07 per diluted share, primarily associated with:

~~a loss on disposal of non-core assets,~~

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

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

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

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

~~Total revenues for the Company increased $361 million, or 15.6%, during the three months ended~~ ~~September 30, 2014~~ ~~as compared to the three months ended~~ ~~September 30, 2013~~. Nearly 94% of the increase was attributable to higher revenues in the Drilling & Production Systems (DPS) segment, reflecting improved performance across each major product line. Revenues in the Valves & Measurement (V&M) segment were up 10% compared to the same period last year, mainly as a result of increased sales of engineered and distributed valves, while PCS segment revenues, excluding discontinued operations, were down nearly 15%.

As a percent of revenues, cost of sales (exclusive of depreciation and amortization) increased from 71.2% during the third quarter of 2013 to 71.5% for the third quarter of 2014, mainly as a result of lower product margins in the V&M and PCS segments as described further below under "Segment Results".

~~Selling and administrative expenses decreased $5 million, or 1.5%, during the three months ended September 30, 2014 as compared to the three months ended~~ September 30, 2013. Selling and administrative expenses were 11.9% of revenues for the third quarter of 2014, down from 14.0% for the third quarter of 2013, reflecting the impact of cost control efforts.

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

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

Other costs totaled $19 million for the three months ended September 30, 2014 as compared to costs of $14 million for the three months ended September 30, 2013. See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information on the nature of these items.

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

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

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

~~Segment Results~~

~~DPS Segment –~~

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

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

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

~~Revenues~~

Increased shipments and higher manufacturing activity associated with high beginning-of-the-period backlog levels, as well as higher aftermarket revenues resulting from an increasing base of installed equipment, led to a 36% increase in drilling equipment revenues and a 15% increase in subsea equipment revenues during the third quarter of 2014 as compared to the third quarter of 2013.

Also contributing to the improvement in segment revenues was an 8% increase in surface equipment revenues, largely as a result of higher activity levels in the unconventional resource regions of North America.

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

~~The increase in the ratio of income from continuing operations before income taxes as a percent of revenues was primarily due to:~~

a 0.4 percentage-point decrease in the ratio of cost of sales to revenues resulting mainly from improved margins in the drilling equipment product line, largely related to growth in higher-margin land and jackup BOP activity and aftermarket business, as well as better cost recovery on rig projects,

a 0.4 percentage-point decrease in the ratio of depreciation and amortization expense to revenues due mainly a decline of nearly $7 million in intangible asset amortization expense in Drilling Systems, and

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

~~Orders~~

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

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

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

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

~~Backlog (at period-end)~~

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

~~a 7% decrease in drilling equipment backlog largely resulting from (i) the reversal of nearly $243 million in backlog in~~ the first quarter of 2014 as ~~the result of~~more drillships became available without a ~~customer cancellation of a large drilling project award issued in 2012, and (ii) a softening~~contract. The utilization for semi-submersibles remained relatively flat across both periods as declines in the number of semi-submersibles being marketed and those under contract remained mostly in balance. At March 31, 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 ~~for newbuild jackup~~conditions, certain drilling contractors have previously announced plans to cold stack or scrap certain older rigs ~~and floaters, as well as~~

in their existing portfolio during 2015.

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

Partially offsetting these declines was a 28% increase in surface equipment backlog due to recent high order rates largely resulting from continued strong activity levels in the unconventional resource regions of North America and increased activity in recent periods in the Middle East, particularly in Saudi Arabia and Oman.

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~~V&M Segment –~~

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

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

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

~~Revenues~~

Favorable North American market conditions and the impact of businesses acquired in the last twelve months contributed to an increase of 15% in sales of distributed valves. Engineered valve sales increased 18% during the third quarter of 2014 as compared to the third quarter of 2013, due primarily to weak market conditions during the third quarter of 2013 which negatively impacted shipments during that period.

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

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

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

~~Orders~~

Overall, total segment orders increased slightly when compared to the same period last year. Distributed valve orders increased 23% reflecting higher activity levels in North America while certain large orders for metering equipment in the current period led to a 13% increase in demand for measurement products. Partially offsetting these increases was a 13% decline in engineered valve orders due mainly to project timing delays.

~~Backlog (at period-end)~~

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

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~~PCS Segment –~~

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

2013⁽¹⁾
$ %

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

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

⁽¹⁾~~Excluding discontinued operations~~

~~Revenues~~

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

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

~~The decrease in the ratio of income from continuing operations before income taxes as a percent of revenues was due primarily to:~~

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

a 0.9 percentage-point increase in the ratio of depreciation and amortization expense to revenues as a result of higher depreciation and amortization expense during the third quarter of 2014 in relation to lower revenues as compared to the same period last year.

~~Partially offsetting these cost increases was a 1.2 percentage-point decrease in the ratio of selling and administrative expenses to revenues as a result of the effects of cost control efforts.~~

~~Orders~~

~~The decrease in segment orders was due mainly to a large award received in the third quarter of 2013 for a CO~~₂ separation system for a floating production storage and offloading (FPSO) vessel to be located offshore Brazil, with no similar-size custom engineered project award received during the third quarter of 2014, partially offset by a large award during the third quarter of 2014 for a new cryogenic gas processing system.

~~Backlog (at period-end)~~

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

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~~Corporate Segment –~~

The loss from continuing operations before income taxes in the Corporate segment increased $2 million from $100 million in the third quarter of 2013 to $102 million in the third quarter of 2014. This increase was due largely to:

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

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

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

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

~~Market Conditions~~

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

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

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

Commodity prices (average of daily U.S. dollar prices per unit during period)⁽²⁾:

West Texas Intermediate Cushing, OK crude spot price per barrel in U.S. dollars $ 99.77 $ 98.17 $ 1.60 1.6 %
Henry Hub natural gas spot price per MMBtu in U.S. dollars $ 4.57 $ 3.70 $ 0.87 23.5 %

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

⁽²⁾~~Source: Bloomberg~~

The increase in average worldwide operating rigs during the first nine months of 2014 as compared to the first nine months of 2013 was driven primarily by higher North American oil drilling activity and higher activity levels in the Middle East and Asia Pacific regions and in Africa. Despite the improvement in natural gas pricing, the challenging economics associated with horizontal shale development drilling at current prices continues to constrain the overall rig market. The average number of rigs drilling for gas was down slightly in North America in the first nine months of 2014 as compared to the first nine months of 2013.

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

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

~~Consolidated Results~~

Consolidated net income for the first nine months of 2014 totaled $587 million, compared to $481 million for the first nine months of 2013. These amounts included $31 million and $42 million, respectively, of net income from discontinued operations for the nine months ended September 30, 2014 and 2013. Consolidated net income also includes $29 million and $3 million, respectively, of net income attributable to noncontrolling interests for the first nine months of 2014 and 2013.

Net income attributable to Cameron stockholders for the nine months ended September 30, 2014 totaled $558 million, compared to $478 million for the first nine months of 2013. Earnings from continuing operations per diluted share totaled $2.53 for the first nine months of 2014, compared to $1.77 per diluted share for the same period in 2013. Included in the results for the nine months ended September 30, 2014 were charges, net of certain gains, totaling $0.26 per diluted share, primarily associated with:

~~a goodwill impairment charge related to the PSE business and an impairment of certain intangible assets,~~

~~a loss on disposal of non-core assets,~~

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

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

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

The results for the first nine months of 2013 included after-tax charges of $0.36 per share, primarily related to formation costs for OneSubsea, including additional income tax expense incurred in connection with the formation, as well as currency devaluation, severance, restructuring and other costs.

~~Absent these costs in both periods, diluted earnings from continuing operations per share would have increased nearly 31% as compared to the first nine months of 2013.~~

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

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

~~Selling and administrative expenses increased $50 million, or 5.4%, during the nine months ended September 30, 2014 as compared to the nine months ended~~ September 30, 2013. This increase was primarily due to higher business activity levels in the DPS segment, along with the impact of additional costs from newly acquired businesses. Selling and administrative expenses were 12.8% of revenues for the first nine months of 2014, down from 14.4% for the same period in 2013, reflecting the impact of cost control efforts in relation to the growth in revenues.

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Depreciation and amortization expense totaled $256 million for the nine months ended September 30, 2014 as compared to $211 million for the nine months ended September 30, 2013, an increase of $45 million. The increase was due mainly to higher depreciation expense as a result of recent increased levels of capital spending, primarily in the DPS segment, and the impact of additional depreciation and acquired intangible amortization expense associated mainly with businesses acquired from Schlumberger in connection with the formation of OneSubsea, partially offset by a $7 million decrease in intangible asset amortization in Drilling Systems.

Net interest increased $24 million, from $74 million during the first nine months of 2013 to $98 million during the first nine months of 2014, mainly resulting from additional interest associated with (i) $750 million of new senior notes issued by the Company in December 2013 and (ii) $500 million of new senior notes issued in June 2014.

Other costs, net of credits, totaled $62 million for the nine months ended September 30, 2014 as compared to $80 million for the nine months ended September 30, 2013, a decrease of $18 million. See Note 3 of the Notes to Consolidated Condensed Financial Statements for further information on the nature of these items.

The effective income tax rate for the first nine months of 2014 was 24.4% as compared to 23.7% for the first nine months of 2013. The components of the effective tax rates for both periods were as follows (dollars in millions):

~~Segment Results~~

~~DPS Segment –~~

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

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

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

~~Revenues~~

Businesses acquired since the beginning of 2013 accounted for 21% of the revenue increase for the segment. Absent this impact, increased shipments and higher manufacturing activity associated with high beginning-of-the-year backlog levels, as well as higher aftermarket revenues resulting from an increasing base of installed equipment, led to a 37% increase in drilling equipment revenues and a 19% increase in subsea equipment revenues during the first nine months of 2014 as compared to the first nine months of 2013.

~~Table of Contents~~

Also contributing to the improvement in segment revenues was a 10% increase in surface equipment revenues, largely as a result of higher activity levels in the unconventional resource regions of North America as well as increased deliveries to customers operating in the North Sea.

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

~~The decrease in the ratio of~~ ~~income from continuing operations before income taxes~~ ~~as a percent of revenues was due primarily to a 0.6 percentage-point increase in the ratio of cost of sales to revenues resulting mainly from:~~

~~a mix shift to a higher proportion of subsea project revenues, which inherently carry lower margins than surface equipment revenues, and~~

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

Mostly offsetting this was a net reduction of 0.4 percentage-points in the combined ratios of depreciation and amortization expense and selling and administrative expenses to revenues, mainly as a result of the effects of cost controls on selling and administrative expenses in relation to the growth in revenues.

~~Orders~~

The decrease in total segment orders was primarily due to a 47% decrease in subsea orders, mainly as a result of certain large project awards received during the first nine months of 2013, with no similar-sized large awards received during the first nine months of 2014, including (i) an award received from Petrobras for subsea trees and associated equipment for use in Pre- and Post-Salt basins offshore Brazil, (ii) a large booking to supply subsea production systems to a project offshore Nigeria, and (iii) an award received from Chevron for the Rosebank project in the UK North Sea. During 2014, customers have continued to evaluate project economics and field layout designs which have had an impact on the timing of new awards.

~~Partially offsetting the decline in subsea orders was:~~

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

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

~~V&M Segment –~~

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

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

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

~~Revenues~~

Overall, segment revenues for the nine months ended September 30, 2014 were relatively flat when compared to the same period last year. Sales of distributed valves and measurement products increased 10% and 15%, respectively, mainly as a result of continued strength in the North American market. Largely offsetting these increases were sales declines of 5% and 9% for engineered valves and process valves, respectively, due largely to project slippage, recent order weakness and delayed timing of valve deliveries due to various customer changes.

~~Table of Contents~~

~~Income before income taxes as a percent of revenues~~

~~The decrease in the ratio of~~ ~~income from continuing operations before income taxes~~ ~~as a percent of revenues was primarily attributable to:~~

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

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

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

~~Orders~~

Overall, total segment orders were relatively flat when compared to the same period last year. Distributed valve orders increased 19% as a result of higher North American activity levels. This was largely offset by declines of approximately 11% and 15% in both engineered and process valve orders, respectively, due mainly to project slippage and lower new pipeline project activity levels in North America.

~~PCS Segment –~~

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

2013⁽¹⁾
$ %

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

Orders $ 465 $ 533 $ (68 ) (12.8 )%

⁽¹⁾~~Excluding discontinued operations~~

~~Revenues~~

The revenue decrease in the PCS segment was due primarily to the timing of manufacturing activity on large international custom engineered processing equipment projects and weaker demand from North American customers for wellhead and midstream processing applications.

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

~~The decrease in the ratio of income from continuing operations before income taxes as a percent of revenues was due primarily to:~~

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

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

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

~~Orders~~

~~The decrease in segment orders was due mainly to a large award received in the first nine months of 2013 for a CO~~₂ separation system for a floating production storage and offloading (FPSO) vessel to be located offshore Brazil, with no similar-size custom engineered project award received during the first nine months of 2014.

~~Corporate Segment –~~

The loss from continuing operations before income taxes in the Corporate segment decreased $38 million from $329 million in the first nine months of 2013 to $291 million in the first nine months of 2014. This decrease was due largely to:

a combined $48 million decline in depreciation and amortization expense and in selling and administrative expenses, mainly reflecting the effects of cost control efforts which have lowered employee-related costs, including travel, information technology and other facility costs, and

~~an $18 million decrease in other costs, as described further in Note 3 of the Notes to Consolidated Condensed Financial Statements.~~

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

~~Liquidity and Capital Resources~~

~~Consolidated Condensed Statements of Cash Flows~~

During the first nine months of 2014, net cash provided by operations totaled $255 million, an increase of $49 million from the $206 million of cash provided by operations during the first nine months of 2013. The 2014 amount was negatively impacted by approximately $95 million of tax payments made during the third quarter associated with the pre-tax gain recognized on the sale of the Reciprocating Compression business.

Cash totaling $532 million was used for working capital during the first nine months of 2014 compared to $464 million during the first nine months of 2013, an increase of $68 million. During the first nine months of 2014, approximately $283 million of cash was used to build inventory levels, primarily in the DPS segment, in order to meet the demands from the high backlog and activity levels in that business segment. The timing of payments to third parties and annual employee incentive payouts, as well as lower advances received from customers, during the first nine months of 2014 also contributed to a use of cash totaling $291 million for the period.

Cash provided by investing activities was $218 million for the first nine months of 2014. In June 2014, the Company received $547 million of cash, net of transaction costs, from the sale of the Reciprocating Compression business to General Electric. Additionally, capital spending during the first nine months of 2014 totaled $259 million. Capital needs in the Surface Systems and OneSubsea divisions of the DPS segment, along with continued development of the Company's enhanced business information systems, accounted for almost three-quarters of the 2014 capital spending.

~~Table of Contents~~

Net cash used for financing activities totaled approximately $1.2 billion for the first nine months of 2014. Approximately $1.6 billion of cash was used to acquire nearly 25 million shares of treasury stock during the first nine months of 2014. In 2014, the Board of Directors authorized the Company to initiate a commercial paper program with authority to issue up to $500 million in short-term debt. Under this program, the Company issued commercial paper totaling $350 million in principal amount for use in funding the treasury stock purchases referred to above and for other corporate needs. The average term of the outstanding commercial paper as of September 30, 2014 was approximately 26 days. The Company currently anticipates being able to continue to issue new commercial paper to fund or extend outstanding commercial paper as it comes due for payment. During June 2014, the Company repaid $250 million of floating rate notes upon maturity and issued a total of $500 million of new senior notes split equally between 3- and 10-year maturities. Additionally, the Company in July 2014, spent $253 million, which included a make-whole premium plus accrued interest, to redeem early $250 million principal amount of 1.6% Senior Notes.

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

~~Future liquidity requirements~~

At September 30, 2014, the Company had nearly $1.2 billion of cash, cash equivalents and short-term investments. Approximately $479 million of the Company's cash, cash equivalents and short-term investments at September 30, 2014 were in the OneSubsea venture. Dividends of available cash from OneSubsea to the venture partners, 40% of which would go to Schlumberger, require approval of the OneSubsea Board of Directors prior to payment. Of the remaining cash, cash equivalents and short-term investments not held by OneSubsea, $184 million was located in the United States.

Total debt at September 30, 2014 was nearly $3.2 billion, most of which was in the United States. Excluding capital leases, approximately $890 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 2018 and 2043.

Excluding discontinued operations, the Company's backlog decreased approximately 4% from December 31, 2013, mainly due to the cancellation of a large drilling project award in the first quarter of 2014 totaling nearly $243 million, as well as weakness in current year-to-date order rates. Orders during the first nine months of 2014 were down nearly 14% from the same period in 2013 due mainly to certain large subsea project awards received in the first nine months of 2013 that did not repeat during the first nine months of 2014. The timing of such large project awards are inconsistent period-over-period. The Company views its backlog of unfilled orders, current order rates, current rig count levels and current and future expected oil and gas prices to be, in varying degrees, leading indicators of and factors in determining its estimates of future revenues, cash flows and profitability levels. Information regarding actual 2014 and 2013 average rig count and commodity price levels and forward-looking twelve-month market-traded futures prices for crude oil and natural gas are shown in more detail under the captions "Market Conditions" above. A more detailed discussion of third quarter and year-to-date orders and September 30 backlog levels by segment may be found under "Segment Results" for each period above. The Company also expects full year capital spending on new equipment and facilities to be approximately $425 million for 2014, down from $520 million during 2013.Goodwill Impairment

The Company believes, based on its current financial condition, existing backlog levels, which are still at historically high levels, and current expectations for future market conditions, that it will be able to meet its short- and longer-term liquidity needs with existing cash, cash equivalents and short-term investments on hand, expected cash flow from future operating activities and amounts available for borrowing under its $835 million five-year multi-currency Revolving Credit Facility, which matures on June 6, 2016, and its new three-year $750 million Revolving Credit Facility, described further in Note 8 of the Notes to Consolidated Condensed Financial Statements. Up to $200 million of this new facility may be used for letters of credit. The Company also has a bi-lateral $40 million facility with a third-party bank, expiring on February 2, 2015. At September 30, 2014, no amounts had been borrowed under the $835 million facility. The Company had issued letters of credit totaling $72 million under the new $750 million Revolving Credit Facility and $25 million under the $40 million bi-lateral facility, leaving $678 million and $15 million, respectively, available for future use. The Company also believes, based on its existing current credit standing, that it will be able to continue to refinance existing debt upon maturity, if desired.

~~Table of Contents~~

The Company has an authorized stock repurchase program whereby the Company may purchase shares directly or indirectly by way of open market transactions or structured programs, including the use of derivatives, for the Company's own account or through commercial banks or financial institutions. The program, initiated in October 2011, has had a series of authorizations by the Board of Directors totaling $3.8 billion since inception. At September 30, 2014, the Company had remaining authority for future stock purchases totaling approximately $665 million.

~~Critical Accounting Policies~~

~~Goodwill – During the first quarter of each annual period, the Company reviews~~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. The estimated fair value of each reporting unit is primarily determined using discounted future expected cash ~~flow models (level~~flows (Level 3 unobservable inputs) consistent with the accounting guidance for ~~fair value~~fair-value measurements. Certain estimates and judgments are required in the application of the ~~discounted cash flow~~fair value models, including, but not limited to, estimates of future cash flows and the selection of a discount rate. At March 31, 2015, the Company's reporting units for goodwill impairment testing purposes were OneSubsea, Process Systems, Surface, Drilling, Valves, and Measurement.

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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.

With respect to the Process Systems reporting unit, our determination of fair value as of March 31, 2015 considered events that occurred in the first quarter, as well as our updated long-term outlook for this reporting unit. Those events included ongoing changes in the energy industry during the first quarter of 2015, a 42% reduction in North American rig count, numerous industry-wide deepwater project deferrals and idling of deepwater drilling rigs, as well as significant capital spending cuts announced by a number of oil and gas exploration companies since December 31, 2014. Consistent with these industry-wide market changes, the Company also experienced the loss or indefinite deferral of several major project awards that we previously anticipated receiving. Accordingly, when determining the fair value of the Process Systems reporting unit as of March 31, 2015, our projections considered these factors as well as the negative impact of the low commodity price environment on the long-term outlook for revenue growth and profitability in this business. Based on these considerations, we concluded the fair value (estimated using Level 3 unobservable inputs) of the Process Systems reporting unit was less than its carrying value as of March 31, 2015. We conducted a Step 2 analysis, which included a hypothetical purchase price allocation, and recorded a goodwill impairment charge of $517 million. As of March 31, 2015, following the impairment, the Process Systems reporting unit had $53 million of goodwill remaining.

Consolidated Results

Net income attributable to Cameron stockholders for the first quarter of 2015 totaled $49 million, compared to $111 million for the first quarter of 2014. Included in the results for the first quarter of 2015 were asset impairment charges of $553 million, including the charge taken for impairment of goodwill in the Company's Process Systems business, as described above, and income from discontinued operations of $429 million. Discontinued operations include the Company's Reciprocating Compression business sold in June 2014 and the Centrifugal Compression business sold effective January 1, 2015. The income from discontinued operations in the first quarter of 2015 primarily represents the gain on the sale of Centrifugal Compression.

Losses from continuing operations per diluted share attributable to Cameron stockholders totaled $1.97 in the first quarter of 2015, compared to $0.49 of income from continuing operations for the same period in 2014, primarily reflecting the impact of the asset impairment charges in the first quarter of 2015. The 2015 gain on the sale of Centrifugal Compression was primarily responsible for earnings from discontinued operations per diluted share increasing from $0.02 per share during the first quarter of 2014 to $2.22 per share for the first quarter of 2015.

Absent the asset impairment charges and certain other costs described in Note 3 and discontinued operations, earnings from continuing operations per diluted share attributable to Cameron stockholders would have been $0.91 during the first three months of 2015, compared to $0.70 during the first three months of 2014, an increase of approximately 30%.

Total revenues for the Company decreased $56 million, or 2%, during the first quarter of 2015 as compared to the same period in 2014, as decreases in market-driven activity levels impacting the Subsea and V&M segments more than offset revenue increases in the Drilling segment.

As a percent of revenues, cost of sales (exclusive of depreciation and amortization) decreased from 72.6% during the first quarter of 2014 to 70.7% for the first quarter of 2015, mainly as a result of better project margins in the Subsea and Drilling segments. Comments regarding margins in the Management's Discussion and Analysis of Financial Condition and Results of Operations refer to Revenues minus Cost of Sales (exclusive of depreciation and amortization) as shown separately on the Company's Consolidated Condensed Statements of Comprehensive Income for each of the three-month periods ended March 31, 2015 and 2014.

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Selling and administrative expenses decreased $32 million, or 10%, during the first quarter of 2015 as compared to the first quarter of 2014. Selling and administrative expenses were 12.6% of revenues for the first quarter of 2015, down from 13.7% for the first quarter of 2014, reflecting the impact of cost control efforts throughout the Company.

Depreciation and amortization expense totaled $89 million during the three months ended March 31, 2015 as compared to $85 million during the three months ended March 31, 2014, an increase of $4 million. The increase was due primarily to higher depreciation expense in the Surface segment from previous spending on new rental fleet equipment.

Net interest increased $6 million, from $32 million during the first quarter of 2014 to $38 million during the first quarter of 2015, mainly as a result of $500 million of new senior notes issued in June 2014 and higher interest on capital leases.

In addition to asset impairment charges of $553 million, including the goodwill impairment charge described ~~further~~above, the Company incurred $24 million of other costs during the first quarter of 2015, as compared to $40 million for an asset impairment charge and $9 million of other costs in the first quarter of 2014. Further information regarding these items may be found in Note 23 of the Notes to Consolidated Condensed Financial Statements.

The Company's effective tax rate on income (loss) from continuing operations before income taxes for the first quarter of 2015 was a negative 16.3% compared to 29.0% for the first quarter of 2014. The components of the effective tax rates for both periods were as follows:


	Three Months Ended March 31,
	2015						2014
(dollars in millions)	Tax Provision			Tax Rate			Tax Provision			Tax Rate
Provision (benefit) based on international income (loss) distribution	$	(75	)		23.0	%	$	37			23.9	%
Adjustments to income tax provision (benefit):
Asset impairments with no tax benefit		127			(39.2	)		10			6.4
Finalization of prior year returns		–			–			(3	)		(1.9	)
Accrual adjustments and other		1			(0.1	)		1			0.6
Tax provision	$	53			(16.3	)%	$	45			29.0	%

Segment Results

Segment revenues and operating income before interest and income taxes represent the results of activities involving third-party customers and transactions with other segments. Segment operating income before interest and income taxes represents the profit remaining in the segment after deducting third-party and intersegment cost of sales, selling and administrative expenses and depreciation and amortization expense from third-party and intersegment revenues. For further information on the Company's segments, see Note 10 of the Notes to Consolidated Condensed Financial Statements ~~effective June 1, 2014, the Company completed the previously announced sale~~included in this Quarterly Report on Form 10-Q.

Table of its Reciprocating Compression business, a division of the Process and Compression Systems (PCS) segment, to General Electric for cash consideration of approximately $547 million, net of transaction costs. Reciprocating Compression had previously been included with the Process Systems and Equipment (PSE) business in the Process Systems & Reciprocating Compression reporting unit for goodwill impairment evaluation purposes. As a result of the classification of Reciprocating Compression as a discontinued operationContents

Subsea Segment

	Three Months Ended March 31,						Increase (Decrease)
(dollars in millions)	2015			2014			$				%

Revenues	$	631		$	681		$	(50	)		(7.3	)%
Segment operating income before interest and income taxes	$	57		$	29		$	28			96.6	%
Segment operating income before interest and income taxes as a percent of revenues		9.0	%		4.3	%		N/A		4.7 pts.

Orders	$	560		$	430		$	130			30.2	%
Backlog (at period-end)	$	4,101		$	4,805		$	(704	)		(14.7	)%

Revenues

Revenues decreased in the first quarter of 2015 as compared to the first quarter of 2014, ~~when a definitive agreement to sell the business was entered into, total reporting unit goodwill was allocated between the two businesses. Following this, the PSE business was evaluated~~primarily as a ~~separate reporting unit~~result of a slowdown in ~~connection with~~new product shipments, partially offset by strong growth in the ~~Company's annual goodwill impairment review conducted~~segment's Services business.

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

Segment operating income before interest and income taxes as a percent of revenues improved in the first quarter of 2015 as compared to the same period in 2014, due mainly to better margin performance resulting from higher pricing on projects in existing backlog and better project execution, as well as cost control efforts that resulted in a decrease in selling and administrative expenses and from lower depreciation and amortization expense in relation to revenues.

Orders

Orders increased during the first three months of 2015 as compared to the same period in 2014, primarily due to an award during the first quarter of 2015 for new subsea trees and related systems for a project offshore Egypt in comparison to the low level of subsea tree awards received during the first three months of 2014.

Backlog (at period-end)

A decline in new project awards, combined with higher revenues during the last twelve months, were the main drivers for the reduction in backlog levels at March 31, 2015 as compared to March 31, 2014.

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Surface Segment

	Three Months Ended March 31,						Increase (Decrease)
(dollars in millions)	2015			2014			$				%

Revenues	$	543		$	538		$	5			0.9	%
Segment operating income before interest and income taxes	$	92		$	91		$	1			1.1	%
Segment operating income before interest and income taxes as a percent of revenues		16.9	%		16.9	%		N/A		0.0 pts.

Orders	$	450		$	635		$	(185	)		(29.1	)%
Backlog (at period-end)	$	1,009		$	1,063		$	(54	)		(5.1	)%

Revenues

Revenues were relatively flat in the first quarter of 2015 as compared to the first quarter of 2014 as deliveries from backlog and international shipments have moderated the impact of lower activity levels in various North American unconventional resource regions as a result of the recent decline in commodity prices.

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 was flat in the first quarter of 2015 as compared to the same period last year as improved product margins were mostly offset by higher depreciation and amortization expense in relation to revenues.

Orders

Orders declined during the first three months of 2015 as compared to the first three months of 2014 reflecting 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 high levels experienced during the first three months of 2014.

Backlog (at period-end)

The decrease in segment backlog at March 31, 2015 as compared to March 31, 2014 largely reflects weakness in demand for new equipment over the last twelve months from customers in the North Sea and Algeria.

Drilling Segment

	Three Months Ended March 31,						Increase (Decrease)
(dollars in millions)	2015			2014			$				%

Revenues	$	726		$	667		$	59			8.8	%
Segment operating income before interest and income taxes	$	135		$	67		$	68			101.5	%
Segment operating income before interest and income taxes as a percent of revenues		18.6	%		10.0	%		N/A		8.6 pts.

Orders	$	267		$	817		$	(550	)		(67.3	)%
Backlog (at period-end)	$	2,864		$	4,050		$	(1,186	)		(29.3	)%

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Revenues

Revenues increased in the first quarter of 2015 as compared to the first quarter of 2014 driven mainly by better project execution of orders from the segment's substantial beginning-of-the-year backlog levels.

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

The significant increase in segment operating income before interest and income taxes as a percent of revenues in the first quarter of 2015 as compared to the same period last year was due primarily to better project execution and cost control efforts which led to a decrease in selling and administrative expenses as compared to the first quarter of 2014.

Orders

Order rates declined during the first three months of 2015 as compared to the first three months of 2014 as a result of a slowdown in rig construction activity (both offshore and onshore) in the first quarter of 2015, mainly reflecting current market conditions with respect to new drilling activity and lower discretionary spending plans by customers for new services.

Backlog (at period-end)

Backlog at March 31, 2015 decreased from March 31, 2014 mainly due to the slowdown in large rig construction and drilling stack project awards in 2014 and the first quarter of 2015, as described above, which, in total, have not kept pace with revenue arising from manufacturing activity levels on previously existing backlog.

V&M Segment

	Three Months Ended March 31,						Decrease
(dollars in millions)	2015			2014			$				%

Revenues	$	428		$	500		$	(72	)		(14.4	)%
Segment operating income before interest and income taxes	$	45		$	98		$	(53	)		(54.1	)%
Segment operating income before interest and income taxes as a percent of revenues		10.5	%		19.6	%		N/A		(9.1) pts.

Orders	$	388		$	536		$	(148	)		(27.6	)%
Backlog (at period-end)	$	810		$	1,057		$	(247	)		(23.4	)%

Revenues

Segment revenues declined in the first quarter of 2015 as compared to the first quarter of 2014, as lower North America upstream activity levels, resulting from a decline in commodity prices, resulted in lower sales of valves and measurement products. Additionally, shipment slippages on custom valve and measurement projects, due to various customer changes, negatively impacted sales.

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 quarter of 2015 as compared to the first quarter of 2014, primarily due to lower valve and measurement product margins and higher depreciation and amortization expense on lower volumes. Although selling and administrative expenses declined in the first quarter of 2015 as compared to the first quarter of 2014, the rate of decline was less than the rate of decline in revenues.

Orders

Orders for the first three months of 2015 reflected a significant decline when compared to the first quarter of 2014. Lower North America upstream activity levels and high distributor inventory levels reduced demand for valve and measurement products. Orders for services increased in the first quarter of 2015 as compared to first quarter of 2014, primarily due to strong Middle East customer operating expenditures on maintenance activities and Asia Pacific customer mid-stream commissioning activities.

Backlog (at period-end)

Backlog levels for the V&M segment decreased from March 31, 2014 to March 31, 2015, as recent order rates for custom valve and measurement products have not kept pace with recent deliveries.

Corporate Expenses

Corporate expenses were $23 million for the first quarter of 2015, a decline of $14 million from $37 million in the first quarter of 2014. The decrease was due primarily to lower employee compensation costs and the impact of cost control efforts on other governance activities.

Liquidity and Capital Resources

Consolidated Condensed Statements of Cash Flows

During the first three months of 2015, net cash used for operations totaled $193 million, an increase of $19 million from the $174 million of cash used for operations during the first three months of 2014.

Cash totaling $429 million was used to increase working capital during the first three months of 2015 compared to $448 million used during the first three months of 2014, a decrease of $19 million. During the first three months of 2015, $147 million of cash was generated from the net collection of receivables while $105 million was used to build inventory levels. The timing of payments to third parties and employee incentive payouts made in the first quarter of 2015 contributed to a use of cash totaling $471 million for the period.

Cash provided by investing activities during the first three months of 2015 was $437 million, compared to $99 million used for investing activities during the first three months of 2014. Net proceeds from the sale of the Centrifugal Compression business added $831 million in cash during the first quarter of 2015. During this same period, net cash of $311 was used to increase the Company's short-term investment balances. Additionally, capital spending declined from $105 million during the first three months of 2014 to $89 million for the first three months of 2015, reflecting current market conditions.

Net cash used for financing activities totaled $396 million for the first three months of 2015 compared to $564 million used during the first three months of 2014. Approximately $182 million of cash was used to acquire nearly 4 million shares of treasury stock and $201 million of cash was used to repurchase outstanding commercial paper during the first quarter of 2015. During the first quarter of 2014, the Company acquired over 15 million shares of treasury shares at a cost of approximately $902 million and issued commercial paper totaling $325.0 million in principal amount. The Company currently anticipates issuing new commercial paper from time to time in the future for general corporate needs.

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Future liquidity requirements

At March 31, 2015, the Company had $1.7 billion of cash, cash equivalents and short-term investments. Approximately $525 million of the Company's cash, cash equivalents and short-term investments at March 31, 2015 were in the OneSubsea venture. Dividends of available cash from OneSubsea to the venture partners require approval of the OneSubsea Board of Directors prior to payment. Of the remaining cash, cash equivalents and short-term investments, nearly $446 million was located in the United States. Total debt at March 31, 2015 was nearly $2.8 billion, most of which was in the United States. Excluding capital leases, nearly $517 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 July 2018 and December 2043.

Excluding discontinued operations, the Company's backlog decreased $752 million or nearly 8% from December 31, 2014. Orders during the first quarter of 2015 were down nearly 31% from the first quarter of 2014 due mainly to decreased activity levels as a result of the significant decline in commodity prices which began in mid-2014. The Company views its backlog of unfilled orders, current order rates, current rig count levels and current and future expected oil and gas prices to be, in varying degrees, leading indicators of and factors in determining its estimates of future revenues, cash flows and profitability levels. Information regarding actual first quarter 2015 and 2014 average rig count and commodity price levels and forward-looking twelve-month market-traded futures prices for crude oil and natural gas are shown in more detail under the caption "Recent Market Conditions" above. A more detailed discussion of orders and backlog by segment may be found under "First Quarter 2015 Compared to First Quarter 2014 - Segment Results" above. As a result of ~~this review,~~these and other factors, the ~~PSE goodwill~~Company currently anticipates declines in consolidated orders, backlog and revenues during the remainder of 2015 as compared to the same periods in 2014.

The Company believes, based on its current financial condition, existing backlog levels, which continue to be at significant levels, and current expectations for future market conditions, that it will be able to meet its short- and longer-term liquidity needs with existing cash, cash equivalents and short-term investments on hand, expected cash flow from future operating activities, amounts available for borrowing under its $835 million five-year multi-currency Revolving Credit Facility, which expires on June 6, 2016, and its three-year $750 million Revolving Credit Facility, expiring April 11, 2017. At March 31, 2015, no amounts had been borrowed under the $835 million facility and the Company had issued letters of credit totaling $45 million under the $750 million facility, leaving a remaining amount of $705 million available for future use.

The Company also believes its existing financial condition and debt ratings, absent significant unanticipated negative developments, allow it the ability to be able to refinance debt maturing within the next three to five years with future long-term debt issuances.

At March 31, 2015, the Company had remaining authority for future treasury stock purchases totaling approximately ~~$40 million, was fully impaired at that time.~~$298 million.

Factors That May Affect Financial Condition and Future Results

Downturns in the oil and gas industry have had, and will likely in the future have, a negative effect on the Company's sales and profitability.

Demand for most of the Company's products and services, and therefore its revenue, depends to a large extent upon the level of capital expenditures related to oil and gas exploration, development, production, processing and transmission. Declines, as well as anticipated declines, in oil and gas prices could negatively affect the level of these activities, or could result in the cancellation, modification or rescheduling of existing orders. ~~As examples,~~For example, oil prices began declining during the third quarter of 2014, ~~and have continued~~dropping nearly 56% for West Texas Intermediate crude from mid-year 2014 levels to ~~decline into the low-to-mid $80 range on the New York Mercantile Exchange~~under $48 per barrel as of March 31, 2015. Similarly, natural gas prices declined from an average of $5.16 per MMBtu during the first ~~half~~three months of ~~October 2014. This decline, if continuing, could~~2014 to $2.62 per MMBtu at March 31, 2015. These declines have already begun to, and are expected to continue to, significantly affect exploration and production activity levels and, therefore, demand for the Company's products and ~~services. Additionally, natural gas spot prices in~~services at least through the ~~United States declined during~~remainder of 2015. During the first ~~half~~quarter of ~~2012~~2015 there have been numerous deepwater projects deferred and deepwater rigs idled. In addition to ~~less than $2 per MMBtu,~~a decline in future orders and revenues, the ~~lowest level in the last decade. Although natural gas prices have subsequently increased, current rig count~~Company expects to incur additional costs as it seeks to adjust its commercial, manufacturing and support operations levels ~~associated with dry gas extraction activities have not fully recovered~~ to ~~previous levels. This price decline negatively impacted 2012 order levels by certain of the Company's customers which affected the Company's 2012 and 2013 revenues and profitability.~~meet expected future customer demand. See also the discussion in "Market Conditions" ~~above.~~above for the first quarter of 2015 as compared to the first quarter of 2014.

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Cancellation, downsizing or delays of orders in backlog are possible.

~~Table~~As described above, commodity prices have declined significantly since mid-2014 which has resulted in various oil and gas exploration and production companies announcing spending cuts or deferrals in their 2015 capital spending plans, as well as headcount reductions. At current price levels, certain projects, particularly those in deepwater environments and unconventional resource regions, may become uneconomical for the risk involved. Certain customers that are more highly leveraged may also experience concerns regarding future projected cash flows based on current price levels. These factors described above could result in existing orders in backlog being cancelled, downsized or future shipment dates may be delayed, all of ~~Contents~~

which could further negatively impact the Company's future profitability.

At March 31, 2015, the Company's backlog was approximately $8.8 billion, down nearly 8% from December 31, 2014. An example of a cancellation of an existing order is the reversal of $243 million of backlog during the first quarter of 2014 as the result of a customer cancellation of a large drilling project award issued in 2012. Another example of a potential delay or downsizing of a previous award is the announcement by Chevron in late 2013 of the deferral of its Rosebank project, which was awarded in 2013 and currently accounts for $488 million of the Company's ending backlog at March 31, 2015, in order to work with its partners to improve the project's economics. Although the original contract remains in place, OneSubsea is currently working with Chevron on a revised scope for the project based on a new field layout design.

The inability of the Company to deliver its backlog or future orders on time could affect the Company's ~~future~~ sales and profitability and its relationships with its customers.

~~At September 30, 2014, the Company's backlog was approximately $10.6 billion, excluding discontinued operations.~~ The ability to meet customer delivery schedules ~~for this~~on the Company's existing backlog, as well as future orders, is dependent on a number of factors including, but not limited to, access to the raw materials required for production, an adequately trained and capable workforce, project engineering expertise for large subsea projects, sufficient manufacturing plant capacity and appropriate planning and scheduling of manufacturing resources. Many of the contracts the Company enters into with its customers require long manufacturing lead times and contain penalty clauses relating to on-time delivery. A failure by the Company to deliver in accordance with customer expectations could subject the Company to financial penalties or loss of financial incentives and may result in damage to existing customer relationships. Additionally, the Company bases its earnings guidance to the financial markets on expectations regarding future order rates and the timing of delivery of product currently in backlog. Failure to deliver equipment in accordance with expectations could negatively impact the market price performance

Portions of the ~~Company's common stock~~backlog for our Subsea and ~~other publicly-traded financial instruments.~~Drilling segments are subject to heightened execution risk.

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

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

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

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

~~Cameron,~~ through ~~OneSubsea,~~our Subsea segment, is a significant participant in the subsea systems projects market. ~~This market is different from most~~Some of the ~~Company's other~~projects for these markets ~~since subsea systems projects are larger in~~carry heightened execution risk because of their scope and complexity, in terms of both technical and logistical requirements. ~~Subsea~~Such projects ~~typically~~ (i) may often involve long lead times, (ii) are larger in financial scope, (iii) require substantial engineering resources to meet the technical requirements of the project and (iv) often involve the application of existing technology to new environments and, in some cases, may require the development of new technology. ~~The~~As a subset of its total backlog at March 31, 2015, the Company's ~~OneSubsea business has~~Drilling segment had projects fitting this risk profile that amounted to approximately $1.4 billion. As a subset of its total backlog ofat March 31, 2015, the Company's Subsea segment had projects fitting this risk profile that amounted to approximately ~~$3.2 billion for subsea systems projects at September 30, 2014.~~$1.9 billion. To the extent the Company experiences unplanned difficulties in meeting the technical and/or delivery requirements of the projects, the Company's earnings or liquidity could be negatively impacted. The Company accounts for its drilling and subsea projects, as it does its separation ~~and drilling~~ projects, using accounting rules for construction-type and ~~production type~~production-type contracts. Factors that may affect future project costs and margins include the ability to properly execute the engineering and design phases consistent with our customers' expectations, production efficiencies obtained, and the availability and costs of labor, materials and subcomponents. These factors can impact the accuracy of the Company's estimates and materially impact the Company's future period earnings. If the Company experiences cost overruns, the expected margin could decline. Were this to occur, in accordance with the accounting guidance, the Company would record a cumulative adjustment to reduce the margin previously recorded on the related project in the period a change in estimate is determined. ~~Subsea~~Deepwater stack and jackup complete drilling packages and subsea systems projects accounted for approximately ~~5.7%~~14% and 12%, respectively, of total ~~revenues in the~~ first ~~nine months of 2014.~~quarter 2015 revenues.

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As a designer, manufacturer, installer and servicer of oil and gas pressure control equipment, the Company may be subject to liability for personal injury, property damage and environmental contamination should such equipment fail to perform to specifications.

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

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

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

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

The implementation of an upgraded business information system may disrupt the Company's operations or its system of internal ~~controls~~.controls.

The Company has a project underway to upgrade its SAP business information systems worldwide. The first stage of this multi-year effort was completed at the beginning of the third quarter of 2011 with the deployment of the upgraded system ~~for certain businesses within~~to the Company's ~~PCS segment.~~process systems and compression businesses. Since then, other businesses and business functions have been migrated in stages. ~~Effective October 1, 2014,~~As of March 31, 2015, nearly all businesses within the V&M segment, the Surface ~~Systems division,~~segment, the Company's worldwide engineering and human resource functions, as well as other corporate office activities are now operating inon the upgraded system. The Drilling ~~Systems division~~segment is scheduled to be migrated in the third quarter of 2015 and the OneSubsea business in 2016. The Drilling ~~Systems division~~segment and the OneSubsea business are major contributors to the Company's consolidated revenues and income before income taxes.

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

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

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

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

The Company has established multiple "Centers of Excellence" facilities for manufacturing such products as subsea trees, subsea chokes, subsea production controls and blowout preventers. These production facilities are located in the United Kingdom, Brazil, Romania, Italy, Norway and other European and Asian countries. To the extent the Company sells these products in U.S. dollars, the Company's profitability is eroded when the U.S. dollar weakens against the British pound, the euro, the Brazilian real and certain Asian currencies, including the Singapore dollar. Alternatively, profitability is enhanced when the U.S. dollar strengthens against these same currencies. For further information on the use of derivatives to mitigate certain currency exposures, see Item 3, "Quantitative and Qualitative Disclosures about Market Risk" below and Note 14 of the Notes to Consolidated Condensed Financial Statements.

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The Company's operations expose it to risks of non-compliance with numerous countries' import and export laws and regulations, and with various nations' trade regulations including U.S. sanctions.

The Company's operations expose it to trade and import and export regulations in multiple jurisdictions. In addition to using "Centers of Excellence" for manufacturing products to be delivered around the world, the Company imports raw materials, semi-finished goods and finished products into many countries for use in country or for manufacturing and/or finishing for re-export and import into another country for use or further integration into equipment or systems. Most movement of raw materials, semi-finished or finished products by the Company involves exports and imports. As a result, compliance with multiple trade sanctions and embargoes and import and export laws and regulations poses a constant challenge and risk to the Company. The Company has received a number of inquiries from U.S. governmental agencies, including the U.S. Securities and Exchange Commission and the Office of Foreign Assets Control, regarding compliance with U.S. trade sanction and export control laws, the most recent of which was received in December 2012 and replied to by the Company in January 2013. The Company has undergone and will likely continue to undergo governmental audits to determine compliance with export and customs laws and regulations.

The United States and the European Union (EU) also recently imposed sanctions on various sectors of the Russian economy and on transactions with certain Russian nationals and entities. These sanctions may severely limit the amount of future business the Company does with customers involved in activities in Russia. As of ~~September 30, 2014,~~March 31, 2015, approximately 1% of the Company's backlog from continuing operations related to future deliveries to customers doing business in Russia. ~~For the nine months ended September 30, 2014, customer~~Customer sales by the Company's continuing operations into Russia during the first quarter of 2015 totaled less than 1% of the Company's sales during ~~that period.~~the year. In addition, the sanctions of the U.S. and the EU are inconsistent and neither is, as yet, well defined, both of which factors increase the risk of an unintended violation.

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

The political and economic risks of doing business on a worldwide basis include the following:

•	volatility in general economic, social and political conditions;
•	the effects of civil unrest and, in some cases, military action on the Company's business operations, customers and employees, such as that recently occurring in several countries in the Middle East, in Ukraine and in Venezuela;
•	exchange controls or other similar measures which result in restrictions on repatriation of capital and/or income, such as those involving the currencies of, and the Company's operations in, Angola and Nigeria; and
•	reductions in the number or capacity of qualified personnel.

In recent months, civil unrest and military action have increased in Iraq which may impact the ability of that country to continue to produce and export oil at current levels. Such unrest may also jeopardize the Company's in-country investments and on-going business activities supporting Iraq's oil and gas production infrastructure. At ~~September 30, 2014,~~March 31, 2015, less than 1% of the Company's backlog related to future deliveries to customers doing business in Iraq. Additionally, less than 1% of the Company's property, plant and equipment were located in Iraq. The Company is also evaluating its options under the force majeure clauses of each of the major contracts with its customers doing business in Iraq in the event the current situation in that country continues to deteriorate.

Cameron also has manufacturing and service operations that are essential parts of its business in other developing countries and volatile areas in Africa, Latin America and other countries that were part of the Former Soviet Union, the Middle East, and Central and South East Asia. Recent increases in activity levels in certain of these regions have increased the Company's risk of identifying and hiring sufficient numbers of qualified personnel to meet increased customer demand in selected locations. The Company also purchases a large portion of its raw materials and components from a relatively small number of foreign suppliers in China, India and other developing countries. The ability of these suppliers to meet the Company's demand could be adversely affected by the factors described above.

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In addition, customers in countries such as Angola and Nigeria increasingly are requiring the Company to accept payments in the local currencies of these countries. These currencies do not currently trade actively in the world's foreign exchange markets.

The Company also has ~~various~~certain manufacturing and ~~aftermarket~~services operations in Venezuela that contributed ~~$54 million in~~less than 1% of the Company's consolidated revenues during the first ~~nine months~~quarter of ~~2014.~~2015. The economy in Venezuela is highly inflationary. As a result, the Company's operations in Venezuela are accounted for as having a U.S. dollar functional currency ~~entities~~ and the Company considers its earnings in Venezuela to be permanently reinvested. ~~Since~~Because of the ~~2013~~continuing economic turmoil in Venezuela and further statutory changes which impact exchange rates companies are allowed to use by the Venezuelan government when converting bolivars into dollars, Cameron recognized a gain of $4 million relating to the impact on its bolivar-denominated net liabilities of a devaluation of the Venezuelan ~~bolivar, the Company has used~~currency from the official exchange rate used in the past to a market-based rate during the first quarter of ~~6.3 bolivars~~2015. The factors described above which led to the ~~U.S. dollar to remeasure non-functional~~ currency transactions in its financial statements. During 2014, the Venezuelan government began using other auction rates (SICAD rates) for activities involving the exchange of bolivars and dollars. At September 30, 2014, the published SICAD I rate was 12.0 bolivars to the U.S. dollar and the published SICAD II rate was approximately 49.99 bolivars to the U.S. dollar. The Company does not currently expect a material loss or a material decline in operating cash flows to occur should these expanded auction rates result in a change in the payment practices of its primary customer or in a further devaluation, ~~of the Venezuelan currency. These factors however,~~ along with recent civil unrest, create political and economic uncertainty with regard to ~~their~~the impact on the Company's continued operations in this country. Net assets associated with the Company's operations in Venezuela at March 31, 2015 totaled approximately $59 million.

Increasingly, some of the Company's customers, particularly the national oil companies, have required a certain percentage, or an increased percentage, of local content in the products they buy directly or indirectly from the Company. This requires the Company to add to or expand manufacturing capabilities in certain countries that are presently without the necessary infrastructure or human resources in place to conduct business in a manner as typically done by Cameron. This increases the risk of untimely deliveries, cost overruns and defective products.

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The Company's operations expose it to risks resulting from differing and/or increasing tax rates.

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

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

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

The Company does business and has operations in a number of developing countries that have relatively underdeveloped legal and regulatory systems compared to more developed countries. Several of these countries are generally perceived as presenting a higher than normal risk of corruption, or as having a culture in which requests for improper payments are not discouraged. Maintaining and administering an effective anti-bribery compliance program under the U.S. Foreign Corrupt Practices Act (FCPA), the United Kingdom's Bribery Act of 2010, and similar statutes of other nations, in these environments ~~presents~~present greater challenges to the Company than is the case in other, more developed countries.

Additionally, the Company's business involves the use of agents and other intermediaries, such as customs clearance brokers, in these countries as well as others. As a result, the risk to the Company of compliance violations is increased because actions taken by any of them when attempting to conduct business on our behalf could be imputed to us by law enforcement authorities.

As an example, various employees and former employees of the Company's primary customer in Brazil are being investigated currently over allegations of bribery and other acts of corruption. This investigation, along with the current recessionary economic conditions in Brazil, is, at present, having a negative impact on future orders and growth prospects for the Company's operations in Brazil. Sales to customers in Brazil accounted for approximately 4% of the Company's consolidated revenues during the first quarter of 2015, as compared to nearly 7% during the first quarter of 2014.

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

The Company's operations are subject to a variety of national and state, provincial and local laws and regulations, including laws and regulations relating to the protection of the environment. The Company is required to invest financial and managerial resources to comply with these laws and expects to continue to do so in the future. To date, the cost of complying with governmental regulation has not been material, but the fact that such laws or regulations are frequently changed makes it impossible for the Company to predict the cost or impact of such laws and regulations on the Company's future operations. The modification of existing laws or regulations or the adoption of new laws or regulations imposing more stringent environmental restrictions could adversely affect the Company.

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

Environmental concerns have been raised regarding the potential impact on underground water supplies of hydraulic fracturing which involves the pumping of water and certain chemicals under pressure into a well to break apart shale and other rock formations in order to increase the flow of oil and gas embedded in these formations. ~~Recently,~~On March 20, 2015, the U.S. Interior Department's Bureau of Land Management (BLM) released a final rule regulating hydraulic fracturing activities on Federal and Indian lands. The final rule includes new well-bore integrity requirements, imposes standards for interim storage of recovered waste fluids, and requires notifications and waiting periods for key parts of the fracturing process, which could lead to delays in fracturing and/or drilling operations. The rule also mandates disclosure of the chemicals used in the process.

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Additionally, on April 7, 2015, the U.S. Environmental Protection Agency (EPA) published a proposed rule that would prohibit the disposal of unconventional oil and natural gas wastewater at publicly owned treatment works.

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

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

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

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

Carbon emission reporting and reduction programs have also expanded in recent years at the state, regional and national levels with certain countries having already implemented various types of cap-and-trade programs aimed at reducing carbon emissions from companies that currently emit greenhouse gases.

To the extent the Company's customers are subject to these or other similar proposed or newly enacted laws and regulations, the Company is exposed to risks that the additional costs by customers to comply with such laws and regulations could impact their ability or desire to continue to operate at current or anticipated levels in certain jurisdictions, which could negatively impact their demand for the Company's products and services.

To the extent Cameron becomes subject to any of these or other similar proposed or newly enacted laws and regulations, the Company expects that its efforts to monitor, report and comply with such laws and regulations, and any related taxes imposed on companies by such programs, will increase the Company's cost of doing business in certain jurisdictions, including the United States, and may require expenditures on a number of its facilities and possibly on modifications of certain of its products.

The Company could also be impacted by new laws and regulations establishing cap-and-trade and those that might favor the increased use of non-fossil fuels, including nuclear, wind, solar and bio-fuels or that are designed to increase energy efficiency. If the proposed or newly executed laws have the effect of dampening demand for oil and gas production, they could lower spending by customers for the Company's products and services.

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Environmental Remediation

The Company's worldwide operations are subject to domestic and international regulations with regard to air, soil and water quality as well as other environmental matters. The Company, through its ~~environmental management system~~Health, Safety and ~~active~~Environmental (HSE) Management System and corporate third-party regulatory compliance audit program, believes it is in substantial compliance with these regulations.

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

Environmental Sustainability

The Company has pursued environmental sustainability in a number of ways. Processes are monitored in an attempt to produce the least amount of waste. All of the waste disposal firms used by the Company are carefully selected in an attempt to prevent any future Superfund involvements. Actions are taken in an attempt to minimize the generation of hazardous wastes and to minimize air emissions. Recycling of process water is a common practice. Best management practices are used in an effort to prevent contamination of soil and ground water on the Company's sites.

Cameron has implemented a corporate ~~"HSE~~HSE Management ~~System" based on~~System that incorporates many of the principles of ISO 14001 and OHSAS 18001. The HSE Management System contains a set of corporate standards that are required to be implemented and verified by each business unit. Cameron has also implemented a corporate third-party regulatory compliance audit program to verify facility compliance with environmental, health and safety laws and regulations. The compliance program employs or uses independent third-party auditors to audit facilities on a regular basis specific to country, region, and local legal requirements. Audit reports are circulated to the senior management of the Company and to the appropriate business unit. The compliance program requires corrective and preventative actions be taken by a facility to remedy all findings of non-compliance which are tracked on the corporate HSE data base.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The Company is currently exposed to market risk from changes in foreign currency ~~exchange~~ rates ~~changes in the value of its equity instruments~~ and changes in interest rates. A discussion of the Company's market risk exposure in financial instruments follows.

Foreign Currency Exchange Rates

A large portion of the Company's operations consist of manufacturing and sales activities in foreign jurisdictions, principally in Europe, Canada, West Africa, the Middle East, Latin America, China and other countries in the Pacific Rim. As a result, the Company's financial performance may be affected by changes in foreign currency exchange rates in these markets. Overall, for those locations where the Company is a net receiver of local non-U.S. dollar currencies, Cameron generally benefits from a weaker U.S. dollar with respect to those currencies. Alternatively, for those locations where the Company is a net payer of local non-U.S. dollar currencies, a weaker U.S. dollar with respect to those currencies will generally have an adverse impact on the Company's financial results. The impact on the Company's financial results of gains or losses arising from foreign currency denominated transactions, if material, have been described under "Results of Operations" in this Management's Discussion and Analysis of Financial Condition and Results of Operations for the periods shown.

In order to mitigate the effect of exchange rate changes, the Company will often structure sales contracts to provide for collections from customers in the currency in which the Company incurs its manufacturing costs. In certain instances, the Company will enter into foreign currency forward contracts to hedge specific large anticipated receipts or disbursements in currencies for which the Company does not traditionally have fully offsetting local currency expenditures or receipts. The Company was party to a number of long-term foreign currency forward contracts at March 31, 2015. The purpose of the majority of these contracts was to hedge large anticipated non-functional currency cash flows on major subsea, drilling, valve or other equipment contracts involving the Company's United States operations and various wholly-owned international subsidiaries. Many of these contracts have been designated as and are accounted for as cash flow hedges, with changes in the fair value of those contracts recorded in accumulated other comprehensive income (loss) in the period such change occurs. Certain other contracts, many of which are centrally managed, are intended to offset other foreign currency exposures but have not been designated as hedges for accounting purposes and, therefore, any change in the fair value of those contracts are reflected in earnings in the period such change occurs. The Company expects to expand its use of such contracts in the future.

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Capital Markets and Interest Rates

The Company is subject to interest rate risk on its variable-interest rate and commercial paper borrowings. Variable-rate debt, where the interest rate fluctuates periodically, exposes the Company's cash flows to variability due to changes in market interest rates. Additionally, the fair value of the Company's fixed-rate debt changes with changes in market interest rates.

The Company manages its debt portfolio to achieve an overall desired position of fixed and floating rates and employs from time to time interest rate swaps as a tool to achieve that goal. The major risks from interest rate derivatives include changes in the interest rates affecting the fair value of such instruments, potential increases in interest expense due to market increases in floating interest rates and the creditworthiness of the counterparties in such transactions.

~~The~~ fair values of the 1.15% and 1.4% 3-year Senior Notes, the 3.6%, 3.7%, 4.0%, 4.5% and 6.375% 10-year Senior Notes and the 5.125%, 5.95% and 7.0% 30-year Senior Notes are principally dependent on prevailing interest rates. The fair value of ~~the~~ commercial paper and other short-term debt is expected to approximate its book value.

The Company has various other long-term debt instruments, but believes that the impact of changes in interest rates in the near term will not be material to these instruments.

Derivatives Activity

Total gross volume bought (sold) by notional currency and maturity date on open derivative contracts at March 31, 2015 was as follows:

	Notional Amount - Buy								Notional Amount - Sell
(amounts in millions)	2015		2016		2017		Total		2015			2016			Total
Foreign exchange forward contracts -
Notional currency in:
Euro		236		14		–		250		(51	)		–			(51	)
Malaysian ringgit		319		51		–		370		(47	)		–			(47	)
Norwegian krone		580		184		4		768		(63	)		(54	)		(117	)
Pound Sterling		150		9		–		159		(28	)		(1	)		(29	)
U.S. dollar		61		–		–		61		(481	)		(137	)		(618	)

Foreign exchange option contracts -
Notional currency in:
U.S. dollar		13		–		–		13		–			–			–

As described further in Note 14 of the Notes to Consolidated Condensed Financial Statements, the net fair value of the Company's outstanding derivatives was a $119 million liability to the Company at March 31, 2015 ($99 million liability at December 31, 2014).

Fair Value of Financial Instruments

The Company had approximately $1.3 billion of cash equivalents and $424 million of short-term investments at March 31, 2015. Cash equivalents represent highly liquid investments which are readily convertible to cash and have maturities of three months or less at the time of purchase. Short-term investments have original maturities of more than three months but less than one year. Certain of these investments are valued based upon quoted or estimated market prices which represent levels 1 and 2 market inputs.

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The fair values of the Company's foreign exchange forward and option contracts were based on quoted exchange rates for the respective currencies applicable to similar instruments (level 2 observable market inputs).

The Company's international pension plans have assets available to fund future pension liabilities. The majority of these assets are invested in debt and equity securities or mutual funds, which were valued based on quoted market prices for an individual asset (level 1 market inputs), or mutual fund unit values, which were based on the fair values of the individual securities that the fund had invested in (level 2 observable market inputs). A certain portion of the assets were invested in insurance contracts, real estate and other investments, which were valued based on level 3 unobservable inputs.

The values of these assets are subject to change, based generally on changes in market conditions involving foreign exchange rates, interest rates and debt and equity security investment pricing.

Item 4. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, the Company carried out an evaluation, under the supervision and with the participation of the Company's Sarbanes-Oxley Disclosure Committee and the Company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures, as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective as of ~~September 30, 2014~~March 31, 2015 to ensure that information required to be disclosed by the Company that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is accumulated and communicated to the Company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There were no material changes in the Company's internal control over financial reporting during the quarter ended ~~September 30, 2014.~~March 31, 2015.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

The information set forth under the caption "Factors That May Affect Financial Condition and Future Results" on pages 3328 – 3834 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

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

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Shares of common stock purchased and placed in treasury during the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015 under the Board's treasury stock purchase authorization program ~~described above~~ were as follows:

Period
Total number of shares purchased during the period Average price paid per share Cumulative number of shares purchased as part of repurchase program
Maximum number of shares that may yet be purchased under
repurchase program⁽¹⁾

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

Period	Total number of shares purchased during the period		Average price paid per share		Cumulative number of shares purchased as part of repurchase program		Maximum number of shares that may yet be purchased under repurchase program⁽¹⁾
1/1/15 – 1/31/15		1,230,663	$	44.55		56,618,578		9,415,237
2/1/15 – 2/28/15		1,451,000	$	46.86		58,069,578		7,510,988
3/1/15 – 3/31/15		1,264,871	$	44.28		59,334,449		6,595,850
Total		3,946,534	$	45.31		59,334,449		6,595,850

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

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

N/A

Item 5. Other Information

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

None

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

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

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Item 6. Exhibits

Exhibit 31.1 –

Certification

Exhibit 31.2 –

Certification

Exhibit 32.1 –

Certification of the CEO and CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 101.INS –

XBRL Instance Document

Exhibit 101.SCH –

XBRL Taxonomy Extension Schema Document

Exhibit 101. CAL –

XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit ~~101.DEF–~~101.DEF –

XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB –

XBRL Taxonomy Extension Label Linkbase Document

Exhibit 101.PRE –

XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

Date: ~~October 23, 2014~~April 24, 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

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EXHIBIT INDEX

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

(Mark One)
R	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended ~~September 30, 2014~~March 31, 2015
OR
£☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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)

	September 30, 2014			December 31, 2013			March 31, 2015			December 31, 2014
	(unaudited)						(unaudited)
ASSETS
Cash and cash equivalents	$	1,058		$	1,813		$	1,322		$	1,513
Short-term investments		115			41			424			113
Receivables, net		2,580			2,719			2,178			2,389
Inventories, net		3,130			3,133			2,930			2,929
Other current assets		378			463			397			391
Assets of discontinued operations		235			–			–			217
Total current assets		7,496			8,169			7,251			7,552
Plant and equipment, net		1,941			2,037			1,830			1,964
Goodwill		2,607			2,925			1,858			2,461
Intangibles, net		817			904			679			728
Other assets		228			214			187			187
TOTAL ASSETS	$	13,089		$	14,249		$	11,805		$	12,892

LIABILITIES AND STOCKHOLDERS' EQUITY
Short-term debt	$	403		$	297		$	31		$	263
Accounts payable and accrued liabilities		3,456			3,883			3,194			3,748
Accrued income taxes		97			80			393			168
Liabilities of discontinued operations		107			–			–			90
Total current liabilities		4,063			4,260			3,618			4,269
Long-term debt		2,809			2,563			2,813			2,819
Deferred income taxes		199			277			179			193
Other long-term liabilities		222			233			166			167
Total liabilities		7,293			7,333			6,776			7,448
Stockholders' Equity:
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at September 30, 2014 and December 31, 2013		3			3
Stockholders' Equity:
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at March 31, 2015 and December 31, 2014								3			3
Capital in excess of par value		3,244			3,207			3,234			3,255
Retained earnings		5,378			4,820			5,680			5,631
Accumulated other elements of comprehensive income (loss)		(232	)		(80	)		(765	)		(540	)
Less: Treasury stock, 64,808,073 shares at September 30, 2014 (41,683,164 shares at December 31, 2013)		(3,608	)		(2,098	)
Less: Treasury stock, 71,543,192 shares at March 31, 2015 (68,139,027 shares at December 31, 2014)								(3,949	)		(3,794	)
Total Cameron stockholders' equity		4,785			5,852			4,203			4,555
Noncontrolling interests		1,011			1,064			826			889
Total equity		5,796			6,916			5,029			5,444
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	13,089		$	14,249		$	11,805		$	12,892

Sales price	$	850
Net assets sold, including estimated post-closing working capital adjustments		(160	)
Transaction and other costs associated with the sale		(10	)
Pre-tax gain		680
Tax provision		(248	)
Gain on sale	$	432

	September 30, 2014			December 31, 2013
(dollars in millions)							March 31, 2015			December 31, 2014

Trade receivables	$	2,078		$	2,368		$	1,430		$	1,678
Costs and estimated earnings in excess of billings on uncompleted contracts		397			253			615			621
Other receivables		134			119			172			122
Allowance for doubtful accounts		(29	)		(21	)		(39	)		(32	)
Total receivables	$	2,580		$	2,719
Total receivables, net							$	2,178		$	2,389

PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements	3
Consolidated Condensed Statements of Comprehensive Income	3
Consolidated Condensed Balance Sheets	4
Consolidated Condensed Statements of Cash Flows	5
Consolidated Condensed Statement of Changes in Equity	6
Notes to Consolidated Condensed Financial Statements	7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3. Quantitative and Qualitative Disclosures About Market Risk	3935
Item 4. Controls and Procedures	4037
PART II — OTHER INFORMATION	4037
Item 1. Legal Proceedings	4037
Item 1A. Risk Factors	4037
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4037
Item 3. Defaults Upon Senior Securities	4138
Item 4. Mine Safety Disclosures	4138
Item 5. Other Information	4138
Item 6. Exhibits	4239
SIGNATURES	4340

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

Balance at December 31, 2013	$	3	$	3,207		$	4,820	$	(80	)	$	(2,098	)	$	1,064
Balance at December 31, 2014																	$	3	$	3,255		$	5,631	$	(540	)	$	(3,794	)	$	889
Net income		–		–			558		–			–			29			–		–			49		–			–			2
Other comprehensive income (loss), net of tax		–		–			–		(152	)		–			(46	)		–		–			–		(225	)		–			(65	)
Non-cash stock compensation expense		–		43			–		–			–			–			–		10			–		–			–			–
Purchase of treasury stock		–		–			–		–			(1,561	)		–			–		–			–		–			(179	)		–
Treasury stock issued under stock compensation plans		–		(12	)		–		–			51			–			–		(31	)		–		–			24			–
Tax benefit of stock compensation plan transactions		–		6			–		–			–			–			–		–			–		–			–			–
Purchase of noncontrolling ownership interests		–		–			–		–			–			4
Distribution to noncontrolling interest owners		–		–			–		–			–			(40	)

Balance at September 30, 2014	$	3	$	3,244		$	5,378	$	(232	)	$	(3,608	)	$	1,011
Balance at March 31, 2015																	$	3	$	3,234		$	5,680	$	(765	)	$	(3,949	)	$	826

	September 30, 2014			December 31, 2013

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

Balance at December 31, 2014	$	2,461
Impairment of goodwill (See Note 3)		(517	)
Adjustments to the purchase price allocation for prior year acquisitions		(5	)
Translation effect of currency changes		(81	)
Balance at March 31, 2015	$	1,858

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

$	46	$	34	$	(24	)	$	(10	)	$	–	$	46

	September 30, 2014			December 31, 2013

Commercial paper (0.32% weighted average rate)	$	350		$	–
Senior notes:
Floating rate notes due June 2, 2014		–			250
1.6% notes due April 30, 2015		–			250
1.15% notes due December 15, 2016		250			250
1.4% notes due June 15, 2017		250			–
6.375% notes due July 15, 2018		450			450
4.5% notes due June 1, 2021		250			250
3.6% notes due April 30, 2022		250			250
4.0% notes due December 15, 2023		250			250
3.7% notes due June 15, 2024		250			–
7.0% notes due July 15, 2038		300			300
5.95% notes due June 1, 2041		250			250
5.125% notes due December 15, 2043		250			250
Unamortized original issue discount		(7	)		(7	)
Other debt		61			57
Obligations under capital leases		58			60
		3,212			2,860
Current maturities		(403	)		(297	)
Long-term maturities	$	2,809		$	2,563

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

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

	Three Months Ended September 30, 2014
	Accumulated Foreign Currency Translation Gain (Loss)			Prior Service Credits and Net Actuarial Losses			Accumulated Gain (Loss) on Cash Flow Hedge Derivatives			Total			Three Months Ended September 30, 2013
Beginning of period balance	$	(43	)	$	(45	)	$	12		$	(76	)	$	(156	)

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

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

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

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

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

	Fair Value Based on Quoted Prices in Active Markets for Identical Assets (Level 1)				Fair Value Based on Significant Other Observable Inputs (Level 2)					Total					Fair Value Based on Quoted Prices in Active Markets for Identical Assets (Level 1)				Fair Value Based on Significant Other Observable Inputs (Level 2)						Total
(in millions)	2014		2013		2014			2013		2014			2013
(dollars in millions)															2015		2014		2015			2014			2015			2014

Cash and cash equivalents:
Cash	$	497	$	618	$	–		$	–	$	497		$	618	$	534	$	616	$	–		$	–		$	534		$	616
Money market funds		493		1,172		–			–		493			1,172		665		842		–			–			665			842
Commercial paper		–		–		21			4		21			4		–		–		55			13			55			13
U.S. Treasury securities																7		5		–			–			7			5
U.S. corporate obligations		11		–		–			–		11					23		4		–			–			23			4
Non-U.S. bank and other obligations		36		19		–			–		36			19		25		33		–			–			25			33
U.S. non-governmental agency asset-backed securities																–		–		13			–			13			–
Short-term investments:
Commercial paper		–		–		9			–		9			–		–		–		115			11			115			11
U.S. Treasury securities		71		41		–			–		71			41		76		51		–			–			76			51
U.S. corporate obligations		35		–		–			–		35			–		188		51		–			–			188			51
U.S. non-governmental agency asset-backed securities																–		–		45			–			45			–
Non-qualified plan assets:
Money market funds		1		1		–			–		1			1		–		1		–			–			–			1
Domestic bond funds		3		3		–			–		3			3		3		3		–			–			3			3
Domestic equity funds		6		5		–			–		6			5		6		5		–			–			6			5
International equity funds		3		3		–			–		3			3		3		3		–			–			3			3
Blended equity funds		5		4		–			–		5			4		5		5		–			–			5			5
Common stock		2		2		–			–		2			2		2		2		–			–			2			2
Derivatives, net asset (liability):
Foreign currency contracts		–		–		(43	)		19		(43	)		19		–		–		(119	)		(99	)		(119	)		(99	)
	$	1,163	$	1,868	$	(13	)	$	23	$	1,150		$	1,891	$	1,537	$	1,621	$	109		$	(75	)	$	1,646		$	1,546

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

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

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

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

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

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

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

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

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

Commodity prices (average of daily U.S. dollar prices per unit during period)⁽²⁾:
West Texas Intermediate Cushing, OK crude spot price per barrel in U.S. dollars	$	99.77	$	98.17	$	1.60		1.6	%
Henry Hub natural gas spot price per MMBtu in U.S. dollars	$	4.57	$	3.70	$	0.87		23.5	%