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 June 30, 2012
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 July 20, 2012 was 246,277,579.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION			3
Item 1. Financial Statements			3
Consolidated Condensed Statements of Comprehensive Income			3
Consolidated Condensed Balance Sheets			4
Consolidated Condensed Statements of Cash Flows			5
Notes to Consolidated Condensed Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			17
Item 3. Quantitative and Qualitative Disclosures About Market Risk			34
Item 4. Controls and Procedures			35
PART II — OTHER INFORMATION			35
Item 1. Legal Proceedings			35
Item 1A. Risk Factors			35
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			35
Item 3. Defaults Upon Senior Securities			35
Item 4. Mine Safety Disclosures			36
Item 5. Other Information			36
Item 6. Exhibits			36
SIGNATURES			37

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CAMERON INTERNATIONAL CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(unaudited)

REVENUES	$	2,053.7		$	1,741.1		$	3,858.0		$	3,242.3
COSTS AND EXPENSES
Cost of sales (exclusive of depreciation and amortization shown separately below)		1,448.9			1,213.4			2,729.3			2,271.2
Selling and administrative expenses		286.2			250.5			557.6			480.3
Depreciation and amortization		63.6			47.6			123.1			92.4
Interest, net		22.0			22.1			44.7			42.2
Other costs (see Note 3)		9.9			20.1			8.4			29.0
Total costs and expenses		1,830.6			1,553.7			3,463.1			2,915.1
Income before income taxes		223.1			187.4			394.9			327.2
Income tax provision		(48.5	)		(39.4	)		(86.3	)		(69.6	)
Net income	$	174.6		$	148.0		$	308.6		$	257.6
Earnings per common share:
Basic	$	0.71		$	0.60		$	1.25		$	1.05
Diluted	$	0.70		$	0.59		$	1.25		$	1.03
Shares used in computing earnings per common share:
Basic		246.3			245.0			246.2			244.8
Diluted		247.7			249.9			247.8			251.1

Comprehensive income	$	128.7		$	176.8		$	309.6		$	362.6

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)

	June 30, 2012			December 31, 2011
	(unaudited)
ASSETS
Cash and cash equivalents	$	829.0		$	898.9
Short-term investments		419.5			423.5
Receivables, net		1,824.0			1,757.3
Inventories, net		2,650.0			2,399.9
Other		359.3			349.0
Total current assets		6,081.8			5,828.6
Plant and equipment, net		1,614.1			1,500.1
Goodwill		1,966.9			1,615.3
Other assets		427.5			417.7
TOTAL ASSETS	$	10,090.3		$	9,361.7

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of long-term debt	$	21.5		$	10.6
Accounts payable and accrued liabilities		2,621.1			2,669.7
Total current liabilities		2,642.6			2,680.3
Long-term debt		2,016.1			1,574.2
Deferred income taxes		165.5			184.5
Other long-term liabilities		229.4			215.3
Total liabilities		5,053.6			4,654.3
Stockholders’ Equity:
Common stock, par value $.01 per share, 400,000,000 shares authorized, 263,111,472 shares issued at June 30, 2012 and December 31, 2011		2.6			2.6
Capital in excess of par value		2,073.4			2,072.4
Retained earnings		3,678.8			3,370.2
Accumulated other elements of comprehensive income (loss)		(89.8	)		(90.8	)
Less: Treasury stock, 16,839,018 shares at June 30, 2012 (17,579,397 shares at December 31, 2011)		(628.3	)		(647.0	)
Total stockholders’ equity		5,036.7			4,707.4
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	10,090.3		$	9,361.7

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(unaudited)

Cash flows from operating activities:
Net income	$	174.6		$	148.0		$	308.6		$	257.6
Adjustments to reconcile net income to net cash provided by (used for) operating activities:
Depreciation		51.6			37.6			99.4			72.2
Amortization		12.0			10.0			23.7			20.2
Non-cash stock compensation expense		10.7			9.4			21.6			17.5
Deferred income taxes and tax benefit of employee stock compensation plan transactions		12.2			(31.8	)		31.7			(13.0	)
Changes in assets and liabilities, net of translation, acquisitions and non-cash items:
Receivables		(80.7	)		(169.5	)		16.8			(201.2	)
Inventories		(109.6	)		(111.5	)		(312.1	)		(285.0	)
Accounts payable and accrued liabilities		124.4			115.9			(168.3	)		(133.4	)
Other assets and liabilities, net		(31.7	)		93.3			(61.7	)		39.8
Net cash provided by (used for) operating activities		163.5			101.4			(40.3	)		(225.3	)
Cash flows from investing activities:
Proceeds from sales and maturities of short-term investments		190.6			–			512.3			–
Purchases of short-term investments		(265.4	)		–			(508.3	)		–
Capital expenditures		(95.1	)		(72.4	)		(181.8	)		(134.3	)
Acquisitions, net of cash acquired		(248.1	)		(14.9	)		(309.6	)		(42.5	)
Proceeds from sale of plant and equipment		8.5			3.2			18.3			9.9
Net cash used for investing activities		(409.5	)		(84.1	)		(469.1	)		(166.9	)
Cash flows from financing activities:
Short-term loan borrowings (repayments), net		(62.9	)		33.5			(44.5	)		31.5
Issuance of senior debt		499.3			747.8			499.3			747.8
Debt issuance costs		(3.4	)		(4.7	)		(3.4	)		(4.7	)
Redemption of convertible debentures		–			(181.2	)		–			(181.2	)
Premium for purchased call options		–			(21.9	)		–			(21.9	)
Purchase of treasury stock		(4.4	)		–			(7.5	)		–
Proceeds from stock option exercises, net of tax payments from stock compensation plan transactions		(0.3	)		0.9			2.1			16.6
Excess tax benefits from employee stock compensation plan transactions		0.5			0.1			5.2			4.8
Principal payments on capital leases		(2.9	)		(2.0	)		(5.3	)		(3.8	)
Net cash provided by financing activities		425.9			572.5			445.9			589.1
Effect of translation on cash		(13.4	)		3.7			(6.4	)		13.7
Increase (decrease) in cash and cash equivalents		166.5			593.5			(69.9	)		210.6
Cash and cash equivalents, beginning of period		662.5			1,449.6			898.9			1,832.5
Cash and cash equivalents, end of period	$	829.0		$	2,043.1		$	829.0		$	2,043.1

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, 2011.

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 June 6, 2012, the Company closed on its purchase of the drilling equipment business of TTS Energy Division from TTS Group ASA, a Norwegian company (“TTS”), for a cash payment of $248.1 million, net of cash acquired, subject to certain post-closing adjustments. TTS provides high performance drilling equipment, rig packages and rig solutions for both onshore and offshore rigs to the international energy industry and its financial results have been included in the Drilling & Production Systems (DPS) segment since the date of acquisition.

As of June 30, 2012, the Company has made only minimal purchase price allocation adjustments to the opening balance sheet of TTS. The primary areas of the purchase price allocation, which are not yet finalized, relate to inventory, property, plant and equipment, identifiable intangible assets, goodwill, certain preacquisition contingencies and related adjustments to deferred taxes. As of June 30, 2012, preliminary goodwill recorded from this transaction was $235.3 million.

During the first quarter of 2012, the Company acquired 100% of the outstanding stock of Elco Filtration and Testing, Inc. (“Elco”), for a total purchase price of $61.5 million, net of cash acquired. Elco was purchased to strengthen the Company’s wellhead product and service offerings and has been included in the DPS segment since the date of acquisition.

Preliminary goodwill recorded from the Elco acquisition during the six months ended June 30, 2012 was approximately $28.0 million. The Company is still awaiting significant information relating to the fair value of the assets and liabilities of Elco in order to finalize the purchase price allocation.

As discussed in more detail in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, the Company closed on the acquisition of LeTourneau Technologies, Inc., a wholly-owned subsidiary of Joy Global, Inc. on October 24, 2011. The Company made a preliminary allocation of the purchase price at the time of acquisition based on preliminary valuations of the assets and liabilities acquired. While certain adjustments to the preliminary allocation were made during the first six months of 2012, the Company is still awaiting certain information to finalize its preliminary estimates and assumptions related to the fair value of inventory, property, plant and equipment, identifiable intangible assets, goodwill, certain pre-acquisition contingencies and related adjustments to deferred taxes.

Note 3: Other Costs

Other costs consisted of the following (in millions):

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011

International pension settlement costs	$	6.1		$	–	$	6.1		$	–
Acquisition integration costs		3.3			–		5.2			–
BOP litigation costs		0.8			14.0		1.0			22.3
Mark-to-market impact on currency derivatives(1)		(1.5	)		–		(5.6	)		–
Severance, restructuring and other costs		1.2			6.1		1.7			6.7
	$	9.9		$	20.1	$	8.4		$	29.0

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

Note 4: Receivables

Receivables consisted of the following (in millions):

	June 30, 2012			December 31, 2011

Trade receivables	$	1,685.4		$	1,523.5
Insurance company receivable related to the indemnity settlement with BP Exploration and Production Inc.		–			167.5
Other receivables		146.2			76.2
Allowance for doubtful accounts		(7.6	)		(9.9	)
Total receivables	$	1,824.0		$	1,757.3

Note 5: Inventories

Inventories consisted of the following (in millions):

	June 30, 2012			December 31, 2011

Raw materials	$	399.7		$	427.3
Work-in-process		891.0			767.8
Finished goods, including parts and subassemblies		1,528.5			1,376.9
Other		12.3			12.5
		2,831.5			2,584.5
Excess of current standard costs over LIFO costs		(107.0	)		(102.7	)
Allowances		(74.5	)		(81.9	)
Total inventories	$	2,650.0		$	2,399.9

Note 6: Plant and Equipment and Goodwill

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

	June 30, 2012			December 31, 2011

Plant and equipment, at cost	$	2,885.2		$	2,688.0
Accumulated depreciation		(1,271.1	)		(1,187.9	)
Total plant and equipment	$	1,614.1		$	1,500.1

Changes in goodwill during the six months ended June 30, 2012 were as follows (in millions):

Balance at December 31, 2011	$	1,615.3
Current year acquisitions		263.3
Adjustments to the purchase price allocation for prior year acquisitions		89.8
Translation		(1.5	)
Balance at June 30, 2012	$	1,966.9

Note 7: Accounts Payable and Accrued Liabilities

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

	June 30, 2012		December 31, 2011

Indemnity settlement with BP Exploration and Production Inc.	$	–	$	250.0
Trade accounts payable and accruals		738.4		718.8
Advances from customers		1,241.0		1,012.5
Other accruals		641.7		688.4
Total accounts payable and accrued liabilities		2,621.1	$	2,669.7

Activity during the six months ended June 30, 2012 associated with the Company’s product warranty accruals was as follows (in millions):

Balance December 31, 2011		Net warranty provisions		Acquisitions		Charges against accrual			Translation and other			Balance June 30, 2012

$	65.0	$	22.3	$	3.9	$	(24.1	)	$	(0.1	)	$	67.0

Note 8: Debt

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

	June 30, 2012			December 31, 2011

Senior notes:
Floating rate notes due June 2, 2014	$	250.0		$	250.0
1.6% notes due April 30, 2015		250.0			–
6.375% notes due July 15, 2018		450.0			450.0
4.5% notes due June 1, 2021		250.0			250.0
3.6% notes due April 30, 2022		250.0			–
7.0% notes due July 15, 2038		300.0			300.0
5.95% notes due June 1, 2041		250.0			250.0
Unamortized original issue discount		(4.3	)		(3.8	)
Other debt		17.1			70.0
Obligations under capital leases		24.8			18.6
		2,037.6			1,584.8
Current maturities		(21.5	)		(10.6	)
Long-term maturities	$	2,016.1		$	1,574.2

Senior Notes

On May 17, 2012, the Company completed the public offering of $500.0 million in aggregate principal amount of senior unsecured notes as follows:

•	$250.0 million principal amount of 1.6% Senior Notes due April 30, 2015; and

•	$250.0 million principal amount of 3.6% Senior Notes due April 30, 2022.

Interest on the 1.6% and 3.6% Senior Notes is payable on April 30 and October 30 of each year, beginning October 30, 2012. The 1.6% and 3.6% Senior Notes were sold at 99.957% and 99.744% of principal amount, respectively, and can both be redeemed in whole or in part by the Company prior to maturity for an amount equal to the principal amount of the notes redeemed plus, under certain circumstances, a make-whole premium as described further in the Supplemental Indenture for each respective Senior Note. Both issuances of Senior Notes rank equally with the Company’s other existing unsecured and unsubordinated debt.

Proceeds from the issuance of the Senior Notes were used to (i) fund the acquisition of TTS, as described further in Note 2 of the Notes to Consolidated Condensed Financial Statements, (ii) repay certain indebtedness of our Brazilian subsidiary to unaffiliated third parties and, (iii) meet certain other general corporate needs.

Multicurrency Revolving Letter of Credit and Credit Facilities

At June 30, 2012, the Company had issued:

•	$25.4 million of letters of credit under its $835.0 million Amended Credit Agreement leaving $809.6 million remaining available for future use under the Amended Credit Agreement, and

•	$119.8 million of letters of credit under its $250.0 million multi-currency revolving letter of credit facility leaving $130.2 million remaining available for use under this facility.

Note 9: Income Taxes

The Company’s effective tax rate for the first six months of 2012 was 21.9% compared to 21.3% for the same period in 2011. The increase in the effective tax rate was due primarily to certain tax benefits recognized in the first half of 2011 from tax planning strategies put in place in prior periods and resolution of uncertainties regarding certain other tax benefits. This effect was partially offset by a mix shift between domestic and international earnings and the effect of resolution of certain tax contingencies in both periods.

Note 10: Business Segments

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues:
DPS	$	1,155.8		$	1,002.7		$	2,197.9		$	1,868.3
V&M		558.3			426.5			1,049.5			766.4
PCS		339.6			311.9			610.6			607.6
	$	2,053.7		$	1,741.1		$	3,858.0		$	3,242.3

Income (loss) before income taxes:
DPS	$	176.1		$	161.4		$	311.4		$	277.6
V&M		111.1			75.5			203.7			130.7
PCS		26.9			34.0			37.5			64.5
Corporate & other		(91.0	)		(83.5	)		(157.7	)		(145.6	)
	$	223.1		$	187.4		$	394.9		$	327.2

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 pension settlement costs, 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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011

Net income	$	174.6	$	148.0	$	308.6	$	257.6

Average shares outstanding (basic)		246.3		245.0		246.2		244.8
Common stock equivalents		1.4		1.9		1.6		2.2
Incremental shares from assumed conversion of convertible debentures		–		3.0		–		4.1
Diluted shares		247.7		249.9		247.8		251.1

Basic earnings per share	$	0.71	$	0.60	$	1.25	$	1.05
Diluted earnings per share	$	0.70	$	0.59	$	1.25	$	1.03

The Company’s 2.5% Convertible Debentures were included in the calculation of diluted earnings per share for the three and six months ended June 30, 2011, since the average market price of the Company’s common stock exceeded the conversion value of the debentures during those periods. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 for further information.

During the three and six months ended June 30, 2012, the Company acquired 100,000 and 157,200 treasury shares at an average cost of $43.66 and $47.93 per share, respectively. No treasury shares were acquired during the three and six months ended June 30, 2011. A total of 87,330 and 897,579 treasury shares were issued during the three and six months ended June 30, 2012, respectively, in satisfaction of stock option exercises and vesting of restricted stock units.

Note 12: Comprehensive Income

The amounts of comprehensive income were as follows (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income per Consolidated Condensed Statements of Comprehensive Income	$	174.6		$	148.0		$	308.6		$	257.6
Foreign currency translation gain (loss)		(44.4	)		26.0			(4.5	)		96.3
Amortization of net prior service credits related to the Company’s pension and postretirement benefit plans, net of tax		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Amortization of net actuarial losses related to the Company’s pension and postretirement benefit plans, net of tax		4.0			1.4			4.8			2.8
Change in fair value of derivatives accounted for as cash flow hedges, net of tax		(5.3	)		1.6			1.1			6.2
Comprehensive income	$	128.7		$	176.8		$	309.6		$	362.6

The components of accumulated other elements of comprehensive income (loss) at June 30, 2012 and December 31, 2011 were as follows (in millions):

	June 30, 2012			December 31, 2011

Accumulated foreign currency translation loss	$	(33.2	)	$	(28.7	)
Prior service credits, net, related to the Company’s pension and postretirement benefit plans, net of tax		3.7			4.1
Actuarial losses, net, related to the Company’s pension and postretirement benefit plans, net of tax		(55.5	)		(60.3	)
Change in fair value of derivatives accounted for as cash flow hedges, net of tax		(4.8	)		(5.9	)
Accumulated other elements of comprehensive income (loss)	$	(89.8	)	$	(90.8	)

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 in 2010 when the rig experienced an explosion and fire resulting in bodily injuries and loss of life, the loss of the rig, and discharge of hydrocarbons into the Gulf of Mexico.

The Company was named as one of a number of defendants in over 350 suits asserting claims for personal injury, wrongful death, property damage, pollution and economic damages. Most of these suits were consolidated into a single proceeding before a single Federal judge under rules governing multi-district litigation. The consolidated case is styled: In Re: Oil Spill by the Oil Rig “Deep Water Horizon” in the Gulf of Mexico on April 20, 2010, MDL Docket No. 2179.

On December 15, 2011, the Company entered into an agreement with BP Exploration and Production Inc. (BPXP), guaranteed by BP Corporation North America Inc., pursuant to which BPXP agreed to indemnify the Company for any and all current and future compensatory claims, and to pay on behalf of the Company any and all such claims, associated with or arising out of the Deepwater Horizon incident the Company otherwise would have been obligated to pay, including claims arising under the Oil Pollution Act, claims for natural resource damages and associated damage-assessment costs, clean-up costs, and other claims arising from third parties. The agreement does not provide indemnification of the Company against any fines, penalties, punitive damages or certain other potential non-compensatory claims levied on or awarded against it individually. The Company does not consider any of these, singly or cumulatively, to pose a material financial risk to it because, while the United States 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, the Company was not named as a defendant in this suit. Additionally, BP and the Plaintiffs’ Steering Committee (“PSC”), appointed by the Court in the MDL proceeding to represent the interests of third-party claimants, concluded an “Economic and Property Damages Settlement Agreement” and a “Medical Benefits Class Action Settlement Agreement” which were filed with the Court on April 18, 2012. Under the terms of these settlements, the PSC, on behalf of these claimants who would be included in the proposed settling classes, has released any claim against BP and certain other parties, including the Company, for punitive and other non-compensatory damages. This settlement has yet to be approved by the Court. The proposed settlement, and the release of punitive and other non-compensatory damages against Cameron, will not affect the claims of (i) persons who opt out of the settlement; (ii) persons outside of Alabama, Louisiana, Mississippi and certain counties in Florida and Texas, the geographic scope of the settlement; (iii) persons outside the class of lost business covered by the settlement class such as gambling, real estate development and insurance; and (iv) the Gulf states and local government entities.

A shareholder derivative suit, Berzner vs. Erikson, et al., Cause No. 2010-71817, 190th District Court of Harris County, Texas, was filed in October 2010 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, but remains in the pleading stage.

Other Litigation

The Company has been and continues to be named as a defendant in a number of multi-defendant, multi-plaintiff tort lawsuits. At June 30, 2012, the Company’s consolidated balance sheet included a liability of approximately $9.5 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 50 countries. As a result, the Company is subject to various tax filing requirements in these countries. The Company prepares its tax filings in a manner which it believes is consistent with such filing requirements. However, some of the tax laws and regulations to which the Company is subject 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 and which may have yet undiscovered contamination. The Company does not believe, based upon information currently available, that there are any material environmental liabilities existing at these locations. At June 30, 2012, the Company’s consolidated balance sheet included a noncurrent liability of approximately $5.2 million for environmental matters.

In 2001, the Company discovered that contaminated underground water from the former manufacturing site in Houston referenced above 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 the property’s 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 June 30, 2012.

Note 14: Fair Value of Financial Instruments

Fair Value of Financial Instruments

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

Following is a summary of the Company’s financial instruments which have been valued at fair value in the Company’s Consolidated Balance Sheets at June 30, 2012 and December 31, 2011:

	Fair Value Based on Quoted Prices in Active Markets for Identical Assets (Level 1)				Fair Value Based on Significant Other Observable Inputs (Level 2)						Fair Value Based on Significant Unobservable Inputs (Level 3)				Total
($ in millions)	2012		2011		2012			2011			2012		2011		2012			2011

Cash and cash equivalents:
Cash	$	429.0	$	491.7	$	–		$	–		$	–	$	–	$	429.0		$	491.7
Money market funds		195.3		133.4		–			–			–		–		195.3			133.4
Commercial paper		–		–		131.9			140.4			–		–		131.9			140.4
U.S.non-governmental agency asset-backed securities		–		–		37.0			27.8			–		–		37.0			27.8
U.S. corporate obligations		7.4		29.1		–			–			–		–		7.4			29.1
Non-U.S. bank and other obligations		28.4		76.5		–			–			–		–		28.4			76.5
Short-term investments:
Commercial paper		–		–		250.3			213.5			–		–		250.3			213.5
U.S. Treasury securities		5.0		10.1		–			–			–		–		5.0			10.1
U.S. non-governmental agency asset-backed securities		–		–		59.2			77.3			–		–		59.2			77.3
U.S. corporate obligations		105.0		122.6		–			–			–		–		105.0			122.6
Derivatives, net asset (liability):
Foreign currency contracts		–		–		(20.9	)		(13.8	)		–		–		(20.9	)		(13.8	)
Interest rate contracts		–		–		–			1.4			–		–		–			1.4
	$	770.1	$	863.4	$	457.5		$	446.6		$	–	$	–	$	1,227.6		$	1,310.0

Fair values for financial instruments utilizing level 2 inputs were determined from information obtained from third party pricing sources, broker quotes, calculations involving the use of market indices or mutual fund unit values determined based upon the valuation of the funds’ underlying assets.

At June 30, 2012, the fair value of the Company’s fixed-rate debt (based on Level 1 quoted market rates) was approximately $1.98 billion as compared to the $1.75 billion face value of the debt recorded, net of original issue discounts, in the Company’s Consolidated Balance Sheet. At December 31, 2011, the fair value of the Company’s fixed-rate debt (based on Level 1 quoted market rates) was approximately $1.47 billion as compared to the $1.25 billion face value of the debt.

Derivative Contracts

In order to mitigate the effect of exchange rate changes, the Company will often attempt to structure sales contracts to provide for collections from customers in the currency in which the Company incurs its manufacturing costs. In certain instances, the Company will enter into foreign currency forward contracts to hedge specific large anticipated receipts or disbursements in currencies for which the Company does not traditionally have fully offsetting local currency expenditures or receipts. The Company was party to a number of long-term foreign currency forward contracts at June 30, 2012. 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 Australia, France, Italy, Malaysia, Norway, 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 (loss) in the period such change occurs. Certain other contracts, many of which are centrally managed, are intended to offset other foreign currency exposures but have not been designated as hedges for accounting purposes and, therefore, any change in the fair value of those contracts are reflected in earnings in the period such change occurs. The Company determines the fair value of its outstanding foreign currency forward contracts based on quoted exchange rates for the respective currencies applicable to similar instruments.

Total gross volume bought (sold) by notional currency and maturity date on open derivative contracts at June 30, 2012 was as follows (in millions):

	Notional Amount - Buy								Notional Amount - Sell
	2012		2013		2014		Total		2012			2013			2014			Total
FX Forward Contracts
Notional currency in:
EUR		144.7		60.4		17.8		222.9		(38.2	)		(7.8	)		–			(46.0	)
GBP		35.2		1.1		–		36.3		(8.5	)		(7.2	)		(0.3	)		(16.0	)
NOK		90.0		–		–		90.0		(37.4	)		–			–			(37.4	)
SGD		2.6		10.1		–		12.7		–			–			–			–
USD		157.4		91.7		0.4		249.5		(323.1	)		(181.8	)		(30.1	)		(535.0	)
CAD		10.5		0.9		–		11.4		(2.2	)		–			–			(2.2	)

The fair values of derivative financial instruments recorded in the Company’s Consolidated Condensed Balance Sheets at June 30, 2012 and December 31, 2011 were as follows (in millions):


	June 30, 2012				December 31, 2011
	Assets		Liabilities		Assets		Liabilities

Derivatives designated as hedges:
Foreign exchange contracts –
Current	$	1.6	$	8.2	$	1.9	$	7.0
Non-current		0.2		1.2		–		0.6
Total derivatives designated as hedges		1.8		9.4		1.9		7.6

Derivatives not designated as hedges:
Foreign exchange contracts –
Current		6.9		17.8		2.5		10.6
Non-current		1.2		3.6		–		–

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

Total derivatives not designated as hedges		8.1		21.4		3.9		10.6

Total derivatives	$	9.9	$	30.8	$	5.8	$	18.2

The effects of derivative financial instruments designated as cash flow hedges on the Company’s consolidated condensed financial statements for the three months ended June 30, 2012 and 2011 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 June 30,					Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income at June 30,					Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives at June 30,
Derivatives in Cash Flow Hedging Relationships	2012			2011			2012			2011			2012			2011

Foreign exchange contracts	$	(7.4	)	$	0.4	Revenues	$	(0.6	)	$	0.2	Cost of goods sold- ineffective portion	$	(0.8	)	$	(0.1	)
						Cost of goods sold		(1.1	)		(0.8)

						Depreciation expense		–			–
Total	$	(7.4	)	$	0.4		$	(1.7	)	$	(0.6)		$	(0.8	)	$	(0.1	)

The effects of derivative financial instruments designated as cash flow hedges on the Company’s consolidated condensed financial statements for the six months ended June 30, 2012 and 2011 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 June 30,					Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income at June 30,					Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives at June 30,
Derivatives in Cash Flow Hedging Relationships	2012			2011			2012			2011			2012			2011

Foreign exchange contracts	$	(4.4	)	$	2.9	Revenues	$	(2.0	)	$	1.8	Cost of goods sold- ineffective portion	$	(0.5	)	$	(0.3	)
						Cost of goods sold		(4.8	)		(6.5)

						Depreciation expense		(0.1	)		(0.1)
Total	$	(4.4	)	$	2.9		$	(6.9	)	$	(4.8)		$	(0.5	)	$	(0.3	)

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012		2011

Foreign currency contracts:
Cost of sales	$	(0.5	)	$	(1.3	)	$	0.5	$	(0.8	)
Other costs		1.5			–			5.6		–

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

Equity call options:
Other costs		–			1.6			–		1.6

Total	$	1.0		$	0.3		$	6.1	$	0.6

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; 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.

SECOND QUARTER 2012 COMPARED TO SECOND QUARTER 2011

Market Conditions

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

	Three Months Ended June 30,				Increase (Decrease)
	2012		2011		Amount			%
Drilling activity (average number of working rigs during period)(1):
United States		1,970		1,829		141			7.7	%
Canada		173		188		(15	)		(8.0	)%
Rest of world		1,229		1,146		83			7.2	%
Global average rig count		3,372		3,163		209			6.6	%
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	$	93.30	$	102.28	$	(8.98	)		(8.8	)%
Henry Hub natural gas spot price per MMBtu in U.S. dollars	$	2.30	$	4.36	$	(2.06	)		(47.2	)%
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
West Texas Intermediate Cushing, OK crude oil contract (per barrel)	$	87.14	$	98.03	$	(10.89	)		(11.1	)%
Henry Hub Natural Gas contract (per MMBtu)	$	3.29	$	4.65	$	(1.36	)		(29.2	)%
Number of deepwater floaters and semis under contract in competitive major markets at period-end(3):
U.S. Gulf of Mexico		34		28		6			21.4	%
Northwestern Europe		41		37		4			10.8	%
West Africa		31		30		1			3.3	%
Southeast Asia and Australia		26		23		3			13.0	%

(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 increased slightly in the second quarter of 2012 as compared to the second quarter of 2011. Almost two-thirds of the increase was a result of higher United States activity levels largely reflecting the impact of unconventional resource opportunities in the region.

Crude oil prices (West Texas Intermediate, Cushing, OK) decreased for much of the latter half of the second quarter of 2012 after reaching a high of $106 per barrel in late April before closing the period at approximately $85 per barrel. On average, crude oil prices were 8.8% lower during the second quarter of 2012 as compared to the second quarter of 2011. The twelve-month futures price for crude oil at June 30, 2012 was relatively flat compared to spot prices near the end of the quarter.

Natural gas (Henry Hub) prices trended slightly upward during the second quarter of 2012 from their lowest levels in the last decade, closing at $2.74 per MMBtu. On average, prices during the second quarter of 2012 were down 47.2% as compared to the same period in 2011, due largely to increased supplies available in North America as a result of new unconventional resource developments and higher activity levels. The twelve-month futures strip price for natural gas at June 30, 2012 remains depressed at $3.29 per MMBtu. In response to the current low natural gas prices, many oil and gas exploration and production companies have indicated they have curtailed development activities for “dry gas” wells. This activity has shifted to areas that produce gas with a mixture of liquid hydrocarbons (“wet gas” wells); thus, there has not been a significant drop off of overall U.S. activity levels to date. Should the twelve-month futures strip price stay at current levels for a long period of time, the portion of the North American rig count directed to gas drilling could decline further, which could further impact the Company’s future orders flow. Additionally, should the price of various liquid hydrocarbons drop dramatically, rather than shifting activities from dry gas wells to wet gas wells, customers may elect to curtail overall activity levels which could also further negatively impact the Company’s future orders flow in the U.S.

Critical Accounting Policies

Goodwill – The Company reviews the carrying value of goodwill in accordance with accounting rules on impairment of goodwill, which require that the Company estimate the fair value of each of its reporting units annually, or when impairment indicators exist, and compare such amounts to their respective carrying values to determine if an impairment of goodwill is required. The estimated fair value of each reporting unit is determined using discounted future expected cash flow models (level 3 unobservable inputs) consistent with the accounting guidance for fair value measurements. Certain estimates and judgments are required in the application of the discounted cash flow models, including, but not limited to, estimates of future cash flows and the selection of a discount rate. Generally, this review is conducted during the first quarter of each annual period. The results of the 2012 test indicated that there was no impairment of goodwill. Should the Company’s estimate of the fair value of any of its reporting units decline significantly in future periods due to changes in customer demand, market activity levels, interest rates or other factors which would impact future earnings and cash flow or market valuation levels of the Company or any of its reporting units, an impairment of goodwill could be required.

Goodwill at June 30, 2012 was nearly $2.0 billion, a large portion of which was allocated to the Company’s Process & Compression Systems (PCS) segment, which includes the majority of the NATCO operations acquired in 2009. The Company’s determination of the fair value of its Custom Process Systems (CPS) business within the PCS segment included assumptions for continued long-term improvements to recent results. As a result of competitive pressures during the economic downturn that began prior to the acquisition of the NATCO operations in 2009, the backlog of the CPS business has carried unusually low margins which have negatively impacted recent profitability. Additionally, the Company experienced operating inefficiencies during 2011 which continued into 2012. While management is taking steps to improve the financial results of CPS, should it continue to underperform expectations assumed in the Company’s discounted cash flow calculations, an impairment of goodwill for this reporting unit could be required. Goodwill associated with the CPS business was approximately $572.4 million at June 30, 2012.

Consolidated Results

Net income for the second quarter of 2012 totaled $174.6 million, or $0.70 per diluted share, compared to net income for the second quarter of 2011 of $148.0 million, or $0.59 per diluted share.

Total revenues for the Company increased $312.6 million, or 18.0%, during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011 on the strength of higher sales in the Company’s Drilling & Production Systems (DPS) and Valves & Measurement (V&M) business segments.

•

DPS segment revenues increased 15.3% in the second quarter of 2012 as compared to the second quarter of 2011 largely as a result of the impact of newly acquired businesses, as well as increased aftermarket activity levels which resulted in higher revenues in the surface and drilling equipment product lines.

•

Revenues in the V&M segment were up 30.9% in the second quarter of 2012 as compared to the same period last year as increased worldwide activity levels resulted in double-digit increases in each of the segment’s major new equipment product lines.

As a percent of revenues, cost of sales (exclusive of depreciation and amortization) increased from 69.7% during the second quarter of 2011 to 70.6% for the second quarter of 2012. Lower margins in the PCS segment, particularly in the Custom Process Systems and Reciprocating Compression product lines, accounted for the majority of the increase in the ratio.

Selling and administrative expenses increased $35.7 million, or nearly 14.3%, during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011.

•

Selling and administrative expenses were 13.9% of revenues for the second quarter of 2012 as compared to 14.4% for the second quarter of 2011.

•

Nearly 92% of the dollar increase was due to higher employee and facility-related costs mainly as a result of increased business volumes, the impact of newly acquired businesses and international and aftermarket expansion efforts.

Depreciation and amortization expense totaled $63.6 million for the second quarter of 2012 as compared to $47.6 million during the second quarter of 2011, an increase of $16.0 million, due mainly to higher depreciation expense as a result of recent increased levels of capital spending for new equipment, facilities and the Company’s enhanced business information systems, as well as the impact of recently acquired businesses.

Other costs consisted of:

	Three Months Ended June 30,
($ in millions)	2012			2011

International pension settlement costs	$	6.1		$	-
Acquisition integration costs		3.3			-
BOP litigation costs		0.8			14.0
Mark-to-market impact on currency derivatives not designated as accounting hedges		(1.5	)		-
Severance, restructuring and other costs		1.2			6.1
	$	9.9		$	20.1

The Company’s effective tax rate for the second quarter of 2012 was 21.7% compared to 21.0% for the second quarter of 2011. The increase in the effective tax rate was due primarily to certain tax benefits recognized in the second quarter of 2011 from tax planning strategies put in place in prior periods and resolution of uncertainties regarding certain other tax benefits. This effect was partially offset by a mix shift between domestic and international earnings and the effect of resolution of certain tax contingencies in both periods.

Segment Results

DPS Segment –

	Three Months Ended June 30,						Increase (Decrease)
($ in millions)	2012			2011			$		%

Revenues	$	1,155.8		$	1,002.7		$	153.1	15.3	%
Income before income taxes	$	176.1		$	161.4		$	14.7	9.1	%
Income before income taxes as a percent of revenues		15.2	%		16.1	%		N/A	(0.9	)%

Orders	$	1,617.2		$	1,442.7		$	174.5	12.1	%
Backlog (at period-end)	$	5,155.3		$	3,628.3		$	1,527.0	42.1	%

Revenues

The increase in revenues was mainly due to the impact of newly acquired businesses which accounted for almost 90% of the total change from the second quarter of 2011. Absent this effect,

•

sales of surface equipment increased 10% largely as a result of higher revenues from rental equipment deployed in unconventional resource regions of North America, and

•

drilling equipment sales were up 10% largely related to increased demand for spares and rig upgrades.

These increases were partially offset by lower subsea project activity levels, primarily offshore West Africa.

Income before income taxes as a percent of revenues

The ratio of income before income taxes as a percent of revenues declined by 0.9 percentage points from the second quarter of 2011 to the second quarter of 2012, primarily as a result of:

•

an increase of 0.7 percentage points in the ratio of depreciation and amortization as a percent of revenues, related mainly to higher capital spending in recent periods on rental equipment and aftermarket facilities and higher amortization of acquired intangibles, and

•

a 0.5 percentage-point increase in the ratio of selling and administrative costs to revenues. Selling and administrative costs increased in total 21% from the same period last year. Approximately 39% of the total dollar increase in selling and administrative costs in the second quarter of 2012 as compared to the second quarter of 2011 was from the impact of newly acquired businesses with the remainder mainly attributable to higher costs related to increased activity levels and worldwide aftermarket expansions.

This was partially offset by a decrease in the ratio of cost of sales to revenues during the second quarter of 2012 as compared to the second quarter of 2011. Margins improved approximately 3.3 percentage points due to a shift to higher volumes of higher-margin drilling and surface equipment sales. Most of this improvement was offset by a decline in subsea project margins resulting in a net improvement of 0.3 percentage points in total segment margins.

Orders

Excluding the impact of newly acquired businesses, total segment orders increased 5% in the second quarter of 2012 as compared to the same period last year. This increase was primarily attributable to:

•

a 69% increase in orders for subsea equipment reflecting a doubling of the number of subsea trees awarded in the second quarter of 2012 as compared to the same period in 2011, and

•

a 29% increase in orders for surface equipment, mainly due to increased demand for rental equipment in unconventional resource regions of North America and higher international activity levels, primarily in Latin America and the Asia-Pacific region.

These increases were largely offset by a 32% decline in drilling equipment orders as a result of the lower level of major project awards in the second quarter of 2012 as compared to the second quarter of 2011.

Backlog (at period-end)

Over 80% of the increased level of backlog at June 30, 2012 as compared to June 30, 2011 was due to higher backlog in the drilling equipment product line due mainly to strong demand in previous periods for new equipment and aftermarket parts and services.

V&M Segment –

	Three Months Ended June 30,						Increase
($ in millions)	2012			2011			$		%

Revenues	$	558.3		$	426.5		$	131.8	30.9	%
Income before income taxes	$	111.1		$	75.5		$	35.6	47.2	%
Income before income taxes as a percent of revenues		19.9	%		17.7	%		N/A	2.2	%

Orders	$	549.8		$	526.5		$	23.3	4.4	%
Backlog (at period-end)	$	1,144.0		$	1,016.2		$	127.8	12.6	%

Revenues

Engineered valve sales increased 35% as compared to the same period in 2011 as a result of higher worldwide pipeline construction project activity levels. Better market conditions in North America and increased shipments from higher beginning-of-period backlog resulted in a 36% increase in sales of distributed valves as compared to the same period in 2011. Combined, these two product lines accounted for over three-fourths of the increase in total V&M segment sales.

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 2.8 percentage-point decrease in the ratio of selling and administrative expenses to revenues as a result of revenues increasing at a greater rate than selling and administrative expenses during the second quarter of 2012 as compared to the second quarter of 2011, and

•

a 0.5 percentage-point decrease in the ratio of depreciation and amortization to revenues mainly resulting from the impact of increasing revenues in relation to relatively flat depreciation and amortization during the second quarter of 2012 as compared to the second quarter of 2011.

These decreases were offset by an increase of 1.1 percentage points in the ratio of cost of sales to revenue resulting from a mix change in the second quarter of 2012 compared to the second quarter of 2011.

Orders

Orders increased in all product lines except distributed valves, with measurement equipment orders accounting for nearly 60% of the total segment increase in the second quarter of 2012 as compared to the second quarter of 2011. The primary drivers for the changes were:

•

increased project activity, primarily in North America, which contributed to a 15% increase in orders for process valves, a 24% increase in demand for measurement equipment and a 4% increase in orders for aftermarket parts and services. This was partially offset by

•

a 10% decrease in orders for distributed valves as a result of weaker orders from Canadian customers.

Backlog (at period-end)

Backlog levels for the V&M segment increased almost 13% from June 30, 2011 due to improved demand across all major product lines with nearly three-fourths of the increase attributable to stronger demand for engineered and process valves.

PCS Segment –

	Three Months Ended June 30,						Increase (Decrease)
($ in millions)	2012			2011			$			%

Revenues	$	339.6		$	311.9		$	27.7		8.9	%
Income before income taxes	$	26.9		$	34.0		$	(7.1	)	(20.9	)%
Income before income taxes as a percent of revenues		7.9	%		10.9	%		N/A		(3.0	)%

Orders	$	407.0		$	418.1		$	(11.1	)	(2.7	)%
Backlog (at period-end)	$	1,154.3		$	875.1		$	279.2		31.9	%

Revenues

A 34% increase in sales of centrifugal compression equipment, mainly resulting from higher international shipments of new engineered equipment and plant air units, and a 9% increase in process systems sales, largely due to higher demand for process applications in unconventional resource markets, more than offset a 51% decline in shipments of Superior compressors, primarily resulting from a large international shipment of high speed packaged units that occurred in the second quarter of 2011, which did not repeat in the same period in 2012.

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 4.2 percentage-point increase in the ratio of cost of sales to revenues during the second quarter of 2012, due mainly to lower margins in the custom process systems business as a result of project and manufacturing delays and inefficiencies as well as the impact on margins of lower volumes in the reciprocating compression product line. This increase in the cost of sales ratio was partially offset by a 1.2 percentage-point improvement in the ratio of selling and administrative costs to revenues as these costs remained relatively flat while revenues increased 8.9% from the second quarter of 2011 to the second quarter of 2012.

Orders

Nearly 80% of the decrease in total segment orders for the second quarter of 2012 as compared to the second quarter of 2011 was due to a 4% decline in demand for new process systems applications, primarily resulting from a large international order for a custom process application received in the second quarter of 2011 that did not repeat in the second quarter of 2012.

Backlog (at period-end)

The increase in backlog at June 30, 2012 as compared to June 30, 2011 was split fairly evenly between the compression equipment business and the process systems business. Over 68% of the increase in compression equipment backlog was due to recent high demand in the centrifugal engineered product line. Backlog in the process systems business was up nearly 30% largely as a result of a large order for new custom equipment received in a previous period.

Corporate Segment –

The $7.5 million increase in the loss before income taxes in the Corporate segment during the second quarter of 2012 as compared to the second quarter of 2011 (see Note 10 of the Notes to Consolidated Condensed Financial Statements) was due primarily to:

•	a $9.9 million increase in selling and administrative expenses, due primarily to higher incentive compensation and other employee-related costs, including at certain international locations which report directly to the Corporate office,

•	a $4.1 million increase in depreciation and amortization expense largely related to increased spending in recent periods for development of the Company’s enhanced business information systems, and

•	$4.1 million of foreign currency exchange losses incurred in the second quarter of 2012 on certain intercompany loans.

These increases were partially offset by a $10.2 million reduction in other costs as described above under “Consolidated Results”.

SIX MONTHS ENDED JUNE 30, 2012 COMPARED TO SIX MONTHS ENDED JUNE 30, 2011

Market Conditions

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

	Six Months Ended June 30,				Increase (Decrease)
	2012		2011		Amount			%
Drilling activity (average number of working rigs during period)(1):
United States		1,981		1,773		208			11.7	%
Canada		382		387		(5	)		(1.3	)%
Rest of world		1,209		1,156		53			4.6	%
Global average rig count		3,572		3,316		256			7.7	%
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	$	98.11	$	98.40	$	(0.29	)		(0.3	)%
Henry Hub natural gas spot price per MMBtu in U.S. dollars	$	2.36	$	4.27	$	(1.91	)		(44.7	)%
Twelve-month futures strip price (U.S. dollar amount at period end)(2):
West Texas Intermediate Cushing, OK crude oil contract (per barrel)	$	87.14	$	98.03	$	(10.89	)		(11.1	)%
Henry Hub Natural Gas contract (per MMBtu)	$	3.29	$	4.65	$	(1.36	)		(29.2	)%

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

(2) Source: Bloomberg

The average number of worldwide operating rigs increased during the first quarter of 2012 but declined during the second quarter of 2012 to end the period at a level slightly higher than the beginning of the year rig count level. Both quarterly movements were largely driven by seasonal trends in Canada. The first six months of 2011 reflected a similar trend. Increased U.S. activity levels accounted for over 80% of the average global rig count increase during the first six months of 2012 as compared to the first six months of 2011.

Crude oil prices (West Texas Intermediate, Cushing, OK) during the first six months of 2012 remained above $100 per barrel for most of the period before declining to the mid-$80 range by the end of the period. Average prices for the first half of 2012 were relatively consistent when compared to the first half of 2011.

Natural gas (Henry Hub) prices were fairly constant during the first six months of 2012 but showed a slight recovery towards the end of the period. The average price per MMBtu in the first half 2012 was $2.36, a 45% decrease from the average price per MMBtu in the first half of 2011, due largely to increased supplies available in North America as a result of new unconventional resource developments and higher activity levels.

Consolidated Results

Net income for the six months ended June 30, 2012 totaled $308.6 million, or $1.25 per diluted share, compared to net income for the six months ended June 30, 2011 of $257.6 million, or $1.03 per diluted share. Included in the results for the first six months of 2011 were charges of $0.17 per diluted share primarily associated with cost overruns on a large subsea project in Nigeria and charges to reserve for receivables on work previously performed in Libya that were believed unlikely to be collected due to sanctions imposed by the United States government and other governments during the first half of 2011.

Total revenues for the Company increased by $615.7 million, or 19.0%, during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. Almost 40% of the revenue increase resulted from businesses acquired over the last 12 months with the remaining increase reflecting higher sales levels in the existing operations of the Company’s DPS and V&M 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 70.0% during the first half of 2011 to 70.7% for the comparable period in 2012. The increase was due largely to lower margins in the PCS segment, partially offset by a mix change to a larger share of higher-margin V&M segment revenues.

Selling and administrative expenses increased $77.3 million, or 16.1%, during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. As a percent of revenues, selling and administrative expenses decreased from 14.8% during the first half of 2011 to 14.5% for the first half of 2012. Over 90% of the dollar increase was due to (i) higher employee-related costs due to headcount increases, higher incentive compensation and travel, as well as (ii) higher facility costs, resulting largely from aftermarket and international expansion activities and the impact of newly acquired businesses.

Depreciation and amortization expense increased $30.7 million, from $92.4 million for the first half of 2011 to $123.1 million for the first half of 2012. The increase was due mainly to:

•	higher capital spending in recent periods on rental equipment and aftermarket facilities, as well as the impact of newly acquired businesses in the DPS segment,

•	higher spending for development of the Company’s enhanced business information systems, and

•	higher amortization of acquired intangibles.

Net interest for the six months ended June 30, 2012 was $44.7 million, an increase of $2.5 million, from $42.2 million for the six months ended June 30, 2011. The increase was due mainly to $1.7 million of additional interest associated with the $500 million senior note offering in May 2012 (see Note 8 of the Notes to Consolidated Condensed Financial Statements for further information).

Other costs consisted of:

	Six Months Ended June 30,
($ in millions)	2012			2011

International pension settlement costs	$	6.1		$	-
Acquisition integration costs		5.2			-
BOP litigation costs		1.0			22.3
Mark-to-market impact on currency derivatives not accounted for as hedges		(5.6	)		-
Severance, restructuring and other costs		1.7			6.7
	$	8.4		$	29.0

Segment Results

DPS Segment –

	Six Months Ended June 30,						Increase (Decrease)
($ in millions)	2012			2011			$		%

Revenues	$	2,197.9		$	1,868.3		$	329.6	17.6	%
Income before income taxes	$	311.4		$	277.6		$	33.8	12.2	%
Income before income taxes as a percent of revenues		14.2	%		14.9	%		N/A	(0.7	)%

Orders	$	3,306.6		$	2,261.0		$	1,045.6	46.2	%

Revenues

Nearly 80% of the increase in revenues was attributable to newly acquired businesses. Absent this effect,

•

sales of surface equipment increased almost 13% as a result of higher rental equipment initiatives for unconventional resource regions in North America and increased shipments to customers in Latin America and the Asia-Pacific region, and

•

drilling equipment sales increased approximately 4% mainly as a result of increased demand for stack upgrades, spares and repair services.

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 0.6 percentage-point increase in the ratio of depreciation and amortization expense to revenues primarily as a result of higher capital spending in recent periods on rental equipment and aftermarket facilities and higher amortization of acquired intangibles.

Orders

Subsea orders almost doubled in the first half of 2012 as compared to the same period last year, accounting for 54% of the increase in total segment orders. The increase was primarily the result of three large orders totaling 40 subsea trees slated for installation offshore Brazil, Egypt and China.

Other increases included:

•

orders from newly acquired businesses, which accounted for approximately 16% of the total segment order increase,

•

a 26% increase in surface equipment orders, excluding businesses recently acquired, resulting mainly from (i) increased demand for rental equipment and aftermarket parts and services in unconventional resource regions of North America, and (ii) increased activity levels in Latin America, the North Sea and the Asia-Pacific region, and

•

a 14% increase in drilling equipment orders, excluding businesses recently acquired, related primarily to higher demand for new equipment for land and jack-up rigs and for parts and services for spares and fleet upgrades.

V&M Segment –

	Six Months Ended June 30,						Increase
($ in millions)	2012			2011			$		%

Revenues	$	1,049.5		$	766.4		$	283.1	36.9	%
Income before income taxes	$	203.7		$	130.7		$	73.0	55.9	%
Income before income taxes as a percent of revenues		19.4	%		17.1	%		N/A	2.3	%

Orders	$	1,077.8		$	953.9		$	123.9	13.0	%

Revenues

Revenues increased across all product lines as a result of:

•

improved market conditions in North America, particularly in unconventional resource areas, which resulted in a 40% increase in sales of distributed valves and a 23% increase in measurement equipment sales during the six months ended June 30, 2012, as compared to the same period in 2011, and

•

an increase in sales of engineered and process valves of 46% and 38%, respectively as compared to the same period in 2011, due to higher North American and Asia Pacific activity levels, combined with 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 of 2.4% was due primarily to (i) a 3.5 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, and (ii) a 0.7 percentage-point decrease in the ratio of depreciation and amortization to revenues, due mainly to the impact of relatively flat depreciation and amortization expense on an increasing revenue base, offset by a 1.8 percentage-point increase in the ratio of cost of sales to revenues, due to mix changes in the first six months of 2012 as compared to the same period in 2011.

Orders

Orders increased in all product lines with engineering and process valves combining to account for nearly three-fourths of the total segment increase:

•

engineered valve orders were up 15% based on increased demand for pipeline valves in North America and the Asia-Pacific region,

•

a more active downstream market contributed to a 20% increase in orders for measurement equipment, and

•

the increased need in the U.S. for gas storage driven by lower prices led to a 20% increase in orders for process valves.

PCS Segment –

	Six Months Ended June 30,						Increase (Decrease)
($ in millions)	2012			2011			$			%

Revenues	$	610.6		$	607.6		$	3.0		0.5	%
Income before income taxes	$	37.5		$	64.5		$	(27.0	)	(41.9	)%
Income before income taxes as a percent of revenues		6.1	%		10.6	%		N/A		(4.5	)%

Orders	$	759.0		$	694.8		$	64.2		9.2	%

Revenues

The increase in revenues was mostly due to a 13% increase in sales of centrifugal compression equipment, largely related to higher international deliveries of new engineered and plant air equipment, partially offset by a 30% decline in sales of Superior Compressors, primarily resulting from a large international shipment of high speed packaged units that occurred in the first half of 2011, which did not repeat in the same period of 2012.

Income before income taxes as a percent of revenues

The ratio of income before income taxes as a percent of revenues decreased in the first six months of 2012 as compared to the first six months of 2011 primarily due to:

•

a 2.5 percentage-point increase in the ratio of cost of sales to revenues, reflecting lower margins in each of the major product lines, and

•

1.7 percentage-point increase in the ratio of selling and administrative costs to revenues as a result of higher employee-related costs and higher information technology and other costs in relation to relatively flat revenues.

Orders

The increase in orders for the first half of 2012 compared to the first half of 2011 was due largely to:

•

a doubling of the order rate for new Superior Compressors as a result of awards received for two large projects in the first six months of 2012, and

•

a 7% increase in process systems orders mainly due to higher demand for process applications in certain unconventional resource regions of the United States.

Corporate Segment –

The $12.1 million increase in the loss before income taxes of the Corporate segment during the first six months of 2012 as compared to the first six months of 2011 (see Note 10 of the Notes to Consolidated Condensed Financial Statements) was due primarily to:

•

a $20.0 million increase in selling and administrative expenses mainly related to higher incentive compensation and other employee-related costs, including at certain international locations which report directly to the Corporate office,

•

$7.4 million of higher depreciation and amortization largely related to increased spending in recent periods for development of the Company’s enhanced business information systems, and

•

an increase of $5.3 million in (i) foreign currency losses incurred on certain intercompany loans and (ii) net interest, as described in more detail under “Consolidated Results” above.

These increases were partially offset by a $20.6 million reduction in “Other costs” which is also described in more detail under “Consolidated Results” above.

Liquidity and Capital Resources

Consolidated Condensed Statements of Cash Flows

During the first six months of 2012, net cash used for operations totaled $40.3 million, a decrease of $185.0 million from the $225.3 million of cash used for operations during the first six months of 2011.

Cash totaling $463.6 million was used to increase working capital during the first six months of 2012 compared to $619.6 million during the first six months of 2011, a decrease of $156.0 million. During the first six months of 2012, the Company made a net cash payment of $82.5 million to BP Exploration and Production Inc. in connection with the indemnity settlement reached in late 2011. Additionally, inventory levels increased in the DPS and PCS segments to meet the demands from additional bookings and major project awards. Progress payments and customer advances increased as a result of collections associated with milestone payments on major project awards.

Cash used for investing activities increased by $302.2 million, from $166.9 million during the first six months of 2011 to $469.1 million during the first six months of 2012. This increase primarily resulted from higher capital expenditures of $47.5 million and the $248.1 million net cash purchase of TTS discussed further in Note 2 of the Notes to Consolidated Condensed Financial Statements.

Net cash provided by financing activities totaled $445.9 million for the first six months of 2012, mainly reflecting the $499.3 of net cash proceeds received from the public offering of Senior Notes by the Company in May 2012. A portion of these proceeds were used to fund the TTS acquisition noted above and to repay other debt, primarily in Brazil.

Future liquidity requirements

The Company expects to spend approximately $500 million for capital equipment and facilities for the full year of 2012.

The Company believes, based on its current financial condition, existing backlog levels and current expectations for future market conditions and potential future capital markets transactions, that it will be able to meet its short- and longer-term liquidity needs. Cash and short-term investments totaling $1.2 billion at June 30, 2012, future expected operating cash flows, and amounts available under the Company’s $835 million five-year Amended Credit Agreement, which ultimately expires on June 6, 2016, are expected to be used in some combination thereof to fund among other things, future acquisitions, the integration of the operations of its recent acquisitions into the Company, the remainder of the Company’s 2012 capital spending program and future working capital and other corporate needs.

At June 30, 2012, the amount available for borrowing under the Amended Credit Agreement totaled $809.6 million.

Factors That May Affect Financial Condition and Future Results

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

Demand for most of the Company’s products and services, and therefore its revenue, depends to a large extent upon the level of capital expenditures related to oil and gas exploration, 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 first quarter 2012 decline in natural gas spot prices in the United States to less than $2 per MMBtu, the lowest level in the last decade, could eventually result in a reduction in orders by the Company’s customers which could negatively impact the Company’s future revenues and profitability. See also the discussion in “Market Conditions” above.

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 June 30, 2012, the Company’s backlog was approximately $7.5 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 market price performance of the Company’s 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.

The Company reviews the carrying value of goodwill in accordance with accounting rules on impairment of goodwill, which require that the Company estimate the fair value of each of its reporting units annually, or when impairment indicators exist, and compare such amounts to their respective carrying values to determine if an impairment of goodwill is required. The estimated fair value of each reporting unit is determined using discounted future expected cash flow models (level 3 unobservable inputs) consistent with the accounting guidance for fair value measurements. Certain estimates and judgments are required in the application of the discounted cash flow models, including, but not limited to, estimates of future cash flows and the selection of a discount rate. Generally, this review is conducted during the first quarter of each annual period. The results of the 2012 test indicated that there was no impairment of goodwill. Should the Company’s estimate of the fair value of any of its reporting units decline significantly in future periods due to changes in customer demand, market activity levels, interest rates or other factors which would impact future earnings and cash flow or market valuation levels of the Company or any of its reporting units, an impairment of goodwill could be required.

Total Company goodwill at June 30, 2012 was nearly $2.0 billion, a large portion of which was allocated to the Company’s PCS segment, which includes the majority of the NATCO operations acquired in 2009. The Company’s determination of the fair value of its Custom Process Systems (CPS) business within the PCS segment included assumptions for continued long-term improvements to recent historical and 2012 budgeted results. As a result of competitive pressures during the economic downturn that began prior to the acquisition of the NATCO operations in 2009, the backlog of the CPS business has carried unusually low margins which have negatively impacted recent profitability. The CPS business has also underperformed its estimated budget for the second quarter of 2012. While management is taking steps to reverse this trend, should the CPS business continue to underperform future expectations assumed in our discounted cash flow calculations, an impairment of goodwill for this reporting unit could be required. Goodwill associated with the CPS business was approximately $572.4 million at June 30, 2012.

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

Cameron is a significant participant in the subsea systems projects market. This market is significantly different from most of 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 and (iv) often involve the application of existing technology to new environments and, in some cases, may require the development of new technology. The Company’s subsea business unit received orders in the amount of $1.2 billion during the first six months ended June 30, 2012. Total backlog for the subsea business unit at June 30, 2012 was approximately $2.3 billion. To the extent the Company experiences unplanned difficulties in meeting the technical and/or delivery requirements of the projects, the Company’s earnings or liquidity could be negatively impacted. The Company accounts for its subsea projects, as it does its 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 overruns, the expected margin could decline. Were this to occur, in accordance with the accounting guidance, the Company would record a cumulative adjustment to reduce the margin previously recorded on the related project in the period a change in estimate is determined. As an example, the Company incurred a $51.0 million charge in the first quarter of 2011 for cost overruns on a large subsea project in Nigeria. Large subsea systems projects accounted for approximately 11.2% of total revenues for the six-month period ended June 30, 2012 and represent a significant portion of the subsea business unit’s total operations. As of June 30, 2012, the Company had a subsea systems project backlog of approximately $1.6 billion.

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

Cameron provides products and systems to customers involved in oil and gas exploration, development and production, as well as in certain other industrial markets. Some of the Company’s equipment is designed to operate in high-temperature, 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, including customer sites, for this and other equipment. Because of applications to which the Company’s products and services are put, particularly those involving the high temperature and pressure environments, a failure of such equipment, or a failure by the Company’s customers to maintain, operate or use the equipment properly, could cause damage to the equipment, damage to customers’ and third-parties’ property, personal injury and environmental contamination, onshore or offshore. 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. See the discussion of the Deepwater Horizon Matter in Note 13 of the Notes to Consolidated Condensed Financial Statements.

Integration of the recent acquisitions of LeTourneau Technologies, Inc. and TTS into the Company’s operations may cause disruptions, inefficiencies or the risk of unplanned costs for the Company.

In October 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. In June 2012, the Company closed on the acquisition of TTS, for $248.1 million, net of cash acquired, subject to certain post-closing adjustments. The Company will spend a good portion of 2012 integrating the operations of both LeTourneau and TTS into Cameron’s Drilling Systems division of the DPS segment. The integration of these operations will require a significant amount of time and effort for management and employees and may result in disruptions and inefficiencies for a period of time. Additionally, former customers of these companies may elect to buy from competitors of Cameron rather than continue to do business with these former entities now that they have become part of the Cameron organization. Costs of integrating these operations into Cameron could exceed what is currently expected. Any of these events, if they occurred, could negatively impact the Company’s expected future revenues, costs, profitability and operating cash flows.

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

The Company has established multiple “Centers of Excellence” facilities for manufacturing such products as subsea trees, subsea chokes, subsea production controls and 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 operations expose it to risks of non-compliance with multiple trade regulations and import/export laws and regulations.

The Company’s operations expose it to trade regulations and import/export regulations of multiple jurisdictions. In addition to using “Centers of Excellence” for manufacturing products to be delivered around the world the Company imports raw materials, semi-finished goods as well as finished products into many countries for use in country or for manufacturing and/or finishing for re-export and import into another country for use or further integration into equipment or systems. Most movement of raw materials, semi-finished or finished products by the Company involves exports and imports. As a result, compliance with multiple trade sanctions and embargoes and import and export laws and regulations pose a constant challenge and risk to the Company. Cameron has received a number of inquiries from U.S. governmental agencies, including the U.S. Securities and Exchange Commission and the Office of Foreign Assets Control regarding compliance with U.S. trade sanction and export control laws as well as inquiries from other countries regarding compliance with their export and customer laws and regulations. The Company also regularly undergoes governmental audits to determine compliance with export and customs laws and regulations. Recently the Company underwent a Focused Assessment Audit regarding compliance with U.S. customs regulations and is currently undergoing a customs audit in Brazil, and has received inquiries regarding compliance with export and customs laws and regulations from several other countries. The Company has been assessed with approximately $51.0 million of additional customs duties, penalties and interest by the government of Brazil as a result of the current customs audit for the years 2003-2010. The Company has identified numerous errors in the assessment, the government has not provided appropriate supporting documentation for the assessment, and the Company believes a vast majority of this assessment will ultimately be proven to be incorrect. As a result, the Company currently expects no material adverse impact on its results of operations or cash flows as a result of the ultimate resolution of this matter. No amounts have been accrued for this assessment as of June 30, 2012 as no loss is currently considered probable.

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

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

•	volatility in general economic, social and political conditions;
•	the effects of civil unrest and sanctions imposed by the United States and other governments on transactions with various countries, such as Iran and, in 2011, Libya;
•	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 and/or increasing tax rates. 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;
•	exchange controls or other similar measures that result in restrictions on repatriation of capital and/or income; and
•	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. Recent increases in activity levels in certain of these regions have increased the Company’s risk of identifying and hiring sufficient numbers of qualified personnel to meet increased customer demand in selected locations. The Company also purchases a large portion of its raw materials and components from a relatively small number of foreign suppliers in China, India and other developing countries. The ability of these suppliers to meet the Company’s demand could be adversely affected by the factors described above.

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 and subject to civil unrest and labor strife. This increases the risk of untimely deliveries, cost overruns and defective products.

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

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

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

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

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

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

The Company provides equipment and services to companies employing hydraulic fracturing or “fracking” and could be adversely impacted by new regulations of this enhanced recovery technique. Environmental concerns have been raised regarding the potential impact on underground water supplies of fracturing which involves the pumping of water and certain chemicals under pressure into a well to break apart shale and other rock formations in order to increase the flow of oil and gas embedded in these formations. Recently, certain U.S. states have proposed regulations regarding disclosure of chemicals used in fracking operations or have temporarily suspended issuance of permits for conducting such operations. Additionally, the United States Environmental Protection Agency (EPA) issued rules on April 17, 2012, designed to limit the release of volatile organic compounds, or pollutants, from natural gas wells that are hydraulically fractured. Companies will be required to implement these new rules beginning January 2015. The EPA is also continuing to study whether the fracking process has any negative impact on underground water supplies. Should additional governmental regulations ultimately be imposed that further restrict or curtail hydraulic fracking activities, the Company’s revenues and earnings could be negatively impacted.

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

The EPA has made a finding under the United States Clean Air Act that greenhouse gas emissions endanger public health and welfare and the EPA has enacted regulations requiring monitoring and reporting by certain facilities and companies of greenhouse gas emissions. Carbon emission reporting and reduction programs have also expanded in recent years at the state, regional and national levels with certain countries having already implemented various types of cap-and-trade programs aimed at reducing carbon emissions from companies that currently emit greenhouse gases.

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

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 on modifications of certain of its compression products, which involve use of power generation equipment.

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

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. Deployment to the remaining businesses within the PCS segment was completed at the beginning of the second quarter of 2012. 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.

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

Cameron continues to increase its dependence on digital technologies to conduct its operations, to collect monies from customers and to pay vendors and employees. Many of the Company’s files are digitized and more employees are working in almost paperless environments. Additionally, the hardware, network and software environments to operate SAP, the Company’s main enterprise-wide operating system, have been outsourced to third parties. Other key software products used by the Company to conduct its operations either reside on servers in remote locations or are operated by the software vendors or other third parties for the Company’s use as “cloud-based” or “web-based” applications. The Company has also outsourced certain information technology development, maintenance and support functions. As a result, the Company is exposed to potentially severe cyber incidents at both its internal locations and outside vendor locations that could disrupt its operations for an extended period of time and result in the loss of critical data and in higher costs to correct and remedy the effects of such incidents, although no such material incidents have occurred to date. The Company has developed disaster recovery procedures and maintains security policies to control access to and changes in its operating systems and periodically reviews similar controls and policies of its key software, hardware and network vendors.

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.

For further information, refer to Note 13 of the Notes to Consolidated Condensed Financial Statements.

Environmental Sustainability

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

Cameron has implemented a corporate “HSE 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 implemented a corporate regulatory compliance audit program to verify facility compliance with environmental, health and safety laws and regulations. The compliance program employs or uses independent third party auditors to audit facilities on a regular basis specific to country, region, and local legal requirements. Audit reports are circulated to the senior management of the Company and to the appropriate business unit. The compliance program requires corrective and preventative actions be taken by a facility to remedy all findings of non-compliance, which are tracked on the corporate HSE data base.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Foreign Currency Exchange Rates

A large portion of the Company’s operations consist of manufacturing and sales activities in foreign jurisdictions, principally in Europe, Canada, West Africa, the Middle East, Latin America 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.

Capital Markets and Interest Rates

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

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

The fair values of the 1.6% 3-year Senior Notes, the 3.6%, 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.

Item 4. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, the Company carried out an evaluation, under the supervision and with the participation of the Company’s Sarbanes-Oxley Disclosure Committee and the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2012 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 June 30, 2012.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Deepwater Horizon Matter

For further information, refer to Note 13 of the Notes to Consolidated Condensed Financial Statements.

Item 1A. Risk Factors

The information set forth under the caption “Factors That May Affect Financial Condition and Future Results” on pages 28 – 33 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

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

In December 2011, the Board of Directors adopted a resolution allowing for the repurchase of shares of the Company’s common stock up to an amount of $500.0 million. This authorization superseded and replaced all previous authorizations. The Company, under this authorization, may purchase shares directly or indirectly by way of open market transactions or structured programs, including the use of derivatives, for the Company’s own account or through commercial banks or financial institutions.

Shares of common stock purchased and placed in treasury during the three months ended June 30, 2012 under the Board’s authorization program described above were as follows:

Period	Total number of shares purchased		Average price paid per share		Total number of shares purchased as part of repurchase program		Maximum number of shares that may yet be purchased under repurchase program(1)
4/1/12 – 4/30/12		−	$	−		106,200		9,647,278
5/1/12 – 5/31/12		15,600	$	45.59		121,800		10,805,687
6/1/12 – 6/30/12		84,400	$	43.31		206,200		11,474,046
Total		100,000	$	43.66		206,200		11,474,046

(1)	Based upon month-end stock price.

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

N/A

Item 5. Other Information

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

None

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

There have been no material changes to the procedures enumerated in the Company’s definitive proxy statement filed on Schedule 14A with the Securities and Exchange Commission on March 28, 2012 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: July 30, 2012	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