Edgar Filing: CAMERON INTERNATIONAL CORP

form10-q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

Commission File Number 1-13884

Cameron International Corporation

(Exact Name of Registrant as Specified in its Charter)

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

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

713/513-3300

(Registrant’s Telephone Number, Including Area Code)

N/A

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes R No £

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

Yes R No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer R Accelerated filer £

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

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

Yes £ No R

Number of shares outstanding of issuer’s common stock as of October 20, 2011 was 245,200,784.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION	3
Item 1. Financial Statements	3
Consolidated Condensed Results of Operations	3
Consolidated Condensed Balance Sheets	4
Consolidated Condensed Statements of Cash Flows	5
Notes to Consolidated Condensed Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3. Quantitative and Qualitative Disclosures About Market Risk	36
Item 4. Controls and Procedures	37
PART II — OTHER INFORMATION	38
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3. Defaults Upon Senior Securities	39
Item 4. Removed and Reserved	39
Item 5. Other Information	39
Item 6. Exhibits	40
SIGNATURES	41

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CAMERON INTERNATIONAL CORPORATION

CONSOLIDATED CONDENSED RESULTS OF OPERATIONS

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(unaudited)
REVENUES	$	1,685.9		$	1,527.1		$	4,928.2		$	4,326.5
COSTS AND EXPENSES
Cost of sales (exclusive of depreciation and amortization shown separately below)		1,136.6			1,048.7			3,407.9			2,947.5
Selling and administrative expenses		243.4			210.2			723.6			611.9
Depreciation and amortization		53.1			52.7			145.5			153.7
Interest, net		20.6			20.0			62.7			56.4
Other costs (see Note 3)		34.2			10.4			63.2			39.1
Total costs and expenses		1,487.9			1,342.0			4,402.9			3,808.6
Income before income taxes		198.0			185.1			525.3			517.9
Income tax provision		(33.5	)		(36.4	)		(103.2	)		(119.7	)
Net income	$	164.5		$	148.7		$	422.1		$	398.2
Earnings per common share:
Basic	$	0.67		$	0.61		$	1.72		$	1.64
Diluted	$	0.67		$	0.61		$	1.69		$	1.61
Shares used in computing earnings per common share:
Basic		245.1			242.2			244.9			243.2
Diluted		247.1			245.5			249.8			247.0

The accompanying notes are an integral part of these statements.

CAMERON INTERNATIONAL CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS

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

	September 30, 2011			December 31, 2010
	(unaudited)
ASSETS
Cash and cash equivalents	$	1,536.5		$	1,832.5
Receivables, net		1,396.2			1,056.1
Inventories, net		2,177.7			1,779.3
Other		328.6			265.0
Total current assets		5,439.0			4,932.9
Plant and equipment, net		1,339.5			1,247.8
Goodwill		1,496.7			1,475.8
Other assets		351.6			348.6
TOTAL ASSETS	$	8,626.8		$	8,005.1

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of long-term debt	$	10.9		$	519.9
Accounts payable and accrued liabilities		2,029.8			2,016.0
Accrued income taxes		-			38.0
Total current liabilities		2,040.7			2,573.9
Long-term debt		1,576.3			772.9
Deferred income taxes		159.5			95.7
Other long-term liabilities		240.5			170.2
Total liabilities		4,017.0			3,612.7
Stockholders’ Equity:
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at September 30, 2011 and December 31, 2010		2.6			2.6
Capital in excess of par value		2,070.9			2,259.3
Retained earnings		3,270.4			2,848.3
Accumulated other elements of comprehensive income (loss)		(77.5	)		(27.1	)
Less: Treasury stock, 17,913,815 shares at September 30, 2011 (19,197,642 shares at December 31, 2010)		(656.6	)		(690.7	)
Total stockholders’ equity		4,609.8			4,392.4
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	8,626.8		$	8,005.1

The accompanying notes are an integral part of these statements.

CAMERON INTERNATIONAL CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(dollars in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(unaudited)

Cash flows from operating activities:
Net income	$	164.5		$	148.7		$	422.1		$	398.2
Adjustments to reconcile net income to net cash provided by (used for) operating activities:
Depreciation		42.9			36.4			115.1			107.8
Amortization		10.2			16.3			30.4			45.9
Non-cash stock compensation expense		9.1			6.7			26.7			25.2
Deferred income taxes and tax benefit of employee stock compensation plan transactions		25.6			(13.0	)		12.5			(5.5	)
Changes in assets and liabilities, net of translation, acquisitions and non-cash items:
Receivables		(159.1	)		(67.0	)		(360.4	)		(46.9	)
Inventories		(146.4	)		(25.1	)		(431.4	)		(91.0	)
Accounts payable and accrued liabilities		158.0			(31.2	)		24.6			(398.8	)
Other assets and liabilities, net		0.1			23.1			39.8			(95.6	)
Net cash provided by (used for) operating activities		104.9			94.9			(120.6	)		(60.7	)
Cash flows from investing activities:
Capital expenditures		(94.2	)		(47.0	)		(228.5	)		(115.0	)
Acquisitions, net of cash acquired		−			−			(42.5	)		(40.9	)
Proceeds from sale of plant and equipment		7.8			1.4			17.6			8.9
Net cash used for investing activities		(86.4	)		(45.6	)		(253.4	)		(147.0	)
Cash flows from financing activities:
Short-term loan borrowings (repayments), net		18.2			12.1			49.7			(6.6	)
Issuance of senior debt		−			−			747.8			−
Debt issuance costs		−			−			(4.7	)		−
Redemption of convertible debentures		(524.5	)		−			(705.7	)		−
Sale (purchase) of equity call options, net		9.7			−			(12.2	)		−
Purchase of treasury stock		–			–			−			(123.9	)
Proceeds from stock option exercises, net of tax payments from stock compensation plan transactions		3.3			2.5			20.0			(9.6	)
Excess tax benefits from employee stock compensation plan transactions		0.5			0.9			5.4			6.3
Principal payments on capital leases		(2.2	)		(1.6	)		(6.0	)		(4.9	)
Net cash provided by (used for) financing activities		(495.0	)		13.9			94.3			(138.7	)
Effect of translation on cash		(30.1	)		20.1			(16.3	)		(2.8	)
Increase (decrease) in cash and cash equivalents		(506.6	)		83.3			(296.0	)		(349.2	)
Cash and cash equivalents, beginning of period		2,043.1			1,428.5			1,832.5			1,861.0
Cash and cash equivalents, end of period	$	1,536.5		$	1,511.8		$	1,536.5		$	1,511.8

The accompanying notes are an integral part of these statements.

CAMERON INTERNATIONAL CORPORATION

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Unaudited

Note 1: Basis of Presentation

The accompanying Unaudited Consolidated Condensed Financial Statements of Cameron International Corporation (the Company) have been prepared in accordance with Rule 10-01 of Regulation S-X and do not include all the information and footnotes required by generally accepted accounting principles for complete financial statements. Those adjustments, consisting of normal recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the financial information for the interim periods, have been made. The results of operations for such interim periods are not necessarily indicative of the results of operations for a full year. The Unaudited Consolidated Condensed Financial Statements should be read in conjunction with the Audited Consolidated Financial Statements and Notes thereto filed by the Company on Form 10-K for the year ended December 31, 2010.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include, but are not limited to, estimates of total contract profit or loss on certain long-term production contracts, estimated losses on accounts receivable, estimated realizable value on excess and obsolete inventory, contingencies, including tax contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to pension accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill for impairment, estimated proceeds from assets held for sale and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ materially from these estimates.

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

Note 2: Acquisitions

On October 24, 2011, the Company closed on the acquisition of LeTourneau Technologies, Inc., a wholly-owned subsidiary of Joy Global Inc., for $375.0 million in cash, subject to certain post-closing adjustments. LeTourneau provides drilling equipment as well as rig designs and components for both the land and offshore rig markets.

During the nine months ended September 30, 2011, the Company acquired the stock of three businesses for a total cash purchase price, net of cash acquired, of $42.5 million. Vescon Equipamentos Industriais Ltda. was acquired to strengthen the Company’s surface product offerings in the Brazilian market and has been included in the DPS segment since the date of acquisition. The remaining interest in Scomi Energy Sdn Bhd., previously a Cameron joint venture company, was acquired in order to strengthen the Company’s process systems offerings in the Malaysian market. On June 20, 2011, TS-Technology AS, a Norwegian company, was acquired to enhance the Company’s water treatment technology offerings. The results of both the Scomi Energy Sdn Bhd and TS-Technology AS businesses have been included in the PCS segment since the dates of the respective acquisitions.

Preliminary goodwill recorded from the three acquisitions during the nine months ended September 30, 2011 was approximately $25.7 million, of which approximately $20.1 million is deductible for tax purposes. The Company is still awaiting significant information relating to the fair value of the assets and liabilities of the acquired businesses in order to finalize the purchase price allocations.

Note 3: Other Costs

Other costs for the three and nine months ended September 30, 2011 and 2010 consisted of the following (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010

Employee severance	$	–	$	–	$	5.8	$	9.5
NATCO acquisition integration costs		–		5.7		–		18.5
BOP litigation		13.2		4.1		35.5		6.8
Mark-to-market impact on currency derivatives(1)		6.4		–		6.4		–
Acquisition, refinancing and other restructuring costs(2)		14.6		0.6		15.5		4.3
	$	34.2	$	10.4	$	63.2	$	39.1

(1)	These derivatives have not been designated as accounting hedges.

(2)	Includes $13.8 million and $12.2 million of costs for the three and nine months ended September 30, 2011, respectively, associated with retiring the 2.5% convertible debentures as described further in Note 14.

Note 4: Receivables

Receivables consisted of the following (in millions):

	September 30, 2011			December 31, 2010

Trade receivables	$	1,263.5		$	991.2
Other receivables		103.3			78.9
Net income tax receivable		43.4			–
Allowance for doubtful accounts		(14.0	)		(14.0	)
Total receivables	$	1,396.2		$	1,056.1

Note 5: Inventories

Inventories consisted of the following (in millions):

	September 30, 2011			December 31, 2010

Raw materials	$	181.9		$	166.5
Work-in-process		801.2			575.9
Finished goods, including parts and subassemblies		1,360.2			1,190.5
Other		12.4			12.1
		2,355.7			1,945.0
Excess of current standard costs over LIFO costs		(101.1	)		(97.7	)
Allowances		(76.9	)		(68.0	)
Total inventories	$	2,177.7		$	1,779.3

Note 6: Plant and Equipment and Goodwill

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

	September 30, 2011			December 31, 2010

Plant and equipment, at cost	$	2,468.1		$	2,285.9
Accumulated depreciation		(1,128.6	)		(1,038.1	)
Total plant and equipment	$	1,339.5		$	1,247.8

Changes in goodwill during the nine months ended September 30, 2011 were as follows (in millions):

Balance at December 31, 2010	$	1,475.8
Current year acquisitions		25.7
Translation		(4.8	)
Balance at September 30, 2011	$	1,496.7

Note 7: Accounts Payable and Accrued Liabilities

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

	September 30, 2011		December 31, 2010

Trade accounts payable and accruals	$	571.3	$	571.3
Salaries, wages and related fringe benefits		177.7		190.2
Advances from customers		858.9		863.3
Sales-related costs and provisions		91.6		90.2
Payroll and other taxes		67.1		67.4
Product warranty		53.2		45.7
Fair market value of derivatives		12.2		1.8
Other		197.8		186.1
Total accounts payable and accrued liabilities	$	2,029.8	$	2,016.0

Activity during the nine months ended September 30, 2011 associated with the Company’s product warranty accruals was as follows (in millions):

Balance December 31, 2010		Net warranty provisions		Charges against accrual			Translation and other			Balance September 30, 2011

$	45.7	$	23.9	$	(16.3	)	$	(0.1	)	$	53.2

Note 8: Debt

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

	September 30, 2011			December 31, 2010

Senior notes:
Floating rate notes due June 2, 2014	$	250.0		$	–
6.375% notes due July 15, 2018		450.0			450.0
4.5% notes due June 1, 2021		250.0			–
7.0% notes due July 15, 2038		300.0			300.0
5.95% notes due June 1, 2041		250.0			–
Unamortized original issue discount		(3.9	)		(1.8	)
Convertible debentures:
2.5% notes due June 15, 2026		–			500.0
Unamortized discount		–			(6.9	)
Other debt		73.7			37.5
Obligations under capital leases		17.4			14.0
		1,587.2			1,292.8
Current maturities		(10.9	)		(519.9	)
Long-term maturities	$	1,576.3		$	772.9

Senior Notes

Effective June 2, 2011, the Company completed the public offering of $750.0 million in aggregate principal amount of senior unsecured notes as follows:

$250.0 million principal amount of Floating Rate Senior Notes due June 2, 2014, bearing interest based on the 3-month London Interbank Offered Rate (LIBOR) plus 0.93%, per annum. The interest rate is reset quarterly and interest payments are due on March 2, June 2, September 2 and December 2 of each year, beginning September 2, 2011;

·	$250.0 million principal amount of 4.5% Senior Notes due June 1, 2021; and

·	$250.0 million principal amount of 5.95% Senior Notes due June 1, 2041.

Interest on the 4.5% and 5.95% Senior Notes is payable on June 1 and December 1 of each year, beginning December 1, 2011. The 4.5% and 5.95% Senior Notes were sold at 99.151% and 99.972% of principal amount, respectively, and can both be redeemed in whole or in part by the Company prior to maturity in accordance with the terms of the respective Supplemental Indentures. The Floating Rate Senior Notes are not redeemable by the Company prior to maturity. All of the Company’s senior notes rank equally with the Company’s other existing unsecured and unsubordinated debt.

The proceeds from the debt offering were used for the purchase or redemption of the Company’s 2.5% Convertible Debentures (see below) and for general corporate purposes.

Convertible Debentures

In June 2011, the Company notified holders of its 2.5% Convertible Debentures that it was exercising its right to redeem for cash all of the outstanding debentures on July 6, 2011 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest. Holders of $295.5 million principal amount of debentures notified the Company they were instead electing to convert their debentures under the terms of the debenture agreement. The Company elected to settle the entire conversion amount (principal plus the conversion value in excess of principal) in cash for those electing conversion. The remaining $204.5 million principal amount of debentures were either purchased by the Company on the open market or redeemed for cash during June and July 2011. As a result of these transactions, the Company retired all $500.0 million principal amount of its outstanding 2.5% Convertible Debentures for a total of $705.7 million in cash. Approximately $203.3 million of the cash payment represented conversion value in excess of principal which has been recorded in capital in excess of par value.

In order to hedge a portion of the conversion value for the 2.5% Convertible Debentures, the Company entered into an agreement with a third party financial intermediary in the second quarter of 2011 to purchase 5.0 million call options on its common stock for a total premium payment of $21.9 million. See Note 14 of the Notes to Consolidated Condensed Financial Statements for further information.

Multicurrency Revolving Letter of Credit and Credit Facilities

On June 6, 2011, the Company entered into a Second Amendment to its Credit Agreement dated April 14, 2008 (the Amended Credit Agreement). This amendment increased the Company’s multicurrency borrowing capacity from $585.0 million to $835.0 million and extended the maturity date to June 6, 2016. Similar to the original Credit Agreement, the Company may borrow funds at LIBOR plus a spread, which varies based on the Company’s current debt rating, and, if aggregate outstanding credit exposure exceeds one-half of the total facility amount, an additional fee will be incurred. The entire $835.0 million committed facility is available to the Company through April 14, 2013, with $730.0 million available thereafter through June 6, 2016. At September 30, 2011, the Company had issued letters of credit totaling $25.4 million under this Amended Credit Agreement with the remaining amount of $809.6 million available for future use.

The Company also has a three-year $250.0 million committed multi-currency revolving letter of credit facility with a third party bank. At September 30, 2011, the Company had issued letters of credit totaling $70.8 million under this revolving credit facility, leaving a remaining amount of $179.2 million available for future use.

Note 9: Income Taxes

The Company’s effective tax rates for the nine months ended September 30, 2011 and 2010 were 19.6% and 23.1%, respectively. The tax provision was reduced by:

·	realization of certain tax benefits totaling $18.4 million associated with tax planning strategies put in place in prior years,

·	the recognition of certain historical tax benefits totaling $12.2 million as prior uncertainty regarding those benefits has been resolved during the first nine months of 2011, and

·	a reduction in the tax provision of $4.8 million from the finalization of prior year tax returns.

During the nine months ended September 30, 2011, the Company recorded income tax benefits of $75.0 million, with a corresponding increase in its unrecognized tax benefits accrual, which resulted in no net impact to capital in excess of par value or earnings.

Note 10: Business Segments

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues:
DPS	$	977.2		$	944.0		$	2,845.5		$	2,600.1
V&M		434.4			312.7			1,200.8			937.0
PCS		274.3			270.4			881.9			789.4
	$	1,685.9		$	1,527.1		$	4,928.2		$	4,326.5
Income (loss) before income taxes:
DPS	$	196.6		$	161.8		$	474.3		$	463.8
V&M		81.5			43.0			212.2			137.3
PCS		24.0			41.4			88.5			96.4
Corporate & other		(104.1	)		(61.1	)		(249.7	)		(179.6	)
	$	198.0		$	185.1		$	525.3		$	517.9

Corporate & other includes expenses associated with the Company’s Corporate office, all of the Company’s interest income and interest expense, certain litigation expense managed by the Company’s General Counsel, foreign currency gains and losses from certain derivative and intercompany lending activities managed by the Company’s centralized Treasury function, all of the Company’s restructuring expense and acquisition-related costs and all stock compensation expense.

Note 11: Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010

Net income	$	164.5	$	148.7	$	422.1	$	398.2

Average shares outstanding (basic)		245.1		242.2		244.9		243.2
Common stock equivalents		2.0		2.3		2.1		2.4
Incremental shares from assumed conversion of convertible debentures		–		1.0		2.8		1.4
Diluted shares		247.1		245.5		249.8		247.0

Basic earnings per share	$	0.67	$	0.61	$	1.72	$	1.64
Diluted earnings per share	$	0.67	$	0.61	$	1.69	$	1.61

The Company’s 2.5% Convertible Debentures were included in the calculation of diluted earnings per share for the nine months ended September 30, 2011 and for the three- and nine-months ended September 30, 2010 since the average market price of the Company’s common stock exceeded the conversion value of the debentures during those periods.

No treasury shares were acquired during the three- and nine-months ended September 30, 2011. During the nine months ended September 30, 2010, the Company acquired 3,176,705 treasury shares at an average cost of $39.05 per share. No treasury shares were acquired during the three months ended September 30, 2010. A total of 132,153 and 1,283,827 treasury shares were issued during the three- and nine-months ended September 30, 2011, respectively in satisfaction of stock option exercises and vesting of restricted stock units.

Note 12: Comprehensive Income

The amounts of comprehensive income for the three and nine months ended September 30, 2011 and 2010 were as follows (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income per Consolidated Condensed Results of Operations	$	164.5		$	148.7		$	422.1		$	398.2
Foreign currency translation gain (loss)		(152.3	)		133.2			(56.0	)		(15.2	)
Amortization of net prior service credits related to the Company’s pension and postretirement benefit plans, net of tax		(0.1	)		(0.1	)		(0.4	)		(0.4	)
Amortization of net actuarial losses related to the Company’s pension and postretirement benefit plans, net of tax		1.4			1.0			4.2			2.7
Change in fair value of derivatives accounted for as cash flow hedges, net of tax		(4.4	)		7.9			1.8			4.5
Comprehensive income	$	9.1		$	290.7		$	371.7		$	389.8

The components of accumulated other elements of comprehensive income (loss) at September 30, 2011 and December 31, 2010 were as follows (in millions):

	September 30, 2011			December 31, 2010

Accumulated foreign currency translation gain (loss)	$	(24.5	)	$	31.5
Prior service credits, net, related to the Company’s pension and postretirement benefit plans, net of tax		3.9			4.3
Actuarial losses, net, related to the Company’s pension and postretirement benefit plans, net of tax		(51.6	)		(55.8	)
Change in fair value of derivatives accounted for as cash flow hedges, net of tax		(5.3	)		(7.1	)
Accumulated other elements of comprehensive income (loss)	$	(77.5	)	$	(27.1	)

Note 13: Contingencies

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

Deepwater Horizon Matter

A blowout preventer (“BOP”) originally manufactured by the Company and delivered in 2001, and for which the Company was one of the suppliers of spare parts and repair services, was deployed by the drilling rig Deepwater Horizon when the rig experienced a tragic explosion and fire on April 20, 2010, resulting in bodily injuries and loss of life, loss of the rig, and an unprecedented discharge of hydrocarbons into the Gulf of Mexico.

While the Company did not operate the BOP, nor did it have anyone on the rig at the time of the incident, claims for personal injury, wrongful death and property damage arising from the Deepwater Horizon incident have been asserted against the Company and others. Additionally, claims for pollution and for economic damages, including business interruption and loss of revenue, have been, and may continue to be asserted against all parties associated with this incident, including the Company, BP p.l.c. and certain of its subsidiaries, the operator of Mississippi Canyon Block 252 upon which the Macondo well was being drilled, Transocean Ltd. and certain of its affiliates, the rig owner and operator, as well as other equipment and service companies, including Halliburton. The Company has been named as one of multiple defendants in over 350 suits filed and presently pending in a variety of Federal and State courts, a number of which have been filed as class actions or multi-plaintiff actions. Other defendants, including BP, Transocean and Halliburton have asserted cross-claims against us as the Company has asserted such claims against them. Most of these suits pending in Federal courts have been consolidated into a single proceeding before a single Federal judge under the rules governing multi-district litigation. The consolidated case is styled In Re: Oil Spill by the Oil Rig “Deepwater Horizon” in the Gulf of Mexico on April 20, 2010, MDL Docket No. 2179. There are also a small number of cases pending in state courts. The States of Alabama and Louisiana have brought a claim for destruction of and/or harm to natural resources against those associated with this incident, including Cameron, in State of Alabama, ex. rel. Troy King, Attorney General vs. Transocean Ltd., et. al., Cause No. 2:10cv00691, U.S. Dist. Ct., M.D. Ala., and State of Louisiana vs. BP Exploration & Production, Inc., et. al, MDL No. 2179, as have a number of other local governmental entities and 3 Mexican states. It is possible other such claims may be asserted against the Company by the United States Government (USG) and by other Gulf and/or East Coast States, whose Attorneys General have notified the Company to preserve documents in the event of a claim, and possibly by other parties. The USG has brought suit against BP and certain other parties associated with this incident for recovery under statutes such as the Oil Pollution Act of 1990 (OPA) and the Clean Water Act, which suit has been made part of the MDL proceedings. While the Company was not named as a defendant in this suit by the USG, BP brought a third-party complaint for contribution under OPA against several parties associated with this incident which were not named by the USG, including the Company. A shareholder derivative suit, Berzner vs. Erikson, et al., Cause No. 2010-71817 in the 190th District Court of Harris County, Texas, has been filed against the Company’s directors in connection with this incident and its aftermath alleging the Company’s directors failed to exercise their fiduciary duties regarding the safety and efficacy of its products. This incident and its causes have been investigated by a joint investigation team (the “JIT”) of the U.S. Coast Guard and the Bureau of Ocean Energy Management, which named Cameron a party-in-interest, the Departments of the Interior and Justice, the U.S. Chemical Safety and Hazard Investigation Board, and by various other governmental entities, including Congressional Committees and the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. The Department of Justice, in addition to its involvement in the civil litigation, formed a task force to conduct investigations into possible criminal charges stemming from this incident and its aftermath.

The Federal Court overseeing the multi-district litigation has ruled that it will begin trying relative fault issues arising out of the Deepwater Horizon Matter in February 2012, and has issued a number of orders to effectuate this scheduling.

Based on the facts known to date, the Company is of the opinion that there was no defect in or failure of the BOP that caused or contributed to the explosion. The reasons as to why the efforts to shut-in the well after the explosion were unsuccessful are not known and are the subject of continuing investigation and discovery in the MDL proceedings. A report on the results of a forensic examination of the BOP by Det Norske Veritas commissioned by the JIT as part of its investigation was made public in March 2011. This report cited what it considered to be the inability of the BOP to shear the off-center drill pipe as a contributing factor to the BOP’s blind shear rams being unable to close and seal the well. The Bureau of Ocean Energy Management in its report following the conclusion of the JIT investigation adopted Det Norske Veritas’ conclusions with respect to the BOP.

The extent of the environmental impact, and the ultimate costs and damages that will ultimately be determined attributable to this incident and its aftermath, as well as the liability of the Company, if any, for some or all of the costs and damages, are not yet known and therefore cannot be reasonably estimated. As a result, we are unable to make any reasonable determination of what liability, if any, the Company could be found to have with respect to any of these claims or whether the Company will be found to have any liability, directly or by way of contribution, under any environmental laws or regulations or otherwise. BP has been designated a Responsible Party for the pollution emanating from the Macondo well under OPA, and has accepted such designation. Cameron has not been named a Responsible Party.

The applicable contracts between Cameron and Transocean entities provide for customary industry “knock-for-knock” indemnification by which each party agreed to bear the risk of, and hold the other harmless with respect to, all claims for personal injury, to include wrongful death, and property loss or damage of its own, its employees and those of its contractors. Settlements in a number of personal injury and wrongful death cases have been reached between Transocean and the claimants, and the settlement agreements have included a complete release of Cameron. In addition, the contracts require that Transocean provide Cameron an indemnity on like terms as Transocean’s customer provides to Transocean for pollution or other damages associated with a blowout or loss of well control. Transocean has publicly stated that it has a full pollution indemnity from BP, although BP has so far declined to acknowledge any obligation under the indemnity. Transocean has, in turn, declined to acknowledge any indemnity obligation under its contracts with Cameron for pollution damage.

The Company has commercial general liability insurance, including completed products and sudden accidental pollution coverage, with limits of $500 million and a self retention of $3 million. Defense costs are not covered by the policy. Coverage includes claims for personal injury and wrongful death, as well as liability for pollution and loss of revenue/business interruption. The Company has notified its insurers of the claims being asserted against it. The insurers have responded with “reservation of rights” letters.

While the Company’s BOPs have a history of reliable performance when properly maintained and operated in accordance with product specifications, until the litigation referred to above progresses and until the investigations referred to above are completed, we are unable to determine the extent of the Company’s future involvement in the litigation and any liability resulting from this incident. If it is ultimately determined that the Company bears some responsibility, and therefore liability, for the costs and damages caused by this event, we will rely on our contractual indemnity rights and on our insurance coverage to the extent available. If our contractual indemnities are determined to be unavailable, or the indemnitors fail or are unable to fulfill their contractual indemnity obligations, or if the damages and costs ultimately determined to be the Company’s responsibility exceed our available insurance coverage, we could be liable for amounts that could have a material adverse impact on our financial condition, results of operations and cash flows.

Through September 30, 2011, the Company incurred and expensed legal fees of $46.9 million. The Company has not accrued any amounts relating to this matter because we do not believe at the present time a loss is probable.

Other Litigation

In 2001, the Company discovered that contaminated underground water from a former manufacturing site in Houston (see discussion below under Environmental Matters) had migrated under an adjacent residential area. Pursuant to applicable state regulations, the Company notified the affected homeowners. Concerns over the impact on property values of the underground water contamination and its public disclosure led to a number of claims by homeowners. The Company has settled these claims, primarily as a result of the settlement of a class action lawsuit, and is obligated to reimburse 197 homeowners for any diminution in value of their property due to contamination concerns at the time of sale.

Based upon 2009 testing results of monitoring wells on the southeastern border of the plume, the Company notified 33 homeowners whose property is adjacent to the class area that their property may be affected. The Company is taking remedial measures to prevent these properties from being affected.

The Company believes, based on its review of the facts and law, that any potential exposure from existing agreements as well as any possible new claims that may be filed with respect to this underground water contamination will not have a material adverse effect on its financial position or results of operations. The Company’s consolidated balance sheet included a liability of approximately $11.8 million for these matters as of September 30, 2011.

The Company has been named as a defendant in a number of multi-defendant, multi-plaintiff tort lawsuits since 1995. At September 30, 2011, the Company’s consolidated balance sheet included a liability of approximately $9.0 million for such cases. The Company believes, based on its review of the facts and law, that the potential exposure from these suits will not have a material adverse effect on its consolidated results of operations, financial condition or liquidity.

Tax Contingencies

The Company has legal entities in over 40 countries. As a result, the Company is subject to various tax filing requirements in these countries. The Company prepares its tax filings in a manner which it believes is consistent with such filing requirements. However, some of the tax laws and regulations to which the Company is subject require interpretation and/or judgment. Although the Company believes the tax liabilities for periods ending on or before the balance sheet date have been adequately provided for in the financial statements, to the extent a taxing authority believes the Company has not prepared its tax filings in accordance with the authority’s interpretation of the tax laws and regulations, the Company could be exposed to additional taxes.

Environmental Matters

The Company is currently identified as a potentially responsible party (PRP) with respect to two sites designated for cleanup under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) or similar state laws. One of these sites is Osborne, Pennsylvania (a landfill into which a predecessor of the PCS operation in Grove City, Pennsylvania deposited waste), where remediation is complete and remaining costs relate to ongoing ground water treatment and monitoring. The other is believed to be a de minimis exposure. The Company is also engaged in site cleanup under the Voluntary Cleanup Plan of the Texas Commission on Environmental Quality at former manufacturing locations in Houston and Missouri City, Texas. Additionally, the Company has discontinued operations at a number of other sites which had been active for many years. The Company does not believe, based upon information currently available, that there are any material environmental liabilities existing at these locations. At September 30, 2011, the Company’s consolidated balance sheet included a noncurrent liability of approximately $5.4 million for environmental matters.

Note 14: Fair Value of Financial Instruments

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

Cash and cash equivalents include highly liquid investments with a maturity of ninety days or less at the time of purchase. Cash equivalents consist primarily of money market securities, U.S. treasury bills, other U.S. agency notes, short-term commercial paper and corporate debt securities, all of which are considered Level 1 under the ASC’s fair value hierarchy. Total cash equivalents were approximately $1.17 billion and $1.38 billion at September 30, 2011 and December 31, 2010, respectively.

Fair value of the Company’s fixed rate debt (based on level 1 quoted market rates) was (in millions):

	September 30, 2011				December 31, 2010
	Principal		Fair Value		Principal		Fair Value
Fixed rate Senior Notes	$	1,250.0	$	1,443.7	$	750.0	$	828.6
2.5% Convertible Debentures		–		–		500.0		724.4
	$	1,250.0	$	1,443.7	$	1,250.0	$	1,553.0

As indicated in Note 8 of the Notes to Consolidated Condensed Financial Statements, during the second quarter of 2011, the Company entered into an agreement with a third party financial intermediary for the purchase of 5.0 million call options on its common stock for a total premium payment of $21.9 million. During the third quarter of 2011, the Company received net proceeds of $9.7 million for the settlement of 3.2 million options. The remaining 1.8 million of options expired upon maturity as the market value of the options was below their strike price.

Proceeds received and changes in the estimated fair value of the call options were as follows (in millions):

	Nine Months Ended September 30, 2011
Beginning balance	$	–
Premium paid		21.9
Proceeds received from settlement of options		(9.7	)
Change in estimated fair value		(12.2	)
Balance at September 30, 2011	$	–

In order to mitigate the effect of exchange rate changes, the Company will often attempt to structure sales contracts to provide for collections from customers in the currency in which the Company incurs its manufacturing costs. In certain instances, the Company will enter into forward foreign currency exchange contracts to hedge specific large anticipated receipts or disbursements in currencies for which the Company does not traditionally have fully offsetting local currency expenditures or receipts. The Company was party to a number of long-term foreign currency forward contracts at September 30, 2011, some of which extend through 2013. The purpose of the majority of these contracts was to hedge large anticipated non-functional currency cash flows on major subsea, drilling, valve or other equipment contracts involving the Company’s United States operations and its wholly-owned subsidiaries in Italy, Romania, Singapore and the United Kingdom. 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 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 determines the fair value of its outstanding foreign currency forward contracts based on quoted exchange rates for the respective currencies applicable to similar instruments. These quoted exchange rates are considered to be Level 2 observable market inputs. Information relating to the contracts as of September 30, 2011 follows:

Total gross volume bought (sold) by notional currency and maturity date on open derivative contracts at September 30, 2011 was as follows (in millions):

Notional Amount Swaps

Notional Amount - Buy

Notional Amount - Sell

2011

2012

Total

2011

2012

2013

Total

2011

2012

2013

Total

FX Forward Contracts

Notional currency

in:

EUR

–

59.6

92.3

1.0

152.9

(1.5

)

(20.2

)

–

(21.7

)

GBP

–

0.1

34.0

–

34.1

(2.0

)

(11.7

)

–

(13.7

)

MYR

–

19.2

–

19.2

–

NOK

–

90.0

–

90.0

–

RON

–

(10.0

)

–

(10.0

)

SGD

–

13.8

3.2

–

17.0

–

USD

–

13.6

0.7

–

14.3

(52.0

)

(41.9

)

(0.1

)

(94.0

)

FX Options

EUR

–

30.1

–

30.1

–

Interest Rate Swaps

USD

–

800.0

–

The fair values of derivative financial instruments recorded in the Company’s Consolidated Condensed Balance Sheets at September 30, 2011 and December 31, 2010 were as follows:

	September 30, 2011				December 31, 2010
	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedges:
Foreign exchange contracts –
Current	$	0.8	$	6.3	$	0.7	$	1.8
Non-current		–		0.2		–		–
Total derivatives designated as hedges		0.8		6.5		0.7		1.8

Derivatives not designated as hedges:
Foreign exchange contracts –
Current		1.1		5.9		1.4		–
Non-current		0.1		4.2		–		–

Interest Rate Swaps –
Current		1.4		–		–		–
Non-current		–		–		4.8		–

Total derivatives not designated as hedges		2.6		10.1		6.2		–

Total derivatives	$	3.4	$	16.6	$	6.9	$	1.8

The effects of derivative financial instruments on the Company’s consolidated condensed financial statements for the three months ended September 30, 2011 and September 30, 2010 were as follows (in millions):

	Effective Portion									Ineffective Portion and Other
Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in OCI on Derivatives at September 30,				Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income at September 30,				Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives at September 30,
Derivatives in Cash Flow Hedging Relationships	2011		2010			2011		2010			2011		2010

Foreign exchange contracts	$	(7.1)	$	4.4	Revenues	$	0.6	$	(2.4)	Cost of sales - ineffective portion	$	(0.3)	$	0.5
					Cost of sales		(1.7)		(3.6)
					Depreciation and amortization		−		−
Total	$	(7.1)	$	4.4		$	(1.1)	$	(6.0)		$	(0.3)	$	0.5

The effects of derivative financial instruments on the Company’s consolidated condensed financial statements for the nine months ended September 30, 2011 and September 30, 2010 were as follows (in millions):

	Effective Portion									Ineffective Portion and Other
Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in OCI on Derivatives at September 30,				Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income at September 30,				Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives at September 30,
Derivatives in Cash Flow Hedging Relationships	2011		2010			2011		2010			2011			2010

Foreign exchange contracts	$	(4.2)	$	(8.5)	Revenues	$	2.5	$	(5.0)	Cost of sales - ineffective portion	$	(0.7)		$	(1.5)
					Cost of sales		(8.2)		(9.7)
					Depreciation and amortization		(0.1)		(0.1)
Total	$	(4.2)	$	(8.5)		$	(5.8)	$	(14.8)		$	(0.7	)	$	(1.5)

The amount of gain (loss) recognized on derivatives not designated as hedging instruments was (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Foreign currency contracts:
Cost of sales	$	(1.4	)	$	(2.3	)	$	(2.2	)	$	0.5
Other costs		(6.4	)		–			(6.4	)		–

Interest rate swaps:
Interest, net		–			1.1			(0.2	)		7.2

Equity call options:
Other costs		(13.8	)		–			(12.2	)		–

Total	$	(21.6	)	$	(1.2	)	$	(21.0	)	$	7.7

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

In addition to the historical data contained herein, this document includes forward-looking statements regarding future market strength, customer spending and order levels, revenues and earnings of the Company, as well as expectations regarding equipment deliveries, margins, profitability, the ability to control and reduce raw material, overhead and operating costs, cash generated from operations, legal fees, costs associated with, or any liability for, a number of lawsuits filed against the Company in connection with the Deepwater Horizon matter, capital expenditures and the use of existing cash balances and future anticipated cash flows made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company’s actual results may differ materially from those described in any forward-looking statements. Any such statements are based on current expectations of the Company’s performance and are subject to a variety of factors, some of which are not under the control of the Company, which can affect the Company’s results of operations, liquidity or financial condition. Such factors may include overall demand for, and pricing of, the Company’s products; the size and timing of orders; the Company’s ability to successfully execute large subsea and drilling projects it has been awarded; the possibility of cancellations of orders in backlog; the Company’s ability to convert backlog into revenues on a timely and profitable basis; the impact of acquisitions the Company has made or may make; changes in the price of (and demand for) oil and gas in both domestic and international markets; raw material costs and availability; political and social issues affecting the countries in which the Company does business, including the difficulty companies are facing in obtaining drilling permits following the lifting of a temporary moratorium imposed by the United States government on drilling activities in deepwater areas of the Gulf of Mexico; fluctuations in currency markets worldwide; and variations in global economic activity. In particular, current and projected oil and gas prices historically have generally directly affected customers’ spending levels and their related purchases of the Company’s products and services. As a result, changes in oil and gas price expectations may impact the demand for the Company’s products and services and the Company’s financial results due to changes in cost structure, staffing and spending levels the Company makes in response thereto. See additional factors discussed in “Factors That May Affect Financial Condition and Future Results” contained herein.

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

THIRD QUARTER 2011 COMPARED TO THIRD QUARTER 2010

Market Conditions

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

	Quarter Ended September 30,				Increase (Decrease)
	2011		2010		Amount			%
Drilling activity (average number of working rigs during period)(1):
United States		1,945		1,622		323			19.9	%
Canada		443		361		82			22.7	%
Rest of world		1,169		1,111		58			5.2	%
Global average rig count		3,557		3,094		463			15.0	%
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	$	89.51	$	76.09	$	13.42			17.6	%
Henry Hub natural gas spot price per MMBtu in U.S. dollars	$	4.12	$	4.28	$	(0.16	)		(3.7	)%
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
West Texas Intermediate Cushing, OK crude oil contract (per barrel)	$	80.26	$	83.42	$	(3.16	)		(3.8	)%
Henry Hub Natural Gas contract (per MMBtu)	$	4.11	$	4.29	$	(0.18	)		(4.2	)%
Number of deepwater floaters and semis under contract in competitive major markets at period-end(3):
U.S. Gulf of Mexico		27		31		(4	)		(12.9	)%
Northwestern Europe		37		34		3			8.8	%
West Africa		33		27		6			22.2	%
Southeast Asia and Australia		26		28		(2	)		(7.1	)%

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

(2) Source: Bloomberg

(3) Source: ODS-Petrodata Ltd.

The average number of worldwide operating rigs trended upward throughout the third quarters of 2011 and 2010 due mainly to strength in the North American markets. Over 87% of the increase in average worldwide operating rigs during the third quarter of 2011 as compared to the third quarter of 2010 was due to higher North American activity levels largely reflecting the impact of unconventional resource opportunities in the region and higher average crude oil prices.

Crude oil prices (West Texas Intermediate, Cushing, OK) trended downward for much of the third quarter of 2011 closing the period at just under $80 per barrel due primarily to the global economic uncertainty that currently exists. Prices were more volatile during the third quarter of 2010 but ended the quarter up more than $4 per barrel as compared to prices at the beginning of the quarter. On average, crude oil prices were 17.6% higher during the third quarter of 2011 as compared to the third quarter of 2010 due to increasing prices during the fourth quarter of 2010 and the first half of 2011 that reached a high of nearly $114 per barrel in April 2011. The twelve month futures price for crude oil at September 30, 2011 was relatively flat compared to spot prices at the end of the quarter.

Natural gas (Henry Hub) prices trended downward during the third quarters of 2011 and 2010 as compared to price levels at the beginning of both periods. On average, prices during the third quarter of 2011 were down 3.7% as compared to the same period in 2010, due largely to increased supplies available in North America as a result of new unconventional resource developments and higher activity levels. However, the 12-month futures strip price for natural gas at September 30, 2011 was up approximately 12% from spot price levels at the end of the quarter.

Historically, the level of capital expenditures by the Company’s customers, which impacts demand for much of the Company’s products and services, has been affected by the level of drilling, exploration and production activity as well as the price of oil and natural gas. The recent changes in crude oil and natural gas prices and expectations of future prices as reflected in the twelve-month futures strip price may affect the future capital spending plans of certain of the Company’s customers.

Consolidated Results

Net income for the third quarter of 2011 totaled $164.5 million, or $0.67 per diluted share, compared to net income for the third quarter of 2010 of $148.7 million, or $0.61 per diluted share. Included in the third quarter 2011 results were pre-tax charges of $34.2 million, or approximately $0.11 per diluted share, primarily associated with costs for BOP litigation, the mark-to-market impact on certain centrally-managed currency derivatives and certain employee severance and restructuring-related activities. Results for the third quarter of 2010 included pre-tax charges of $10.4 million, or $0.03 per diluted share, for acquisition integration activities, employee severance, BOP litigation and certain other matters.

Total revenues for the Company increased $158.8 million, or 10.4%, during the three months ended September 30, 2011 as compared to the three months ended September 30, 2010 on the strength of higher sales in each of the Company’s business segments.

•

Over three-fourths of the revenue increase was due to double-digit sales increases in each product line of the Valves & Measurement (V&M) segment during the third quarter of 2011 as compared to the third quarter of 2010.

•

Sales increases in the Drilling and Production Systems (DPS) segment and the Process & Compression Systems (PCS) segment are discussed in more detail below.

As a percent of revenues, cost of sales (exclusive of depreciation and amortization) decreased from 68.7% during the third quarter of 2010 to 67.4% for the third quarter of 2011. Higher margins in the V&M segment, due largely to better pricing and higher volumes on distributed valve product sales, added approximately 2.2 percentage-points to company-wide margins. Improved margins in the DPS segment, aided by the impact on subsea project contract estimates of the favorable resolution of various cost contingencies, also added approximately 1.0 percentage-points to the Company’s margins. These increases, however, were partially offset by lower PCS segment margins reflecting higher costs and lower volumes, primarily in the process systems business.

Selling and administrative expenses increased $33.2 million, or 15.8%, during the three months ended September 30, 2011 as compared to the three months ended September 30, 2010.

•

Selling and administrative expenses were 14.4% of revenues for the third quarter of 2011 as compared to 13.8% for the third quarter of 2010.

•

Nearly 80% of the increase was due to higher employee-related costs associated with higher headcount levels and increased travel.

Net interest for the three months ended September 30, 2011 was $20.6 million, an increase of $0.6 million from $20.0 million for the three months ended September 30, 2010. The increase was due primarily to the absence in the current year of a $1.1 million benefit from interest rate swaps recognized in the third quarter of 2010 partially offset by higher interest income. A decline in interest expense resulting from the payoff in the second and third quarters of 2011 of the Company’s 2.5% convertible debentures was mostly offset by higher interest expense from a $750.0 million public debt offering completed in the second quarter of 2011.

The Company’s effective tax rates for the three months ended September 30, 2011 and 2010 were 16.9% and 19.7%, respectively. The tax provision was reduced by:

•

realization of certain tax benefits totaling $2.4 million associated with tax planning strategies put in place in prior years,

•

the recognition of certain historical tax benefits totaling $3.4 million as prior uncertainty regarding those benefits has been resolved during the third quarter of 2011, and

•

a reduction in the tax provision of $4.8 million from the finalization of prior year tax returns.

Segment Results

DPS Segment –

	Quarter Ended September 30,						Increase
($ in millions)	2011			2010			$		%

Revenues	$	977.2		$	944.0		$	33.2	3.5	%
Income before income taxes	$	196.6		$	161.8		$	34.8	21.5	%
Income before income taxes as a percent of revenues		20.1	%		17.1	%		N/A	3.0	%

Orders	$	1,149.1		$	718.0		$	431.1	60.0	%
Backlog (at period end)	$	3,755.9		$	3,401.9		$	354.0	10.4	%

Revenues

The increase in revenues was mainly due to:

•

a 22% increase in sales of surface equipment as a result of higher activity levels in most major worldwide regions, particularly in unconventional resource areas of North America, and

•

an 18% increase in sales of drilling equipment largely as a result of increased aftermarket demand for spares and repair services.

These revenue increases were partially offset by an 18% decline in subsea equipment sales due mainly to lower deliveries and activity levels relating to projects offshore West Africa, Egypt and Venezuela.

Income before income taxes as a percent of revenues

The increase in the ratio of income before income taxes as a percent of revenues was due primarily to a 3.7 percentage-point decrease in the ratio of cost of sales to revenues during the third quarter of 2011 due mainly to higher drilling and surface equipment margins as a result of higher volumes and better mix (approximately a 3.2 percentage-point margin increase). Major subsea project margins were also up in the third quarter of 2011 as compared to the third quarter of 2010 due to the impact on project contract estimates of the favorable resolution of various cost contingencies.

Partially offsetting the impact of the cost of sales decrease in relation to revenues was an increase of 0.5 percentage-points in the ratio of selling and administrative costs to revenues due to (i) higher employee-related costs caused by higher headcount levels and (ii) higher bad debt expense.

Orders

An 84% increase in drilling orders and a 74% increase in subsea equipment orders accounted for approximately 82% of the increase in total segment orders in the third quarter of 2011 as compared to the same period last year.

•

The increase in drilling orders was driven mainly by higher demand for blowout preventers for land and jackup rigs and increased aftermarket activity levels.

•

The increase in subsea orders reflected stronger demand for equipment to be used offshore China, Australia and in the Norwegian sector of the North Sea, as well as additional work requested on existing projects.

•

Surface eequipment orders were also up 28% in the current period due mainly to higher worldwide activity levels.

Backlog (at period-end)

A 66% increase in drilling equipment backlog as a result of strong order activity was partially offset by a 6% decline in backlog for subsea equipment at September 30, 2011 as compared to September 30, 2010. Surface equipment backlog levels were up modestly compared to the same period last year.

V&M Segment –

	Quarter Ended September 30,						Increase
($ in millions)	2011			2010			$		%

Revenues	$	434.4		$	312.7		$	121.7	38.9	%
Income before income taxes	$	81.5		$	43.0		$	38.5	89.5	%
Income before income taxes as a percent of revenues		18.8	%		13.7	%		N/A	5.1	%

Orders	$	508.6		$	396.8		$	111.8	28.2	%
Backlog (at period end)	$	1,090.4		$	740.0		$	350.4	47.4	%

Revenues

Sales increased at double-digit levels across all product lines during the third quarter of 2011 as compared to the same period in 2010 with engineered and distributed valves accounting for more than three-fourths of the improvement in total segment sales.

•

Engineered valve sales increased 58% on the strength of higher pipeline construction project activity in North America and certain international locations.

•

Distributed valve sales were up 34% based on higher North American activity levels and increased shipments from higher beginning-of-period backlog levels.

Income before income taxes as a percent of revenues

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

•

a 1.0 percentage-point decrease in the ratio of cost of sales to revenues due largely to improved margins in the distributed valves product line as a result of higher pricing and increased volumes

•

a 1.3 percentage-point decrease in the ratio of depreciation and amortization to revenues mainly resulting from the impact of the increase in revenues on a relatively modest decline in the amortization of intangible assets, and

•

a 2.7 percentage-point decrease in the ratio of selling and administrative expenses to revenues as a result of the impact of revenues increasing at a greater rate than the increase in selling and administrative expenses.

Selling and administrative expenses increased 17% due mainly to higher employee-related costs primarily as a result of headcount increases.

Orders

Orders increased in all product lines with distributed valves accounting for 55% of the total segment increase in the third quarter of 2011 as compared to the third quarter of 2010, mainly as a result of strong North American activity levels, particularly in unconventional resource regions. Demand for engineered valves increased 12% and process valve orders were also up 32%, due largely to the award of certain large projects in the Gulf of Mexico and higher project activity levels in North America.

Backlog (at period-end)

Backlog levels for all product lines in the V&M segment were up from September 30, 2010, with nearly 50% of the increase attributable to higher engineered valves backlog caused by recent higher demand. Stronger demand also resulted in a 108% increase in backlog levels for distributed valves and a 73% increase in process valves backlog as compared to prior year levels.

PCS Segment –

	Quarter Ended September 30,						Increase (Decrease)
($ in millions)	2011			2010			$			%

Revenues	$	274.3		$	270.4		$	3.9		1.4	%
Income before income taxes	$	24.0		$	41.4		$	(17.4	)	(42.0	)%
Income before income taxes as a percent of revenues		8.7	%		15.3	%		N/A		(6.6	)%

Orders	$	345.4		$	365.0		$	(19.6	)	(5.4	)%
Backlog (at period end)	$	941.2		$	793.5		$	147.7		18.6	%

Revenues

The increase is due primarily to a 17% improvement in sales of reciprocating and centrifugal compression equipment resulting largely from (i) stronger international shipments of Superior compressors and (ii) better industrial economic conditions which resulted in higher shipments of plant air machines during the third quarter of 2011 as compared to the third quarter of 2010. These increases were mostly offset by a 16% decline in sales of process systems applications as a result of lower activity levels and the timing of shipments due to execution issues for various custom engineered projects, particularly in North and South America.

Income before income taxes as a percent of revenues

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

•

a 7.5 percentage-point increase in the ratio of cost of sales to revenues during the third quarter of 2011, due mainly to (i) a gain recognized in the third quarter of 2010 from the sale of aftermarket inventory and certain intangible assets associated with a compressor line that is no longer produced by the Company and for which no new units had been sold since the 1990’s (approximately a 3.1 percentage-point increase in the ratio) and (ii) lower project margins in the process systems custom engineered project business due to higher costs (some of which was due to execution issues) and lower volumes, and

•

a 1.0 percentage-point increase in the ratio of selling and administrative costs to revenues resulting mainly from higher legal fees and employee-related costs.

These changes were partially offset by a decrease of 2.0 percentage points in the ratio of depreciation and amortization to revenues during the third quarter of 2011, due mainly to lower amortization of intangible assets and lower capital spending in recent periods.

Orders

The decrease in orders was due mainly to a 40% decline in process systems orders as a result of the timing of several large awards received in the third quarter of 2010 which did not repeat in the third quarter of 2011. This decrease was largely offset by:

•

a 54% increase in centrifugal compression equipment orders due to strong growth across all major regions, particularly in the Far East, for engineered gas, air and air separation equipment, and

•

a 32% increase in demand for reciprocating compression equipment mainly as a result of several large package awards and higher international demand for Superior Compressors.

Backlog (at period-end)

A 55% increase in centrifugal compression equipment backlog, mainly due to strong demand for engineered gas, air and air separation equipment, accounted for approximately 89% of the total segment backlog increase from September 30, 2010 levels. Additionally, reciprocating compression equipment backlog was up 27% while weak demand caused process systems backlog to decline 3% from the prior year.

Corporate Segment –

The $43.0 million increase in the loss before income taxes of the Corporate segment during the third quarter of 2011 as compared to the third quarter of 2010 (see Note 10 of the Notes to Consolidated Condensed Financial Statements) was due primarily to:

•

$2.1 million of foreign currency losses recorded in the third quarter of 2011 due to the strengthening of the U.S. dollar against certain other currencies,

•

a a $4.0 million increase in depreciation and amortization expense due mainly to higher spending in recent periods for development of the Company’s enhanced business information systems,

•

a $12.8 million increase in selling and administrative expenses due primarily to (i) higher employee-related compensation, benefit and travel costs, as well as (ii) a benefit of $3.6 million recognized in the third quarter of 2010 for removal of an uncertainty associated with collection of a balance due from an historical acquisition which did not repeat in the third quarter of 2011, and

•

higher interest and other costs which are described in more detail under “Consolidated Results” above.

NINE MONTHS ENDED SEPTEMBER 30, 2011 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2010

Market Conditions

Information related to a measure of drilling activity and certain commodity spot and futures prices follows:

	Nine Months Ended September 30,				Increase (Decrease)
	2011		2010		Amount			%
Drilling activity (average number of working rigs during period)(1):
United States		1,830		1,492		338			22.7	%
Canada		406		332		74			22.3	%
Rest of world		1,160		1,087		73			6.7	%
Global average rig count		3,396		2,911		485			16.7	%
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	$	95.39	$	77.58	$	17.81			23.0	%
Henry Hub natural gas spot price per MMBtu in U.S. dollars	$	4.22	$	4.56	$	(0.34	)		(7.5	)%
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
West Texas Intermediate Cushing, OK crude oil contract (per barrel)	$	80.26	$	83.42	$	(3.16	)		(3.8	)%
Henry Hub Natural Gas contract (per MMBtu)	$	4.11	$	4.29	$	(0.18	)		(4.2	)%

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

(2) Source: Bloomberg

The average number of worldwide operating rigs trended upwards during the first nine months of 2011 and 2010, in spite of dips during the second quarters of both years largely driven by seasonal trends in Canada. Increased North American activity levels accounted for nearly 85% of the average global rig count increase during the first nine months of 2011 as compared to the first nine months of 2010.

Crude oil prices (West Texas Intermediate, Cushing, OK) increased during the first half of 2011 reaching a high of nearly $114 per barrel in April 2011 before declining during the remainder of the period to its low point for the year of just under $80 per barrel at September 30, 2011, as a result of the global economic uncertainty that currently exists. Oil prices during the nine months ended September 30, 2010 remained relatively flat ending the period slightly below the spot price at the beginning of the year. On average, however, prices for the first nine months of 2011 were up 23% as compared to the first nine months of 2010.

Natural gas (Henry Hub) prices trended downward during the first nine months of 2011 and 2010, although the price decline during the first nine months of 2011 was more modest than the decline during the first nine months of 2010. Prices at September 30, 2011 and 2010 were near their lows for both year-to-date periods. A significant portion of the Company’s business is impacted by the exploration and production of natural gas. Should the 12-month futures strip price for natural gas stay depressed for a long period of time, the portion of the North American rig count directed to gas drilling could decline, which could impact the Company’s future order flow.

Consolidated Results

Net income for the nine months ended September 30, 2011 totaled $422.1 million, or $1.69 per diluted share, compared to net income for the nine months ended September 30, 2010 of $398.2 million, or $1.61 per diluted share. Included in the results for the first nine months of 2011 were pre-tax charges of $63.2 million, or approximately $0.20 per diluted share, primarily associated with costs for BOP litigation, the mark-to-market impact on certain centrally-managed currency derivatives and certain employee severance and restructuring-related activities. Results for the first nine months of 2010 included pre-tax charges of $39.1 million, or approximately $0.12 per diluted share, for acquisition integration activities, employee severance, BOP litigation and certain other matters.

Total revenues for the Company increased $601.7 million, or 13.9%, during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010, on the strength of higher sales in each of the Company’s business segments. Sales in the DPS, V&M and PCS segments are discussed in more detail below.

As a percent of revenues, cost of sales (exclusive of depreciation and amortization) increased from 68.1% during the first nine months of 2010 to 69.2% for the comparable period in 2011. The increase was due largely to margin declines in the DPS and PCS segments which more than offset higher V&M margins.

Selling and administrative expenses increased $111.7 million, or 18.3%, during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. As a percent of revenues, selling and administrative expenses increased from 14.1% during the first nine months of 2010 to 14.7% for the first nine months of 2011. This increase was due largely to:

•

$86.2 million of higher employee-related costs resulting mainly from headcount increases and increased travel,

•

a $13.1 million increase in bad debt expense associated primarily with (i) receivables arising from work previously performed in Libya that are unlikely to be collected due to sanctions imposed by the United States government during 2011, and (ii) the year-over-year impact of reversals in the first nine months of 2010 of certain bad debt reserves upon final collection of amounts due, and

•

higher facility related costs and costs of implementing an enhanced business information system.

Depreciation and amortization expense decreased $8.2 million, from $153.7 million for the first nine months of 2010 to $145.5 million for the first nine months of 2011. The decrease was due mainly to lower amortization of intangible assets, primarily in the PCS segment.

Net interest for the nine months ended September 30, 2011 was $62.7 million, an increase of $6.3 million, from $56.4 million for the nine months ended September 30, 2010. The increase was due primarily to the absence in the current year of a $7.2 million benefit from interest rate swaps recognized in the first nine months of 2010 partially offset by higher interest income. A decline in interest expense resulting from the payoff in the second and third quarters of 2011 of the Company’s 2.5% convertible debentures was mostly offset by higher interest expense from a $750.0 million public debt offering completed in the second quarter of 2011.

The Company’s effective tax rates for the nine months ended September 30, 2011 and 2010 were 19.6% and 23.1%, respectively. The tax provision was reduced by:

•

realization of certain tax benefits totaling $18.4 million associated with tax planning strategies put in place in prior years,

•

the recognition of certain historical tax benefits totaling $12.2 million as prior uncertainty regarding those benefits has been resolved during the first nine months of 2011, and

•

a reduction in the tax provision of $4.8 million from the finalization of prior year tax returns.

Segment Results

DPS Segment –

	Nine Months Ended September 30,						Increase (Decrease)
($ in millions)	2011			2010			$		%

Revenues	$	2,845.5		$	2,600.1		$	245.4	9.4	%
Income before income taxes	$	474.3		$	463.8		$	10.5	2.3	%
Income before income taxes as a percent of revenues		16.7	%		17.8	%		N/A	(1.1	)%

Orders	$	3,410.1		$	2,034.6		$	1,375.5	67.6	%

Revenues

Approximately three-fourths of the increase in revenues was due to a 24% increase in sales of surface equipment, mainly due to increased activity levels in North America, the Middle East and the Asia-Pacific region. Sales of drilling equipment increased 13% primarily due to higher demand for aftermarket spares, repairs and services. These increases were partially offset by a 5% decline in subsea equipment sales primarily due to lower manufacturing activity levels for projects offshore West Africa, South America and Egypt.

Income before income taxes as a percent of revenues

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

•

a 2.6 percentage-point decrease in margins on drilling and subsea projects, almost 70% of which was due to a $51.0 million adjustment during the first nine months of 2011 related to cost overruns on a large subsea project in Nigeria. Offsetting this decrease were higher volumes of higher-margin surface equipment sales, which increased margins by approximately 2.1 percentage points, and

•

a 0.6 percentage-point increase in the ratio of selling and administrative expenses to revenues as selling and administrative expenses increased 15.7% during the first nine months of 2011 as compared to the first nine months of 2010 due mainly to higher employee-related costs, which accounted for approximately three-fourths of the increase, and a $7.8 million increase in bad debt expense associated primarily with receivables arising from work previously performed in Libya that are unlikely to be collected due to sanctions imposed by the United States government in 2011, as well as the year-over-year impact of the reversal in the first nine months of 2010 of certain bad debt reserves upon final collection of amounts due.

Orders

Drilling equipment orders increased 144% in the first nine months of 2011 as compared to the same period last year, accounting for 62% of the increase in total segment orders. Awards received in 2011 for equipment for new deepwater rig construction projects accounted for almost 60% of the drilling increase with the remainder attributable to higher demand for blowout preventers on land and jackup rigs, as well as for stack upgrades, spares, repairs and field service work. Other increases included:

•

a 58% increase in subsea equipment orders as more than twice as many subsea trees were ordered for projects during the first nine months of 2011 as compared to the same period last year, and

•

a 20% increase in surface equipment orders due mainly to higher activity levels in North America, the Middle East and in the North Sea.

V&M Segment –

	Nine Months Ended September 30,						Increase
($ in millions)	2011			2010			$		%

Revenues	$	1,200.8		$	937.0		$	263.8	28.2	%
Income before income taxes	$	212.2		$	137.3		$	74.9	54.6	%
Income before income taxes as a percent of revenues		17.7	%		14.7	%		N/A	3.0	%

Orders	$	1,462.5		$	1,137.0		$	325.5	28.6	%

Revenues

Higher North American activity levels were a major contributor to double digit sales increases across all product lines for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010.

•

Engineered valves and distributed valves account for more than three-fourths of the total sales increase.

•

Engineered valve sales increased 30% due largely to higher North American volumes and large subsea pipeline projects in the Gulf of Mexico.

•

Distributed valves sales were up 35% on the strength of higher recent bookings and higher beginning of the period backlog levels resulting from increased activity, particularly in unconventional resource regions in North America.

Income before income taxes as a percent of revenues

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

•

a 0.8 percentage-point decrease in the ratio of cost of sales to revenues due mainly to improved margins in the distributed valves product line due to better pricing and improved volumes,

•

a 0.9 percentage-point decrease in the ratio of depreciation and amortization to revenues due mainly to the impact of lower amortization of intangible assets on an increasing revenue base, and

•

a 1.3 percentage-point decrease in the ratio of selling and administrative expenses to revenues as selling and administrative expenses did not increase at the same rate as revenues during the current period. Selling and administrative expenses increased 18% in the first nine months of 2011 as compared to the first nine months of 2010, due largely to higher employee-related costs resulting from increased headcount and the full nine months’ impact of costs in 2011 associated with an acquisition made in February 2010.

Orders

Orders increased at double-digit rates in all product lines with distributed and engineered valves accounting for almost three-fourths of the total segment increase.

•

Engineered valve orders were up nearly 27% based on increased North American demand for pipeline valves associated with new pipeline development projects, particularly in unconventional resource areas.

•

Increased activity levels in North American unconventional resource regions was also a main contributor to a 41% increase in orders for distributed valves during the nine months ended September 30, 2011, as compared to the same period last year.

PCS Segment –

	Nine Months Ended September 30,						Increase (Decrease)
($ in millions)	2011			2010			$			%

Revenues	$	881.9		$	789.4		$	92.5		11.7	%
Income before income taxes	$	88.5		$	96.4		$	(7.9	)	(8.2	)%
Income before income taxes as a percent of revenues		10.0	%		12.2	%		N/A		(2.2	)%

Orders	$	1,040.2		$	908.3		$	131.9		14.5	%

Revenues

The increase in revenues was mostly due to:

•

a 45% increase in reciprocating compression equipment sales resulting mainly from international shipments of larger scale Superior compressor machines and higher volumes of aftermarket parts deliveries in the U.S., and

•

a nearly 20% increase in sales of centrifugal compression equipment resulting primarily from higher international deliveries of new plant air units and increased aftermarket activity levels.

These increases were partially offset by a 3% decline in process systems sales, primarily from the custom engineered business, due to the timing of shipments as a result of execution issues and lower activity levels.

Income before income taxes as a percent of revenues

The decrease in the ratio of income before income taxes as a percent of revenues in the first nine months of 2011 as compared to the first nine months of 2010 was primarily due to:

•

a 4.1 percentage-point increase in the ratio of cost of sales to revenues, due largely to lower margins of approximately 5.1 percentage points in the process systems product line (some of which was due to execution issues), which was partially offset by higher reciprocating and centrifugal compression equipment margins of 1.0 percentage-points, and

•

a 0.6 percentage-point increase in the ratio of selling and administrative costs to revenues as a result of higher employee-related costs due to headcount increases, higher costs associated with implementing an enhanced business information system, higher legal and consulting fees and higher bad debt expense largely resulting from the reversal in the first nine months of 2010 of a $2.5 million provision recorded in a prior period upon final collection of an overdue balance.

This was partially offset by a decrease of 2.5 percentage points in the ratio of depreciation and amortization to revenues, due mainly to certain intangible assets associated with the NATCO acquisition becoming fully amortized at the end of 2010, as well as lower depreciation expense in the first nine months of 2011 due to constrained capital spending in recent periods.

Orders

Nearly 83% of the increase in orders was attributable to a 55% increase in awards for centrifugal compression equipment reflecting strong demand from all worldwide regions for new plant air machines and equipment designed for engineered air, gas and air separation applications. Higher international demand for new Ajax units and Superior compressors also led to a 26% increase in reciprocating compression equipment orders. These increases were partially offset by a 6% decline in process systems orders, primarily in the custom engineered business, due to the timing of the issuance of large customer awards.

Corporate Segment –

The $70.1 million increase in the loss before income taxes of the Corporate segment during the first nine months of 2011 as compared to the first nine months of 2010 (see Note 10 of the Notes to Consolidated Condensed Financial Statements) was due primarily to:

•

$3.8 million of foreign currency losses recorded in the first nine months of 2011, due mainly to the strengthening of the U.S. dollar against certain other currencies, as compared to $7.8 million of foreign currency gains recognized during the first nine months of 2010,

•

a $3.1 million increase in depreciation and amortization expense due mainly to higher spending in recent periods for development of the Company’s enhanced business information systems,

•

a $24.5 million increase in selling and administrative expenses due primarily to higher employee-related compensation, benefit and travel costs, and

•

higher interest and other costs as described in more detail under “Consolidated Results” above

Liquidity and Capital Resources

Consolidated Condensed Statements of Cash Flows

During the first nine months of 2011, net cash used for operations totaled $120.6 million, an increase of $59.9 million from the $60.7 million of cash used from operations during the first nine months of 2010.

Cash totaling $727.4 million was used to increase working capital during the first nine months of 2011 compared to $632.3 million during the first nine months of 2010, an increase of $95.1 million.

During the first nine months of 2011, increased sales and the timing of collections resulted in higher receivables in each of the Company’s business segments at September 30, 2011 as compared to December 31, 2010. In addition, inventory levels increased company-wide, largely as a result of higher order rates and higher backlog levels and, in particular, inventory necessary to support the Company's subsea systems project backlog.

Cash used for investing activities increased by $106.4 million, from $147.0 million during the first nine months of 2010 to $253.4 million during the first nine months of 2011. This increase was due mainly to higher capital spending during the nine months ended September 30, 2011, as the drilling and surface businesses expanded their aftermarket capabilities and for enhancements to the Company’s worldwide SAP information technology platform.

Net cash provided by financing activities totaled $94.3 million for the first nine months of 2011, mainly reflecting $747.8 million of net cash proceeds received from the public offering of Senior Notes by the Company in September 2011. A significant portion of these proceeds, totaling $717.9 million, were used to repurchase on the open market or to redeem $500.0 million principal amount of the Company’s 2.5% Convertible Debentures and to acquire call options on 5.0 million shares of the Company’s common stock. Short-term borrowings, primarily at certain international locations, also increased $49.7 million during the first nine months of 2011. During the first nine months of 2010, the Company repaid short-term debt totaling $6.6 million and acquired 3,176,705 treasury shares for a total cash cost of $123.9 million. The Company also received $20.0 million of net cash during the nine months ended September 30, 2011 from stock option exercises and vesting of restricted stock awards.

Future liquidity requirements

On October 24, 2011, the Company closed on its acquisition of LeTourneau Technologies, Inc., a wholly-owned subsidiary of Joy Global Inc., for a cash payment of $375.0 million, subject to certain post closing adjustments.

The Company also expects to spend approximately $350 million for capital equipment and facilities for the full year of 2011.

Cash on hand at September 30, 2011 and future expected operating cash flows have been and will be utilized to fund, among other things, the purchase of LeTourneau Technologies, Inc. and the remainder of the Company’s 2011 capital spending program.

The Company believes, based on its current financial condition, existing backlog levels and current expectations for future market conditions, that it will be able to meet its short- and longer-term liquidity needs, subject to the outcome of the contingency created by the litigation surrounding the Deepwater Horizon matter, with the existing $1.5 billion of cash on hand, expected cash flow from future operating activities and amounts available under its $835.0 million five-year multi-currency Revolving Credit Facility, which ultimately expires on June 6, 2016 (see Note 8 of the Notes to Consolidated Condensed Financial Statements for additional information). At September 30, 2011, the amount available for borrowing under the Revolving Credit Facility totaled $809.6 million.

Factors That May Affect Financial Condition and Future Results

The Deepwater Horizon matter may have a material adverse effect on the Company.

See a more complete discussion of the Deepwater Horizon incident in Note 13 of the Notes to Consolidated Condensed Financial Statements.

The Deepwater Horizon matter has and will continue to have an impact on the Company for the foreseeable future. Preparation for and participation in the litigation and investigations regarding this matter will continue to divert Company resources and management’s attention, as well as that of the Company’s Drilling Systems division.

The Company derives a significant portion of its revenues from deepwater activities around the world. In fact, six of the Company’s eleven divisions participate in this market. New regulations imposed by the United States government on drilling activities in deepwater areas of the Gulf of Mexico, as well as similar regulations adopted in other jurisdictions where the Company and its customers do business, could affect a portion of the Company’s business and may cause customers who are involved in deepwater drilling to face additional costs and regulations involving future drilling. While these regulations may decrease drilling activity, they also may require customers to purchase additional components and/or services currently available from the Company and could require the Company to develop new technologies. The Company may also be subject to future regulations regarding the development and testing of our equipment, including our blowout preventers, which may add to the manufacturing cost of such equipment. The Company may be unable to recover such additional costs through higher sales prices, which could negatively impact the Company’s future profitability and cash flows. Other regions are currently considering similar regulations.

Additionally, this event may make it increasingly difficult for the industry to obtain adequate insurance on economic terms, if at all.

If our contractual indemnities are determined to be inapplicable, or the indemnitors fail or are unable to fulfill their contractual indemnity obligations, and if the damages and costs ultimately determined to be the Company’s responsibility exceed our available insurance coverage, we could be liable for amounts which could have a material adverse impact on our financial condition, results of operations and cash flows.

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

Cameron provides products and systems that serve customers involved in oil and gas exploration, development and production, as well as in certain industrial markets. Certain of the Company’s equipment is designed to operate in high-temperature, high-pressure environments on land, on offshore platforms and on the seabed. Cameron also provides aftermarket parts and repair services at numerous facilities located around the world or at customer sites. Because of the extreme temperature and pressure environments in which certain of the Company’s equipment operates, a failure of such equipment could cause damage to the equipment, damage to a customer’s other property, personal injury and environmental contamination, whether onshore or offshore. In addition, improper servicing and maintenance of such equipment by Company service technicians or by other third parties can contribute to potential failures of the Company’s equipment. Cameron is currently party to litigation involving personal injury, property damage and environmental contamination alleged to have been caused by failures of the Company’s equipment.

In an attempt to mitigate such risks, the Company has invested in engineering and design tools and equipment to enable engineers to conduct product modeling and simulations. The Company has a quality control program to examine materials received from third-party vendors prior to introducing such materials into the Company’s own manufacturing process and tests its products prior to delivery. Additionally, the Company provides training to its service technicians and seeks to mitigate its financial risks from potential failure of its equipment by maintaining property and casualty insurance coverage, which includes coverage for sudden and accidental environmental pollution.

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 revenues, depends to a large extent upon the level of capital expenditures related to oil and gas exploration, production, development, processing and transmission. Declines, as well as anticipated declines, in oil and gas prices could negatively affect the level of these activities, or could result in the cancellation, modification or rescheduling of existing orders. As an example, the substantial decline in oil and gas prices which began during the latter half of 2008 and continued into early 2009, combined with the constricted credit markets during that time, caused reductions in orders by the Company’s customers during 2009 which have, in certain cases, negatively impacted the Company’s 2010 and 2011 revenues and profitability.

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

At September 30, 2011, the Company’s backlog was $5.9 billion. The ability to meet customer delivery schedules for this backlog 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 or incentive 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 the timing of delivery of product currently in backlog. Failure to deliver backlog in accordance with expectations could negatively impact the Company’s financial performance and thus cause adverse changes in the market price of the Company’s outstanding common stock and other publicly-traded financial instruments.

A deterioration in future expected profitability or cash flows could result in an impairment of the Company’s goodwill.

Total Cameron goodwill approximated $1.5 billion at September 30, 2011, a large portion of which was allocated to the Company’s Process Systems division, which includes the majority of the NATCO operations acquired in 2009. As a result, any future deterioration in expected annual profitability or annual cash flows or a deterioration of expected markets served by the Company or its Process Systems division could negatively impact the estimated fair market values of both, which, if it were to occur, could increase the likelihood of a goodwill impairment charge being required. No goodwill impairment charge was required based on the Company’s annual evaluation conducted in the first quarter of 2011.

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

Cameron is a significant participant in serving the subsea systems projects market. This market is significantly different from the Company’s other markets since subsea systems projects are significantly larger in scope and complexity, in terms of both technical and logistical requirements. Subsea projects (i) typically involve long lead times, (ii) typically are larger in financial scope, (iii) typically require substantial engineering resources to meet the technical requirements of the project (iv) often involve the application of existing technology to new environments and in some cases, new technology and (v) can require significant amounts of foreign country, locally manufactured content. The Company’s subsea business unit received orders in the amount of $1.0 billion during the nine months ended September 30, 2011. Total backlog for the subsea business unit at September 30, 2011 was approximately $2.1 billion. To the extent the Company experiences unplanned efficiencies or difficulties in meeting the technical and/or delivery requirements of the projects, the Company’s earnings or liquidity could be positively or negatively impacted. The Company accounts for its subsea projects, as well as separation and drilling projects, using accounting rules for construction-type and production-type contracts. In accordance with this guidance, the Company estimates the expected margin on these projects and recognizes this margin as units are completed. 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 significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future period earnings. If the Company experiences cost underruns or overruns, the expected margin could increase or decline. In accordance with the accounting guidance for construction-type and production-type contracts, the Company would record a cumulative adjustment to increase or reduce the margin previously recorded on the related project in the period a change in estimate is determined. For example, the Company recorded a charge of $51.0 million during the first quarter of 2011 related to cost overruns on one of the Company’s large subsea projects. Continued work stoppages, labor issues and general instability in Nigeria could create further delays in performance of this project, which would have a detrimental effect on future costs and margins. Subsea systems projects accounted for approximately 11.9% of total revenues for the nine month period ended September 30, 2011. As of September 30, 2011, the Company had a subsea systems project backlog of approximately $1.4 billion.

Fluctuations in worldwide 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 BOPs. These production facilities are located in the United Kingdom, Brazil 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.

The Company’s worldwide operations expose it to economic risks and instability due to changes in economic conditions, civil unrest, foreign currency fluctuations, trade and other risks inherent to international business.

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

•

volatility in general economic, social and political conditions;

•

the effects of civil unrest and sanctions imposed and subsequently lifted by the United States government on transactions with Libya, where the Company has $22.7 million of unfilled orders involving equipment scheduled to be delivered to Libya and has recorded a charge in the first nine months of 2011 with respect to receivables which may be uncollectible from sales made prior to the imposition of sanctions and for impairments of certain other assets related to transactions previously entered into involving Libyan customers;

•

the effects of civil unrest on the Company’s business operations, customers and employees, such as that currently occurring in several other countries in the Middle East;

•

differing tax rates, tariffs, exchange controls or other similar restrictions;

•

changes in currency rates;

•

reductions in the number or capacity of qualified personnel.

Cameron has manufacturing and service operations that are essential parts of its business in developing countries and volatile areas in Africa, Latin America, Russia and other countries that were part of the Former Soviet Union, the Middle East, and Central and South East Asia. The Company also purchases a large portion of its raw materials and components from a relatively small number of foreign suppliers in developing countries. The ability of these suppliers to meet the Company’s demand could be adversely affected by the factors described above.

The Company’s worldwide operations expose it to political risks and uncertainties.

Doing business on a worldwide basis necessarily involves exposing the Company and its operations to political risks and the need for compliance with the laws and regulations of many jurisdictions. These laws and regulations include trade regulations, economic sanctions, restrictions on repatriation of income or capital, and various anti-bribery laws, as well as local content rules and the ever-increasing regulatory burdens being imposed on the oil and gas industry in general, all of which expose the Company to potential liability. They also include restrictions on the industry in accessing available oil and gas reserves, as was recently imposed in the U.S. Gulf of Mexico, and in drilling in environmentally sensitive areas.

Compliance with regulations on trade sanctions and embargoes poses a risk to Cameron since its business is conducted on a worldwide basis through various entities. Cameron has received a number of inquiries from U.S. governmental agencies regarding compliance with these regulations. The most recent of these inquiries was a March 25, 2009, letter from the Office of Global Security Risk of the U.S. Securities and Exchange Commission inquiring into the status of Cameron's non-U.S. entities' withdrawal from conducting business in or with Iran, Syria and Sudan, which begin in mid-2006 and has since been completed.

The Company does business and has operations in a number of developing countries that have relatively underdeveloped legal and regulatory systems when 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 where 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) and the United Kingdom’s Bribery Act of 2010, and similar statutes of other nations in these environments presents greater challenges to the Company than is the case in other, more developed countries. The Company has recently concluded an investigation into possible FCPA violations in connection with importation of equipment and supplies into Nigeria in response to inquiries by the Department of Justice and the Securities and Exchange Commission.

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.

The Company recently completed a Focused Assessment Audit regarding compliance with U.S. customs regulations and has received inquiries regarding compliance with customs laws and regulations from several other countries.

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

The Company is subject to environmental, health and safety laws and regulations that expose the Company to potential liability.

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

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

In December 2009, the United States Environmental Protection Agency (EPA) announced a finding under the United States Clean Air Act that greenhouse gas emissions endanger public health and welfare. The EPA also enacted regulations, effective January 1, 2010, requiring monitoring and reporting by certain facilities and companies of greenhouse gas emissions. 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, such as electric power generators and utilities.

To the extent Cameron is 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 modification of certain of its compression products, which involve use of power generation equipment, in order to lower any direct or indirect emissions of greenhouse gases from those facilities and products.

To the extent the Company’s customers, particularly those involved in power generation, petrochemical processing or petroleum refining, are subject to any of 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 similar levels in certain jurisdictions as historically seen or as currently anticipated, which could negatively impact their demand for the Company’s products and services.

The Company could also be impacted by new laws and regulations establishing cap-and-trade programs or 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 dampen demand for oil and gas production, they could lower spending by the Company’s customers for the Company’s products and services.

In addition, environmental concerns have been raised regarding the potential impact on underground water supplies of a procedure known as 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 to the surface for recovery. The Company provides equipment and services to companies employing this enhanced recovery technique.

Recently, certain U.S. states have proposed regulations regarding disclosure of chemicals used in hydraulic fracturing operations or have temporarily suspended issuance of permits for conducting such operations. Additionally, the U.S. Environmental Protection Agency is conducting a study of the hydraulic fracturing process and is developing permitting guidance for hydraulic fracturing activities that use diesel fuels in fracturing fluids. Should governmental regulations ultimately be imposed that restrict or curtail hydraulic fracturing activities, the Company’s revenues and earnings could be negatively impacted.

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

The Company has underway a project 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 the Company’s PCS segment. As this system continues to be deployed throughout the rest of the Company, delays or difficulties may initially be encountered in effectively and efficiently processing transactions and conducting business operations until such time as personnel are familiar with all appropriate aspects and capabilities of the upgraded systems, as was the case with the deployment of the upgraded system for certain businesses within the PCS segment.

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 and active third-party audit program, believes it is in substantial compliance with these regulations.

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. None of the Company’s facilities are rated above Small Quantity Generated status. 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. None of the Company’s facilities are classified as sites that generate more than minimal 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.

Under the direction of its corporate Vice President, Operations Integrity, Cameron has implemented a corporate “HSE Management System” based on 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 also has developed a corporate compliance audit program to address facility compliance with environmental, health and safety laws and regulations. The compliance program utilizes 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. Audit findings and corrective action plans are incorporated into and 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 and 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 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 traditionally have fully offsetting local currency expenditures or receipts. The Company was party to a number of long-term foreign currency forward contracts at September 30, 2011. The purpose of the majority of these contracts was to hedge large anticipated non-functional currency cash flows on major subsea, drilling, valve or other equipment contracts involving the Company’s United States operations and its wholly-owned subsidiaries in Italy, Romania, Singapore and the United Kingdom. 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 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.

Capital Markets and Interest Rates

The Company is subject to interest rate risk on its variable-interest rate borrowings and interest rate swaps. 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 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 4.5% and 6.375% 10-year Senior Notes and the 5.95% and 7.0% 30-year Senior Notes are principally dependent on prevailing interest rates. The fair value of the floating rate notes due June 2, 2014 is expected to approximate 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.

At September 30, 2011, the Company was a party to three interest rate swaps which effectively reduce the Company’s rate on $400.0 million of its 6.375% fixed rate borrowings to an effective fixed interest rate of approximately 5.49% through January 15, 2012, the maturity date of all three swaps. Each of the swaps provide for semiannual interest payments and receipts each January 15 and July 15 and provide for resets of the 3-month LIBOR rate to the then existing rate each January 15, April 15, July 15 and October 15. At September 30, 2011, the fair value of the interest rate swaps was reflected on the Company’s consolidated balance sheet as an asset with the change in the fair value of the swaps reflected as an adjustment to the Company’s consolidated interest expense.

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 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, 2011 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, 2011, except for the conversion during the quarter of certain businesses within the Company’s PCS segment to an enhanced version of Cameron’s SAP business information system.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Deepwater Horizon Matter

As described further in Note 13 of the Notes to Consolidated Condensed Financial Statements, claims for personal injury, wrongful death and property damage arising from the Deepwater Horizon incident have been and will continue to be asserted against the Company. Additionally, claims for pollution and other economic damages, including business interruption and loss of revenue, have been, and we anticipate will continue to be, asserted against all parties associated with this incident, including the Company, BP p.l.c and certain of its subsidiaries, the operator of Mississippi Canyon Block 252 upon which the Macondo well was being drilled, Transocean Ltd. and certain of its affiliates, the rig owner and operator, as well as other equipment and service companies. The Company has been named as one of several defendants in over 350 suits filed and presently pending in a variety of Federal and State courts, a number of which have been filed as class actions or multi-plaintiff actions. Other defendants including BP, Transocean and Halliburton have asserted cross-claims against us as we have asserted such claims against them. Most of the suits pending and presently pending in Federal courts have been consolidated into a single proceeding before a single Federal judge under the Federal rules governing multi-district litigation. The consolidated case is styled In Re: Oil Spill by the Oil Rig “Deepwater Horizon” in the Gulf of Mexico on April 20, 2010, MDL Docket No. 2179. There are also a small number of cases filed and presently pending in state courts. The States of Alabama and Louisiana have brought a claim for destruction of and/or harm to natural resources against those associated with this incident, including Cameron, in State of Alabama, ex. rel. Troy King, Attorney General vs. Transocean Ltd., et. al., Cause No. 2:10cv00691, U.S. Dist. Ct., M.D. Ala., and State of Louisiana vs. BP Exploration & Production , Inc., et. al. MDL No. 2179, as have a number of other local governmental entities and 3 Mexican states. It is possible other such claims may be asserted against the Company by the United States Government (USG) and by other Gulf and/or East Coast States, whose Attorneys General have notified the Company to preserve documents in the event of a claim, and possibly by other parties. The USG has brought suit against BP and certain other parties associated with this incident for recovery under statutes such as the Oil Pollution Act of 1990 (OPA) and the Clean Water Act, which suit has been made part of the MDL proceedings. While the Company was not named as a defendant in this suit by the USG, BP has brought a third-party complaint for contribution under OPA against several parties associated with this incident which were not named by the USG, including the Company. A shareholder derivative suit, Berzner vs. Erikson, et al., Cause No. 2010-71817 in the 190th District Court of Harris County, Texas, has been filed against the Company’s directors in connection with this incident and its aftermath alleging the Company’s directors failed to exercise their fiduciary duties regarding the safety and efficacy of its products.

The Federal Court overseeing the multi-district litigation has ruled that it will begin trying liability issues arising out of the Deepwater Horizon Matter in February 2012, and has issued a number of orders to effectuate this scheduling.

The Company has retained counsel and is, along with counsel, actively participating in the investigation into this matter and the litigation, and its attendant discovery, arising out of this matter. Our counsel are currently evaluating the theories of recovery being relied on by the claimants and cross-claimants and the damages they are asserting as well as our defenses, both factual and legal. Through September 30, 2011, the Company had incurred and expensed legal fees of $46.9 million. The Company has not accrued any amounts relating to this matter because we do not believe at the present time a loss is probable.

Item 1A. Risk Factors

The information set forth under the caption “Factors That May Affect Financial Condition and Future Results” on pages 31 – 35 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

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

Under a resolution adopted by the Board of Directors on February 21, 2008, the Company is authorized to purchase up to 30,000,000 shares of its Common Stock. Additionally, on May 22, 2006, the Company’s Board of Directors approved repurchasing shares of the Company’s common stock with the proceeds remaining from the Company’s 2.5% Convertible Debenture offering, after taking into account a planned repayment of $200,000,000 principal amount of the Company’s outstanding 2.65% senior notes due 2007. This authorization is in addition to the 30,000,000 shares described above.

Purchases pursuant to the 30,000,000-share Board authorization may be made by way of open market purchases, directly or indirectly, for the Company’s own account or through commercial banks or financial institutions and by the use of derivatives such as a sale or put on the Company’s common stock or by forward or economically equivalent transactions. There were no shares of common stock purchased and placed in treasury during the three- and nine-month periods ended September 30, 2011 under the Board’s two authorization programs described above. At September 30, 2011, the Company had previously purchased 29,658,873 shares under the above authorizations and had authority to purchase an additional 2,995,897 shares of its common stock in the future.

Item 3. Defaults Upon Senior Securities

None

Item 4. Removed and Reserved

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 March 24, 2011 with respect to the procedures by which security holders may recommend nominees to the Company’s Board of Directors.

Item 6. Exhibits

Exhibit 31.1 –

Certification

Exhibit 31.2 –

Certification

Exhibit 32.1 –

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

Exhibit 101.INS –

XBRL Instance Document

Exhibit 101.SCH –

XBRL Taxonomy Extension Schema Document

Exhibit 101. CAL –

XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB –

XBRL Taxonomy Extension Label Linkbase Document

Exhibit 101.PRE –

XBRL Taxonomy Extension Presentation Linkbase Document

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: November 2, 2011	CAMERON INTERNATIONAL CORPORATION
	(Registrant)

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

EXHIBIT 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