Edgar Filing: FMC TECHNOLOGIES INC

FMC-2013.12.31-10K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)



ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-16489

FMC TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)



Delaware	36-4412642
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

5875 N. Sam Houston Parkway W., Houston, Texas	77086
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 281/591-4000

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Name of each exchange on which registered
Common Stock, $0.01 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ý NO ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ¨ NO ý

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 ý NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 ý NO ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§232.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 ý Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ¨ NO ý

The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant, determined by multiplying the outstanding shares on June 30, 2013, by the closing price on such day of $55.68 as reported on the New York Stock Exchange, was $7,853,278,583.*

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of February 19, 2014 was 236,011,911.

DOCUMENTS INCORPORATED BY REFERENCE



DOCUMENT	FORM 10-K REFERENCE
Portions of Proxy Statement for the 2014 Annual Meeting of Stockholders	Part III



*	Excludes 96,113,955 shares of the registrant’s Common Stock held by directors, officers and holders of more than 5% of the registrant’s Common Stock as of June 30, 2013. Exclusion of shares held by any person should not be construed to indicate that such person or entity possesses the power, direct or indirect, to direct or cause the direction of the management or policies of the registrant, or that such person or entity is controlled by or under common control with the registrant.

TABLE OF CONTENTS



	Page
PART I

Item 1. Business	4
Executive Officers of the Registrant	12
Item 1A. Risk Factors	13
Item 1B. Unresolved Staff Comments	18
Item 2. Properties	19
Item 3. Legal Proceedings	19
Item 4. Mine Safety Disclosures	19

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6. Selected Financial Data	22
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	43
Item 8. Financial Statements and Supplementary Data	44
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
Item 9A. Controls and Procedures	93
Item 9B. Other Information	93

PART III

Item 10. Directors, Executive Officers and Corporate Governance	94
Item 11. Executive Compensation	94
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	94
Item 13. Certain Relationships and Related Transactions, and Director Independence	95
Item 14. Principal Accounting Fees and Services	95

PART IV

Item 15. Exhibits, Financial Statement Schedules	96
Signatures	98

Cautionary Note Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact contained in this report are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements usually relate to future events and anticipated revenues, earnings, cash flows or other aspects of our operations or operating results. Forward-looking statements are often identified by the words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” “may,” “estimate,” “outlook” and similar expressions, including the negative thereof. The absence of these words, however, does not mean that the statements are not forward-looking. These forward-looking statements are based on our current expectations, beliefs and assumptions concerning future developments and business conditions and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.

All of our forward-looking statements involve significant risks and uncertainties (many of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. These factors include those described in Part I, Item 1A “Risk Factors” of this Annual Report on Form 10-K and factors that are unknown or unpredictable. We wish to caution you not to place undue reliance on any forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any of our forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except to the extent required by law.

PART I

ITEM 1. BUSINESS

OVERVIEW

FMC Technologies, Inc. is a global provider of technology solutions for the energy industry. FMC Technologies, Inc. was incorporated in November 2000 under Delaware law and was a wholly-owned subsidiary of FMC Corporation until our initial public offering in June 2001. Our principal executive offices are located at 5875 North Sam Houston Parkway West, Houston, Texas 77086. As used in this report, except where otherwise stated or indicated by the context, all references to the “Company,” “FMC Technologies,” “we,” “us,” and “our” are to FMC Technologies, Inc. and its consolidated subsidiaries.

We design, manufacture and service technologically sophisticated systems and products, including subsea production and processing systems, surface wellhead production systems, high pressure fluid control equipment, measurement solutions and marine loading systems for the energy industry. We report our results of operations in the following reporting segments: Subsea Technologies, Surface Technologies and Energy Infrastructure. Financial information about our business segments is incorporated herein by reference from Note 19 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

During 2012 we acquired the remaining 55% of Schilling Robotics, LLC (“Schilling Robotics”), 100% of Pure Energy Services Ltd. (“Pure Energy”) and 100% of Control Systems International, Inc. (“CSI”). Schilling Robotics is a supplier of advanced robotic intervention products, including a line of remotely operating vehicle systems (“ROV”), manipulator systems and subsea control systems and is included in our Subsea Technologies segment. The acquisition of the remaining 55% of Schilling Robotics is allowing us to grow in the expanding subsea environment, where demand for ROVs and the need for maintenance activities of subsea equipment is expected to increase. Additionally, we acquired Pure Energy, a provider of fracturing flowback services and wireline services. The acquisition of Pure Energy is complementing the existing products and services of our Surface Technologies segment and is creating client value by providing an integrated well site solution. Finally, we acquired CSI, a provider of automation, control and information technology to the oil and gas industry. Included in our Energy Infrastructure segment, CSI is enhancing our automation and controls technologies and is benefiting production and processing businesses such as measurement solutions through comprehensive fuel terminal and pipeline automation systems. Additional financial information about our 2012 business combinations is incorporated herein by reference from Note 4 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

During 2013 and in conjunction with management’s efforts to accelerate the development and commercialization of subsea boosting technology for subsea markets, our direct drive systems technology development, previously reported in our Energy Infrastructure segment, is now reported in our Subsea Technologies segment. All prior-year information has been adjusted to reflect the current presentation.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and amendments to those reports are available free of charge through our website at www.fmctechnologies.com, under “Investors—Financial Information—SEC Filings” as soon as reasonably practicable after we file the reports with the Securities and Exchange Commission (the “SEC”). Alternatively, our reports may be accessed through the website maintained by the SEC at www.sec.gov.

Throughout this Annual Report on Form 10-K, we incorporate by reference certain information from our Proxy Statement for the 2014 Annual Meeting of Stockholders. We intend to provide stockholders with an annual report containing financial information that has been examined and reported upon, with an opinion expressed thereon by our independent registered public accounting firm. On or about April 2, 2014, we expect our Proxy Statement for the 2014 Annual Meeting of Stockholders will be available on our website under “Investors—Financial Information—SEC Filings.” Similarly, on the same date, we expect our 2013 Annual Report to Stockholders will be available on our website under “Investors—Financial Information—Annual Reports.”

BUSINESS SEGMENTS

Subsea Technologies

Subsea Technologies designs and manufactures products and systems and provides services used by oil and gas companies involved in deepwater exploration and production of crude oil and natural gas. The core competencies of this segment are our

technology and engineering expertise. Our production systems control the flow of crude oil and natural gas from producing wells. We specialize in offshore production systems and have manufacturing facilities near the world’s principal offshore oil and gas producing basins. We market our products primarily through our own technical sales organization.

Principal Products and Services

Subsea Systems. Our systems are used in the offshore production of crude oil and natural gas. Subsea systems are placed on the seafloor and are used to control the flow of crude oil and natural gas from the reservoir to a host processing facility, such as a floating production facility, a fixed platform or an onshore facility.

The design and manufacture of our subsea systems requires a high degree of technical expertise and innovation. Some of our systems are designed to withstand exposure to the extreme hydrostatic pressure that deepwater environments present, as well as internal pressures of up to 15,000 pounds per square inch (“psi”) and temperatures in excess of 350º F. The development of our integrated subsea production systems includes initial engineering design studies and field development planning to consider all relevant aspects and project requirements including optimization of drilling programs and subsea architecture. Our subsea production systems and products include drilling systems, subsea trees, chokes and flow modules, manifold pipeline systems, control and data acquisition systems, well access systems and other electric technology. Additionally, as part of our technologies to enhance field economics by maximizing recovery, our subsea processing systems can enable cost-effective, platform-less solutions where the field is tied directly back to an existing offshore facility or directly to shore. Subsea processing system solutions include subsea boosting, subsea gas compression and subsea separation which are designed to accelerate production, increase recovery or extend field life. In order to provide these products, systems and services, we utilize engineering, project management, procurement, manufacturing, assembly and testing capabilities.

We also provide well access and flow management services and other customer support services that offer a broad range of products and services including installation and workover tools, service technicians for installation assistance and field support for commissioning, intervention, and maintenance of our subsea systems throughout the life of the field. This scope of activity also includes providing tools and technical support such as our riserless light well intervention system for certain well workover and intervention tasks. In 2012, FMC Technologies formed a joint venture with Edison Chouest Offshore LLC to provide integrated vessel-based subsea services for offshore oil and gas fields around the world. This joint venture is expected to provide cost-effective solutions to enhance our customer’s ability to initiate, maintain and increase production from subsea field developments through efficient operations, innovative technologies and a broad inventory of vessels and tools.

Subsea systems represented approximately 63%, 62% and 64% of our consolidated revenue in 2013, 2012 and 2011, respectively.

Schilling Robotics. We design and manufacture ROVs and remote manipulator arms and provide support services for subsea control systems for subsea exploration and production. Our product offering includes electric and hydraulic work-class ROVs, tether-management systems, launch and recovery systems, remote manipulator arms and modular control systems for wide-ranging subsea applications. We also provide services such as engineering services, operations and maintenance training, simulation and mission planning, and ROV mobilization support and service.

Multi Phase Meters. We design and manufacture multiphase and wetgas meters with applications that include production and surface well testing, reservoir monitoring, remote operation, measurement of fluid rates for production and revenue sharing between partners, process monitoring and control, and artificial lift optimization. This technology delivers highly accurate, self-calibrating meters with low maintenance features to meet our customers’ increasing requirements for subsea and topside applications. The Multi Phase Meters product line augments our portfolio of technologies for increasing oil and gas recovery, early water detection and reservoir optimization.

Capital Intensity

Many of the systems and products we supply for subsea applications are highly engineered to meet the unique demands of our customers and are typically ordered one to two years prior to installation. We often receive advance and progress payments from our customers in order to fund initial development and our working capital requirements. However, our working capital balances can vary significantly depending on the payment terms and execution timing on key contracts.

Dependence on Key Customers

Generally, our customers in this segment are major integrated oil companies, national oil companies and independent exploration and production companies.

We have actively pursued alliances with oil and gas companies that are engaged in the subsea development of crude oil and natural gas to promote our integrated systems for subsea production. Development of subsea fields, particularly in deepwater environments, involves substantial capital investments by our customers. Our customers have sought the security of alliances with us to ensure timely and cost-effective delivery of subsea and other energy-related systems that provide integrated solutions to their needs. Our alliances establish important ongoing relationships with our customers. While our alliances do not contractually commit our customers to purchase our systems and services, they have historically led to, and we expect that they will continue to result in, such purchases. Examples of customers we have entered alliances with include Statoil, Shell, BP and Anadarko.

The loss of one or more of our significant oil and gas company customers could have a material adverse effect on our Subsea Technologies business segment. In 2013, we generated approximately 12% of our consolidated revenue from Statoil.

Competition

Subsea Technologies competes with other companies that supply subsea systems and with smaller companies that are focused on a specific application, technology or geographical niche in which we operate. Companies including OneSubsea, GE Oil & Gas, Aker Solutions and Dril-Quip compete with us in the marketplace across our various Subsea Technologies product lines.

Competitive factors in our industry include reliability, cost-effective technology, execution and delivery. Our competitive strengths include our intellectual capital, our execution of our projects, reliability of our products, experience base and breadth of technologies embedded in our products and services that enable us to design unique solutions for our customers’ project requirements while incorporating standardized components to contain costs. We maintain a presence in all of the world’s major producing basins. Our strong customer relationships, experience and technology help us maintain a leadership position in subsea systems.

Seasonality

In the North Sea, winter weather generally subdues drilling activity and demand for subsea services as certain activities cannot be performed. As a result, the level of offshore activity in our subsea services is negatively influenced and tends to decrease in the first quarter of the year.

Surface Technologies

Surface Technologies designs and manufactures products and systems and provides services used by oil and gas companies involved in land and offshore exploration and production of crude oil and natural gas. We also design, manufacture and supply technologically advanced high pressure valves, pumps and fittings used in stimulation activities for oilfield service companies and provide fracturing flowback and wireline services for exploration companies in the oil and gas industry.

Principal Products and Services

Surface Wellhead. We provide a full range of drilling, completion and production systems for both standard service and custom-engineered, critical-service applications. Surface production systems, or trees, are used to control and regulate the flow of crude oil and natural gas from the well. Our surface products and systems are used worldwide on both onshore and offshore applications and can be used in difficult climates, including arctic cold or desert high temperatures. Our product technologies include conventional wellheads, unihead drill-thru wellheads designed for faster surface installations, drilling time optimization (“DTO”) timesaving conventional wellheads designed to reduce overall rig time and other technologies including sealing technology, thermal equipment, and valves and actuators. We support our customers through comprehensive surface wellhead system service packages that provide strategic solutions to ensure optimal equipment performance and reliability and include all phases of the asset’s life cycle, from the early planning stages through testing and installation, commissioning and operations, replacement and upgrades, interventions, decommissioning/abandonment, and maintenance, storage and preservations. In addition, our integrated shale services include hydraulic fracturing manifolds and trees and flow back equipment for timely and cost-effective well completion.

Surface wellhead represented approximately 14%, 13% and 14% of our consolidated revenue in 2013, 2012 and 2011, respectively.

Fluid Control. We design and manufacture flowline products, under the Weco^®/Chiksan^® trademarks, articulating frac arm manifold trailers, well service pumps, compact valves and reciprocating pumps used in well completion and stimulation activities by major oilfield service companies, such as Schlumberger Limited, Baker Hughes Incorporated, Halliburton Company and Weatherford International Ltd. Our flowline products are used in equipment that pumps corrosive and/or erosive fluid into a well during the well construction, hydraulic fracturing or other stimulation processes. Our well service pump product line includes Triplex and Quintuplex pumps utilized in a variety of applications including fracturing, acidizing and matrix stimulation and are capable of delivering flow rates up to 50 barrels per minute at pressures up to 20,000 psi. The performance of this business typically rises and falls with variations in the active rig count throughout the world and pressure pumping activity in the Americas.

Fluid control represented approximately 8%, 12% and 12% of our consolidated revenue in 2013, 2012 and 2011, respectively.

Completion Services. We provide fracturing flowback services, cased hole electric wireline and slickline services, specialty logging services, pressure transient analysis, and well optimization and swabbing services for exploration companies in the oil and gas industry. Acquired in October 2012 and formerly known as Pure Energy Services Ltd., our completion services business provides fracturing flowback and wireline services. Fracturing flowback services provide our customers the well services necessary for the recovery of solids, fracturing fluids and hydrocarbons from oil and natural gas wells after the stimulation of the well and can involve high pressure or multi-well pad operations.

Capital Intensity

Surface Technologies manufactures most of its products, resulting in a reliance on manufacturing locations throughout the world. We also maintain a large amount of rental equipment related to pressure pumping operations.

Dependence on Key Customers

No single Surface Technologies customer accounted for 10% or more of our 2013, 2012 or 2011 consolidated revenue.

Competition

Surface Technologies currently is a market leader for its primary products and services. Some of the competitive factors include technological innovation, reliability and product quality. Surface Technologies competes with other companies that supply surface production equipment and pressure pumping products. Some of our major competitors include Cameron International Corporation, Weir Oil & Gas, GE Oil & Gas and Gardner Denver, Inc.

Seasonality

In western Canada, the level of activity in the oilfield services industry is influenced by seasonal weather patterns. During the spring months, wet weather and the spring thaw make the ground unstable and less capable of supporting heavy equipment and machinery. As a result, municipalities and provincial transportation departments enforce road bans that restrict the movement of heavy equipment, which reduces activity levels. There is greater demand for oilfield services provided by our completion services business in the winter season when freezing permits the movement and operation of heavy equipment. Activities tend to increase in the fall and peak in the winter months of November through March.

Energy Infrastructure

Principal Products and Services

Measurement Solutions. We design and manufacture measurement systems for use in custody transfer of crude oil, natural gas and refined products. Our measurement systems provide solutions in energy-related applications such as crude oil and natural gas production and transportation, refined product transportation, petroleum refining, and petroleum marketing and distribution. We combine advanced measurement technology with state-of-the-art electronics and supervisory control systems to provide the measurement of both liquids and gases for purposes of verifying ownership and determining revenue and tax obligations.

We also provide design, engineering, project management, training, commissioning and aftermarket services in connection with the applications of blending and transfer technology solutions and process automation systems for manufacturers in the lubricant, petroleum, fuel blending, and additive and chemical industries.

Loading Systems. We provide land- and marine-based fluid loading and transfer systems to the oil and gas, petrochemical and chemical industries. Our systems are capable of loading and offloading marine vessels transporting a wide range of fluids including crude oil, liquefied natural gas (“LNG”) and refined products. While these systems are typically constructed on a fixed jetty platform, we also have developed advanced loading systems that can be mounted on a vessel or structure to facilitate ship-to-ship and tandem loading and offloading operations in open seas or exposed locations.

Material Handling Solutions. We provide material handling solutions, including bulk conveying systems, primarily to the power generation and mining industries. We provide innovative solutions for conveying, feeding, screening and orienting bulk product for customers in diverse industries. We offer system design, equipment supply, installation, commissioning and aftermarket support which enable us to provide performance optimization solutions for existing systems or newly customized turnkey plants.

Separation Systems. We design and manufacture systems that separate production flows from wells into oil, gas, sand and water. Our separation technology improves upon conventional separation technologies by moving the flow in a spiral, spinning motion. This causes the elements of the flow stream to separate more efficiently than conventional separation technologies. These systems are currently capable of subsea and topside applications. For subsea separation, performing a part of the required separation process at the seabed enables our customers to have more effective production and reduces the need for topside processing capacity. We are able to apply subsea separation technologies for both greenfield development and retrofit solutions for fields currently in production in order to reduce costs for topside facilities and increase production and recovery of fields.

Automation and Control. We provide automation, control and information technology for the oil and gas and other industries. Acquired in April 2012 and formerly known as Control Systems International, Inc., our automation and control business is a supplier of innovative control and automation system solutions through two primary products: (i) UCOS^® and (ii) FUEL-FACS+^®. UCOS^® is a comprehensive software solution that combines distributed control system and supervisory control and data acquisition system retrofits using software solutions and compression control algorithms which allows customers to control and manage the engineering, design and monitoring of their systems of operations. Additionally, FUEL-FACS+^® is a terminal automation and information management system that allows customers to monitor and control terminal liquid flows and inventory.

Dependence on Key Customers

No single Energy Infrastructure customer accounted for 10% or more of our 2013, 2012 or 2011 consolidated revenue.

OTHER BUSINESS INFORMATION RELEVANT TO OUR BUSINESS SEGMENTS

Product Development

We continue to invest in product development to advance technologies necessary to support the current and future technical challenges of our customers. New products and services are developed in order to ensure our ability to tender in upcoming projects and to develop our growth platforms. We also strive to increase standardization within our product lines in order to reduce delivery times, improve product integrity and control costs. To satisfy all these aims, we are focused on leveraging capabilities and advanced technologies across all of our businesses.

In our Subsea Technologies segment, we seek to invest in new technology that will enable the development of challenging fields. We continue to expand the portfolio of solutions in order to deliver a complete production system for high pressure, high temperature (“HPHT”) applications. During 2013, we began delivering Enhanced Vertical Deepwater Trees (“EVDTs”) that can perform at pressures as high as 15,000 psi and temperatures of 350º F. Key development work continued in the areas of valves, seals and materials to engineer a portfolio of solutions for performance in 20,000 psi and 400º F environments.

In addition to the development of new technology, we also seek to develop solutions that will help operators maximize recovery from existing subsea fields. We continue to develop motor and drive solutions for pumps in order to expand our subsea product portfolio and to meet a broader set of market needs. Along with our development partner, Sulzer Pumps Ltd, we advanced development of multiphase pump systems that will be capable of higher pressures, temperatures, and gas fractions. Utilizing our permanent magnet motor technology, our solutions offer higher speeds, power and efficiency than conventional induction motors. Also supporting these efforts was the development of sensing and monitoring technologies to enable condition and performance monitoring of subsea processing systems. This instrumentation will help operators better understand how subsea systems perform.

Demanding field installations and well intervention operations are increasing the demand and use of ROVs. In our Schilling Robotics business, progress was made in the development of our third generation ultra-heavy duty, work-class ROV. This recent evolution will feature a new hydraulic system, tool dynamic positioning system and high definition Ethernet video system enhancing vehicle operation for ROV pilots.

We are also expanding our subsea services portfolio enabling us to provide more services that maximize production and recovery over the life of the field. We continued construction of a fourth riserless light well intervention (“RLWI”) system. RLWI is a cost-effective intervention solution designed to perform various types of jobs in offshore wells that will improve and optimize recovery using smaller, purpose-built intervention vessels rather than rigs.

In our Surface Technologies segment, development work focused on enhancing our capabilities to provide products and services to support shale operations. Our fluid control business completed development of its new fluid end for well service pumps. Fluid ends are high-wear products containing replaceable valve, piston and liner components that enable pumping. The new fluid end offers better fatigue life by improving internal and external geometry to lower stress. The design allows quick and easy maintenance of well service pumps used in pressure pumping applications. Additional investments in Surface Technologies were directed toward the development of condition and performance monitoring capabilities for surface trees as well as the enhancement of our capabilities to support shallow water production such as our JXT (Jack-Up X-mass Tree) product line, our tree systems for shallow water, jack-up applications. These standard products provide production options that enable operators to minimize time to first oil and reduce capital investments.

In our Energy Infrastructure segment, our separation systems business completed the development of several technologies to improve separation performance, including development work on separation technology to support fracturing operations. These innovative technologies are expected to minimize the footprint of equipment at the frac site and reduce water costs. Our measurement solutions business completed development work on new hardware and software platforms for measurement devices. The new platform will be used across several product lines including ultrasonic meters and electronic truck registers and offers improved usability and diagnostic capabilities.

Order Backlog

Information regarding order backlog is incorporated herein by reference from the section entitled “Inbound Orders and Order Backlog” in Part II, Item 7 of this Annual Report on Form 10-K.

Sources and Availability of Raw Materials

Our business segments purchase carbon steel, stainless steel, aluminum and steel castings and forgings both domestically and internationally. We typically do not use single source suppliers for the majority of our raw material purchases; however, certain geographic areas of our businesses or a project or group of projects may heavily depend on certain suppliers for raw materials or supply of semi-finished goods. We believe the available supplies of raw materials are adequate to meet our needs.

Research and Development

We are engaged in research and development (“R&D”) activities largely directed toward the improvement of existing products and services, the design of specialized products to meet customer needs and the development of new products, processes and services. A large part of our product development spending has focused on the improved design and standardization of our Subsea Technologies product lines to meet our customer needs. Financial information about Company-sponsored R&D activities is incorporated herein by reference from Note 19 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Patents, Trademarks and Other Intellectual Property

We own a number of U.S. and foreign patents, trademarks and licenses that are cumulatively important to our businesses. As part of our ongoing research and development, we seek patents when appropriate for new products and product improvements. We have approximately 1,100 issued patents and pending patent applications worldwide. Further, we license intellectual property rights to or from third parties. We also own numerous U.S. and foreign trademarks and trade names and have approximately 225 registrations and pending applications in the United States and abroad.

We protect and promote our intellectual property portfolio and take those actions we deem appropriate to enforce and defend our intellectual property rights. We do not believe, however, that the loss of any one patent, trademark or license, or group of related patents, trademarks or licenses would have a material adverse effect on our overall business.

Employees

As of December 31, 2013, we had approximately 19,300 full-time employees, consisting of approximately 6,450 in the United States and 12,850 in non-U.S. locations. Less than 2% of our U.S. employees are represented by labor unions.

International Operations in Countries Subject to U.S. Restrictions

In 2009, like many other companies, we adopted a policy directing our non-U.S. subsidiaries to effectuate an orderly withdrawal from doing business with the various countries subject to U.S. restrictions. This policy prohibited entering into new commitments involving these countries, but did not require the non-U.S. subsidiaries to cease performance of existing commitments, provided such commitments could be performed in compliance with all applicable laws and regulations. As a result of this policy decision, non-U.S. subsidiary sales to these countries accounted for less than 0.002% of our consolidated revenue in 2013. As such, we consider these sales immaterial. We had no sales in Iran or Syria during 2013. While some residual service-related sales may occur after 2013, we expect these to be insignificant since all remaining outstanding commitments have been substantially completed.

Segment and Geographic Financial Information

The majority of our consolidated revenue and segment operating profits are generated in markets outside of the United States. Each of our segments’ revenue is dependent upon worldwide oil and gas exploration and production activity. Financial information about our segments and geographic areas is incorporated herein by reference from Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.

EXECUTIVE OFFICERS OF THE REGISTRANT

Pursuant to General Instruction G(3) to Form 10-K, the information regarding our executive officers called for by Item 401(b) of Regulation S-K is hereby included in Part I, Item 1 “Business” of this Annual Report on Form 10-K.

As of February 21, 2014, the executive officers of FMC Technologies, together with the offices currently held by them, their business experience and their ages, are as follows:



Name	Age	Current Position and Business Experience
John T. Gremp	62	Chairman, President and Chief Executive Officer (2013) Chairman and Chief Executive Officer (2012) Chairman, President and Chief Executive Officer (2011) President and Chief Operating Officer (2010) Executive Vice President—Energy Systems (2007)
Maryann T. Seaman	51	Senior Vice President and Chief Financial Officer (2011) Vice President—Treasurer and Deputy Chief Financial Officer (2010) Vice President—Administration (2007)
Bradley D. Beitler	60	Vice President—Technology (2009) Director of Technology (2006)
Sanjay Bhatia	44	Vice President—Corporate Development (2012) Director of Business Development (2007)
Jeffrey W. Carr	57	Senior Vice President, General Counsel and Secretary (2010) Vice President, General Counsel and Secretary (2001)
Tore Halvorsen	59	Senior Vice President—Subsea Technologies (2011) Senior Vice President—Global Subsea Production Systems (2007)
Jay A. Nutt	50	Vice President and Controller (2009) Controller (2008)
Johan Pfeiffer	49	Vice President—Surface Technologies (2011) Vice President—Global Surface Wellhead (2010) General Manager for Subsea activities in Europe, Africa, and the Commonwealth of Independent States (CIS) (2007)
Douglas J. Pferdehirt	50	Executive Vice President and Chief Operating Officer (2012) Executive Vice President—Corporate Development & Communication for Schlumberger Limited (2011) President Reservoir Production Group for Schlumberger Limited (2006)
Mark J. Scott	60	Vice President—Administration (2010) Senior Vice President of Human Resources for Dresser, Inc. (2004)

No family relationships exist among any of the above-listed officers, and there are no arrangements or understandings between any of the above-listed officers and any other person pursuant to which they serve as an officer. During the past five years, none of the above-listed officers was involved in any legal proceedings as defined in Item 401(f) of Regulation S-K. All officers are elected by the Board of Directors to hold office until their successors are elected and qualified.

ITEM 1A. RISK FACTORS

Important risk factors that could impact our ability to achieve our anticipated operating results and growth plan goals are presented below. The following risk factors should be read in conjunction with discussions of our business and the factors affecting our business located elsewhere in this Annual Report on Form 10-K and in our other filings with the SEC.

Demand for our systems and services depends on oil and gas industry activity and expenditure levels, which are directly affected by trends in the demand for and price of crude oil and natural gas.

We are substantially dependent on conditions in the oil and gas industry, including the level of exploration, development and production activity of, and the corresponding capital spending by, oil and natural gas companies. Any substantial or extended decline in these expenditures may result in the reduced pace of discovery and development of new reserves of oil and gas and the reduced exploitation of existing wells, which could adversely affect demand for our systems and services and, in certain instances, result in the cancellation, modification or rescheduling of existing orders. These factors could have an adverse effect on our revenue and profitability. The level of exploration, development and production activity is directly affected by trends in oil and natural gas prices, which, historically, have been volatile.

Factors affecting the prices of oil and natural gas include, but are not limited to, the following:


•	demand for hydrocarbons, which is affected by worldwide population growth, economic growth rates and general economic and business conditions;


•	costs of exploring for, producing and delivering oil and natural gas;


•	political and economic uncertainty and sociopolitical unrest;


•	available excess production capacity within the Organization of Petroleum Exporting Countries (“OPEC”) and the level of oil production by non-OPEC countries;


•	oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;


•	technological advances affecting energy consumption;


•	potential acceleration of the development of alternative fuels;


•	access to capital and credit markets, which may affect our customers’ activity levels and spending for our products and services; and


•	natural disasters.

The oil and gas industry has historically experienced periodic downturns, which have been characterized by diminished demand for oilfield services and downward pressure on the prices we charge. A significant downturn in the oil and gas industry could result in a reduction in demand for oilfield services and could adversely affect our financial condition, results of operations or cash flows.

The industries in which we operate or have operated expose us to potential liabilities arising out of the installation or use of our systems that could adversely affect our financial condition.

We are subject to equipment defects, malfunctions and failures, equipment misuse and natural disasters, the occurrence of which may result in uncontrollable flows of gas or well fluids, fires and explosions. Although we have obtained insurance against many of these risks, our insurance may not be adequate to cover our liabilities. Further, the insurance may not generally be available in the future or, if available, premiums may not be commercially justifiable. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, our business, results of operations, financial condition or cash flows could be materially adversely affected.

Our operations require us to comply with numerous U.S. and international regulations, violations of which could have a material adverse effect on our financial condition, results of operations or cash flows.

We are exposed to a variety of federal, state, local and international laws and regulations relating to matters such as environmental, health and safety, labor and employment, import/export control, currency exchange, bribery and corruption and taxation. These laws and regulations are complex, frequently change and have tended to become more stringent over time. In the event the scope of these laws and regulations expand in the future, the incremental cost of compliance could adversely impact our financial condition, results of operations or cash flows.

Our operations outside of the United States require us to comply with numerous anti-bribery and anti-corruption regulations under the laws of the United States and various other countries. The U.S. Foreign Corrupt Practices Act (“FCPA”), the United Kingdom (“U.K.”) Bribery Act and the China Anti-Unfair Competition Law, among others, apply to us and our operations. We have internal control policies and procedures and have implemented training and compliance programs for our employees and agents with respect to these regulations. However, our policies, procedures and programs may not always protect us from reckless or criminal acts committed by our employees or agents, and severe criminal or civil sanctions may be imposed as a result of violations of these laws. We are also subject to the risks that our employees, joint venture partners and agents outside of the United States may fail to comply with applicable laws.

Moreover, we import raw materials, semi-finished goods, as well as finished products into many countries for use in such countries 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 involves imports and exports. As a result, compliance with multiple trade sanctions, embargoes and import/export laws and regulations, as well as the recently enacted conflict minerals reporting requirements, pose a constant challenge and risk to us since our business is conducted on a worldwide basis through various subsidiaries. Our failure to comply with these laws and regulations could materially affect our reputation, financial condition and results of operations.

Compliance with environmental laws and regulations may adversely affect our business and operating results.

Environmental laws and regulations affect the equipment, systems and services we design, market and sell, as well as the facilities where we manufacture our equipment and systems. We are required to invest financial and managerial resources to comply with environmental laws and regulations and believe that we will continue to be required to do so in the future. These regulations, as well as the adoption of other laws and regulations affecting exploration and development of drilling for crude oil and natural gas, could adversely affect our business and operating results by increasing our costs, limiting the demand for our systems and services or restricting our operations.

International, national and state governments and agencies are currently evaluating and promulgating legislation and regulations that are focused on restricting emissions commonly referred to as greenhouse gas (“GHG”) emissions. For instance, the U.S. Environmental Protection Agency (“EPA”) has made findings that GHG emissions endanger public health and the environment and, based on these findings, has adopted regulations that restrict GHG emissions under existing provisions of the U.S. Clean Air Act, including one that requires a reduction of GHG emissions from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from certain sources, including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. In addition, the European Emissions Trading Scheme is a program through which many of the European Union member states are implementing cap and trade controls covering numerous power stations and industrial facilities. These developments may curtail production and demand for oil and gas in areas of the world where our customers operate and could adversely affect future demand for our products and services.

Moreover, environmental concerns have been raised regarding the potential impact of hydraulic fracturing or “fracking” on underground water supplies. We provide equipment and services to companies employing this enhanced recovery technique. There have been several regulatory and governmental initiatives in the United States to restrict the hydraulic fracturing process, which could have an adverse impact on our customers’ completion or production activities. The EPA issued rules on April 17, 2012, which become effective in January 2015, designed to limit the release of volatile organic compounds, or pollutants, from natural gas wells that are hydraulically fractured. Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. Hydraulic fracturing restrictions also have been or are being considered for adoption in other countries. Should additional governmental regulations ultimately be imposed that further restrict or curtail hydraulic fracturing activities, the demand for our equipment and services could be impacted, which, in turn, could adversely affect our financial condition, results of operations or cash flows.

Disruptions in the political, regulatory, economic and social conditions of the foreign countries in which we conduct business could adversely affect our business or results of operations.

We operate manufacturing facilities in 16 countries outside of the United States and approximately 73% of our 2013 revenue was generated internationally. Instability and unforeseen changes in the international markets in which we conduct business, including economically and politically volatile areas such as North Africa, West Africa, the Middle East and the Commonwealth of Independent States (“CIS”), could have an adverse effect on the demand for our systems and services, our financial condition or our results of operations. These factors include, but are not limited to, the following:


•	nationalization and expropriation;


•	potentially burdensome taxation;


•	inflationary and recessionary markets, including capital and equity markets;


•	civil unrest, labor issues, political instability, terrorist attacks, cyber-terrorism, military activity and wars;


•	supply disruptions in key oil producing countries;


•	ability of OPEC to set and maintain production levels and pricing;


•	trade restrictions, trade protection measures or price controls;


•	foreign ownership restrictions;


•	import or export licensing requirements;


•	restrictions on operations, trade practices, trade partners and investment decisions resulting from domestic and foreign laws and regulations;


•	changes in, and the administration of, laws and regulations;


•	inability to repatriate income or capital;


•	reductions in the availability of qualified personnel;


•	foreign currency fluctuations or currency restrictions; and


•	fluctuations in the interest rate component of forward foreign currency rates.

Because a significant portion of our revenue is denominated in foreign currencies, changes in exchange rates will produce fluctuations in our revenue, costs and earnings and may also affect the book value of our assets located outside of the United States and the amount of our stockholders’ equity. Although it is our policy to seek to minimize our currency exposure by engaging in hedging transactions where appropriate, our efforts may not be successful. To the extent we sell our products and services in foreign markets, currency fluctuations may result in our products and services becoming too expensive for foreign customers. As a result, fluctuations in foreign currency exchange rates may affect our financial results.

We may lose money on fixed-price contracts.

As is customary for the types of businesses in which we operate, we often agree to provide products and services under fixed-price contracts. Under these contracts, we are typically responsible for cost overruns. Our actual costs and any gross profit realized on these fixed-price contracts may vary from the estimated amounts on which these contracts were originally based. There is inherent risk in the estimation process, including significant unforeseen technical and logistical challenges or longer than expected lead times. A fixed-price contract may prohibit our ability to mitigate the impact of unanticipated increases in raw material prices through increased pricing. Depending on the size of a project, variations from estimated contract performance could have a significant impact on our financial condition, results of operations or cash flows.

Disruptions in the timely delivery of our backlog could affect our future sales, profitability, and our relationships with our customers.

Many of the contracts we enter into with our customers require long manufacturing lead times due to complex technical and logistical requirements. These contracts may contain penalty clauses relating to on-time delivery, and a failure by us to deliver in accordance with customer expectations could subject us to contractual penalties, reduce our margins on these contracts or result in damage to existing customer relationships. 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, subcontractor performance, project engineering expertise, sufficient manufacturing plant capacity and appropriate planning and scheduling of manufacturing resources. Failure to deliver backlog in accordance with expectations could negatively impact our financial performance.

Due to the types of contracts we enter into, the cumulative loss of several major contracts or alliances may have an adverse effect on our results of operations.

We often enter into large, long-term contracts that, collectively, represent a significant portion of our revenue. For example, we have an alliance of this type with Statoil from which we generated approximately 12% of our consolidated revenue in 2013. These agreements, if terminated or breached, may have a larger impact on our operating results or our financial condition than shorter-term contracts due to the value at risk. If we were to lose several key alliances or agreements over a relatively short period of time we could experience a significant adverse impact on our financial condition, results of operations or cash flows.

Increased costs of raw materials and other components may result in increased operating expenses and adversely affect our results of operations or cash flows.

Our results of operations may be adversely affected by our inability to manage the rising costs and availability of raw materials and components used in our wide variety of products and systems. Unexpected changes in the size and timing of regional and/or product markets, particularly for short lead-time products, could affect our results of operations or cash flows.

Moreover, in August 2012, the SEC issued its final rule to implement Section 1502 of the Dodd-Frank Wall Street Reform and Consumer Protection Act regarding mandatory disclosure and reporting requirements by public companies of their use of “conflict minerals” (tantalum, tin, tungsten and gold) originating in the Democratic Republic of Congo and adjoining countries. We are required to conduct specified due diligence activities for the 2013 calendar year and provide our first report in May 2014. The new rule could affect sourcing at competitive prices and availability in sufficient quantities of certain of the conflict minerals used in the manufacture of our products or in the provision of our services. The number of suppliers who provide conflict-free minerals may be limited, which could have a material adverse effect on our ability to purchase these products in the future. The costs of compliance, including those related to supply chain research, the limited number of suppliers and possible changes in the sourcing of these minerals, could have a material adverse effect on our results of operations or cash flows.

Our businesses are dependent on the continuing services of certain of our key managers and employees.

We depend on our senior executive officers and other key personnel. The loss of any of these officers or key management could adversely impact our business if we are unable to implement key strategies or transactions in their absence. In addition, competition for qualified employees among companies, like ours, that rely heavily on engineering and technology is intense. The loss of qualified employees or an inability to attract, retain and motivate additional highly-skilled employees required for the operation and expansion of our business could hinder our ability to conduct research activities successfully and develop marketable products and services.

A failure of our information technology infrastructure could adversely impact our business and results of operations.

The efficient operation of our business is dependent on our information technology (“IT”) systems. Accordingly, we rely upon the capacity, reliability and security of our IT hardware and software infrastructure and our ability to expand and update this infrastructure in response to our changing needs. Despite our implementation of security measures, our systems are vulnerable to damages from computer viruses, natural disasters, incursions by intruders or hackers, failures in hardware or software, power fluctuations, cyber terrorists and other similar disruptions. The failure of our IT systems to perform as anticipated for any reason or any significant breach of security could disrupt our business and result in numerous adverse consequences, including reduced effectiveness and efficiency of operations, inappropriate disclosure of confidential information, increased overhead costs and loss of important information, which could have a material adverse effect on our business and results of operations. In addition, we may be required to incur significant costs to protect against damage caused by these disruptions or security breaches in the future.

Our success depends on our ability to implement new technologies and services.

Our success depends on the ongoing development and implementation of new product designs and improvements and on our ability to protect and maintain critical intellectual property assets related to these developments. If we are not able to obtain patent or other protection of our technology, we may not be able to continue to develop systems, services and technologies to meet evolving industry requirements, and if so, at prices acceptable to our customers.

Some of our competitors are large national and multinational companies that may be able to devote greater financial, technical, manufacturing and marketing resources to the research and development of new systems, services and technologies than we are able to do. If we are unable to compete effectively given these risks, our business, results of operations and financial condition could be adversely affected.

Uninsured claims and litigation against us, including intellectual property litigation, could adversely impact our financial condition, results of operations or cash flows.

We could be impacted by the outcome of pending litigation, as well as unexpected litigation or proceedings. We have insurance coverage against operating hazards, including product liability claims and personal injury claims related to our products, to the extent deemed prudent by our management and to the extent insurance is available. However, no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future claims and litigation. Our financial condition, results of operations or cash flows could be adversely affected by unexpected claims not covered by insurance.

In addition, the tools, techniques, methodologies, programs and components we use to provide our services may infringe upon the intellectual property rights of others. Infringement claims generally result in significant legal and other costs and may distract management from running our core business. Royalty payments under licenses from third parties, if available, would increase our costs. If a license were not available, we might not be able to continue providing a particular service or product, which could adversely affect our financial condition, results of operations or cash flows. Additionally, developing non-infringing technologies would increase our costs.

A downgrade in the rating of our debt could restrict our ability to access the capital markets.

Changes in the ratings assigned to our debt may impact our access to the debt capital markets. If ratings for our debt fall below investment grade, our access to the debt capital markets could become restricted. Moreover, our revolving credit agreement includes an increase in interest rates if the ratings for our debt are downgraded, which could have an adverse effect on our results of operations. An increase in the level of our indebtedness and related interest costs may increase our vulnerability to adverse general economic and industry conditions and may affect our ability to obtain additional financing.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We lease our corporate headquarters in Houston, Texas. We own or lease numerous properties throughout the world and consider our production facilities to be our principal properties. We operate 30 production facilities in 17 countries.

We believe our properties and facilities are suitable for their present and intended purposes and are operating at a level consistent with the requirements of the industry in which we operate. We also believe that our leases are at competitive or market rates and do not anticipate any difficulty in leasing suitable additional space upon expiration of our current lease terms.

The following table shows our significant production properties by reporting segment at December 31, 2013:



Subsea Technologies	Surface Technologies	Energy Infrastructure
United States:
* Houston, Texas	Stephenville, Texas	Tupelo, Mississippi
Davis, California	Oklahoma City, Oklahoma	Erie, Pennsylvania
Shingle Springs, California		Corpus Christi, Texas
Fullerton, California		Lenexa, Kansas

International:
Kongsberg, Norway	+ Sens, France	Ellerbek, Germany
* Rio de Janeiro, Brazil	Collechio, Italy	Changshu, China
* Nusajaya, Malaysia	Maracaibo, Venezuela	Arnhem, The Netherlands
* Singapore	Edmonton, Canada
* Bergen, Norway	Jakarta, Indonesia
* Dunfermline, Scotland
Macaé, Brazil
Takoradi, Ghana
* Stavanger, Norway
Luanda, Angola
* Aberdeen, Scotland
Port Harcourt, Nigeria

*These facilities are production properties in Subsea Technologies and Surface Technologies.

+This facility is a production property in Surface Technologies and Energy Infrastructure.

ITEM 3. LEGAL PROCEEDINGS

We are involved in various pending or potential legal actions in the ordinary course of our business. Management is unable to predict the ultimate outcome of these actions because of the inherent uncertainty of litigation. However, management believes that the most probable, ultimate resolution of these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “FTI.”



	2013								2012
	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Common stock price:
High	$	59.34	$	58.35	$	58.73	$	54.39	$	46.93	$	49.96	$	50.54	$	54.36
Low	$	47.78	$	52.38	$	48.50	$	42.97	$	39.70	$	39.64	$	37.68	$	48.26



Closing stock price at December 31, 2013	$	52.21
Closing stock price at February 19, 2014	$	50.52
Number of common stockholders of record at February 19, 2014	3,044

We have not declared or paid cash dividends in 2013 or 2012, and we do not currently have a plan to pay cash dividends in the future.

On February 25, 2011, our Board of Directors approved a two-for-one stock split of our outstanding shares of common stock. The stock split was completed in the form of a stock dividend that was issued on March 31, 2011, to stockholders of record at the close of business on March 14, 2011. All common share and per share information in our consolidated financial statements have been retroactively revised to reflect the stock split.

As of December 31, 2013, our securities authorized for issuance under equity compensation plans were as follows:



	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans
Equity compensation plans approved by security holders	33,786	(1)	$	5.99	24,066,444	(2)
Equity compensation plans not approved by security holders	—		—		—
Total	33,786	(1)	$	5.99	24,066,444	(2)

______________________________


⁽¹⁾	The table includes the number of shares that may be issued upon the exercise of outstanding options to purchase shares of our common stock under the Amended and Restated FMC Technologies, Inc. Incentive Compensation and Stock Plan (the “Plan”). The table does not include shares of restricted stock that have been awarded under the Plan but which have not yet vested.


⁽²⁾	The table includes shares of our common stock available for future issuance under the Plan, excluding the shares quantified in the first column. This number includes 3,290,852 shares available for issuance for nonvested stock awards that vest after December 31, 2013.

We had no unregistered sales of equity securities during the year ended December 31, 2013.

The following table summarizes repurchases of our common stock during the three months ended December 31, 2013.

Issuer Purchases of Equity Securities



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (b)
October 1, 2013 – October 31, 2013	153,260	$	55.47	134,300	13,637,095
November 1, 2013 – November 30, 2013	164,790	$	49.63	153,300	13,483,795
December 1, 2013 – December 31, 2013	596,191	$	50.79	596,191	12,887,604
Total	914,241	$	51.37	883,791	12,887,604

______________________________

^(a)

Represents 883,791 shares of common stock repurchased and held in treasury and 30,450 shares of common stock purchased and held in an employee benefit trust established for the FMC Technologies, Inc. Non-Qualified Savings and Investment Plan. In addition to these shares purchased on the open market, we sold 14,220 shares of registered common stock held in this trust, as directed by the beneficiaries, during the three months ended December 31, 2013.

^(b)

In 2005, we announced a repurchase plan approved by our Board of Directors authorizing the repurchase of up to two million shares of our issued and outstanding common stock through open market purchases. The Board of Directors authorized extensions of this program, adding five million shares in February 2006 and eight million shares in February 2007 for a total of 15 million shares of common stock authorized for repurchase. As a result of the two-for-one stock splits (i) on August 31, 2007, the authorization was increased to 30 million shares; and (ii) on March 31, 2011, the authorization was increased to 60 million shares. In December 2011, the Board of Directors authorized an extension of our repurchase program, adding 15 million shares, for a total of 75 million shares. In addition to the 75 million shares, in July 2008, the Board of Directors authorized the repurchase of $95.0 million of our outstanding common stock, and as of September 2008, there was no remaining amount available for purchase under the $95.0 million authorization.

ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth selected financial data of the Company for each of the five years in the period ended December 31, 2013. This information should be read in conjunction with Part II, Item 7 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” and the audited consolidated financial statements and notes thereto included in Part II, Item 8 of this Annual Report on Form 10-K.



(In millions, except per share data) Years Ended December 31	2013		2012		2011		2010		2009
Statement of income data:
Total revenue	$	7,126.2	$	6,151.4	$	5,099.0	$	4,125.6	$	4,405.4
Total costs and expenses	$	6,378.6	$	5,546.6	$	4,536.6	$	3,574.0	$	3,875.3
Income from continuing operations	$	506.6	$	434.8	$	403.5	$	378.3	$	362.8
Net income attributable to FMC Technologies, Inc.	$	501.4	$	430.0	$	399.8	$	375.5	$	361.8

Earnings per share from continuing operations attributable to FMC Technologies, Inc.:
Basic earnings per share	$	2.10	$	1.79	$	1.66	$	1.55	$	1.46
Diluted earnings per share	$	2.10	$	1.78	$	1.64	$	1.53	$	1.44

Cash dividends declared	$	—	$	—	$	—	$	—	$	—



(In millions) As of December 31	2013			2012			2011			2010			2009
Balance sheet data:
Total assets	$	6,605.6		$	5,902.9		$	4,271.0		$	3,644.2		$	3,556.4
Net (debt) cash ⁽¹⁾	$	(973.2	)	$	(1,298.7	)	$	(279.6	)	$	(47.8	)	$	40.6
Long-term debt, less current portion	$	1,329.8		$	1,580.4		$	36.0		$	351.1		$	391.6
Total FMC Technologies, Inc. stockholders’ equity	$	2,317.2		$	1,836.9		$	1,424.6		$	1,311.7		$	1,102.8



(In millions) Years Ended December 31	2013		2012		2011		2010		2009
Other financial information:
Capital expenditures	$	314.1	$	405.6	$	274.0	$	112.5	$	110.0
Cash flows provided by operating activities of continuing operations	$	795.4	$	138.4	$	164.8	$	194.8	$	596.6
Segment operating capital employed ⁽²⁾	$	3,610.8	$	3,572.6	$	2,204.2	$	1,722.8	$	1,369.6
Order backlog ⁽³⁾	$	6,998.2	$	5,377.8	$	4,876.4	$	4,171.5	$	2,545.4

______________________________


⁽¹⁾	Net (debt) cash consists of cash and cash equivalents less short-term debt, long-term debt and the current portion of long-term debt. Net (debt) cash is a non-GAAP measure that management uses to evaluate our capital structure and financial leverage. See “Liquidity and Capital Resources” in Part II, Item 7 of this Annual Report on Form 10-K for additional discussion of net (debt) cash.

⁽²⁾

We view segment operating capital employed, which consists of assets, net of liabilities, as the primary measure of segment capital. Segment operating capital employed excludes corporate debt facilities and certain investments, pension liabilities, deferred and currently payable income taxes and last-in, first-out (“LIFO”) inventory adjustments. See additional financial information about segment operating capital employed in Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.


⁽³⁾	Order backlog is calculated as the estimated sales value of unfilled, confirmed customer orders at the reporting date.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Overview

We design, manufacture and service technologically sophisticated systems and products for customers in the energy industry. We have manufacturing operations worldwide, strategically located to facilitate delivery of our products, systems and services to our customers. We report the results of operations in the following segments: Subsea Technologies, Surface Technologies and Energy Infrastructure. Management’s determination of the Company’s reporting segments was made on the basis of our strategic priorities and corresponds to the manner in which our chief operating decision maker reviews and evaluates operating performance to make decisions about resources to be allocated to the segment.

A description of our products and services, as well as annual financial data, for each segment can be found in Part I, Item 1, “Business” and Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. The discussions below include the results of each of our segments for the years ended December 31, 2013, 2012 and 2011.

We focus on economic and industry-specific drivers and key risk factors affecting our business segments as we formulate our strategic plans and make decisions related to allocating capital and human resources. The following discussion provides examples of economic and industry factors and key risks that we consider relevant to our business segments.

The results of our businesses are primarily driven by changes in production spending by oil and gas companies, which largely depend upon current and anticipated future crude oil and natural gas demand, production volumes, and consequently, commodity prices. Our Subsea Technologies business is primarily affected by trends in deepwater oil and natural gas production. Our Surface Technologies business is primarily affected by trends in land-based and shallow water oil and natural gas production, including trends in shale production. We use crude oil and natural gas prices as an indicator of demand. Additionally, we use rig count as an indicator of demand which consequently influences the level of worldwide production activity and spending decisions.

We also focus on key risk factors when determining our overall strategy and making decisions for capital allocation. These factors include risks associated with the global economic outlook, product obsolescence and the competitive environment. We address these risks in our business strategies, which incorporate continuing development of leading edge technologies and cultivating strong customer relationships.

We have developed close working relationships with our customers. Our Subsea Technologies business results reflect our ability to build long-term alliances with oil and natural gas companies that are actively engaged in offshore deepwater development and to provide solutions for their needs in a timely and cost-effective manner. We believe that by working closely with our customers, we enhance our competitive advantage, strengthen our market positions and improve our operating results. Examining our share of subsea tree awards during the year is one of the ways we evaluate our market position.

As we evaluate our operating results, we consider business segment performance indicators like segment revenue, operating profit and capital employed, in addition to the level of inbound orders and order backlog. A significant proportion of our revenue is recognized under the percentage of completion method of accounting. Cash receipts from such arrangements typically occur at milestones achieved under stated contract terms. Consequently, the timing of revenue recognition is not always correlated with the timing of customer payments. We may structure our contracts to receive advance payments that we typically use to fund engineering efforts and inventory purchases. Working capital (excluding cash) and net (debt) cash are therefore key performance indicators of cash flows.

In each of our segments, we serve customers from around the world. During 2013, approximately 73% of our total sales were recognized outside of the United States. We evaluate international markets and pursue opportunities that fit our technological capabilities and strategies. For example, we have targeted opportunities in West Africa, Brazil, the North Sea and the Asia-Pacific region because of the expected offshore drilling potential in those regions.

Business Outlook

Overall, management is optimistic about business activity in 2014 as global economic growth continues to recover. While expectations of future energy demand remain closely tied to economic activity in major world economies, total world consumption of crude oil and liquid fuels is expected to slightly increase in 2014. As a result, we expect crude oil prices to remain at a level that supports strong production activity, especially in subsea markets.

Orders were strong in every quarter in 2013 as operators continued to award subsea projects in all basins throughout the world. Our strong subsea project backlog as of December 31, 2013, combined with increasing demand for subsea services related to production activity, supports our expectations of higher subsea revenue and margin expansion in 2014. However, due to the lower backlog conversion rate associated with multi-year delivery schedule awards, we expect modest subsea revenue growth in 2014 when compared to the growth we have experienced over the last few years. Subsea awards over the last couple of years have filled industry backlogs, and we believe the pricing environment should remain positive in 2014 as oil and gas companies remain committed to developing their deepwater portfolios because of the long-term returns these portfolios generate.

In addition, we continue to focus on subsea processing and subsea services as key growth platforms so that we can expand our role as life-of-field partners with our customers by lowering their costs and improving their recovery. In subsea services and in conjunction with our joint venture with Edison Chouest Offshore LLC, we expect to bring our fourth riserless light well intervention system into the market in the end of 2014. Also, our service facility expansions in Norway and Brazil are expected to allow us to meet the growing customer demand for equipment refurbishment. Overall, we expect market demand to remain strong for our subsea technologies systems and service offerings worldwide despite expectations that total industry tree orders will be lower as Petrobras will not repeat its awards related to its multi-year pre-salt requirements. We continue to seek ways to leverage our capacity investments, our talent, and our overall cost structure to drive improvement in our execution and our financial results.

Regarding our surface technologies portfolio, the slowdown in North American surface activity in the latter half of 2012, resulting from oversupply of equipment and lower natural gas prices, led to curtailed fracturing capacity expansion. This slowdown in North American surface activity continued in 2013. As a result, the slowdown had a negative impact on profits in our fluid control business and fracturing rental assets in our surface wellhead business in 2013 compared to the prior year. We believe the international markets for our surface technologies businesses are expected to remain strong in 2014, while the flat activity in North American markets experienced in 2013 is expected to continue in 2014. Shale markets remains part of our long-term strategy, and we continue to invest in our surface technologies businesses to capitalize on these growth opportunities while taking steps to better integrate our product and service offerings with our customers’ needs.

CONSOLIDATED RESULTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011



	Year Ended December 31,									Change
(In millions, except percentages)	2013			2012			2011			2013 vs. 2012				2012 vs. 2011
Revenue	$	7,126.2		$	6,151.4		$	5,099.0		$	974.8		16%	$	1,052.4		21%
Costs and expenses:
Cost of sales	5,571.4			4,832.9			3,966.2			738.5			15	866.7			22
Selling, general and administrative expense	694.8			596.9			479.9			97.9			16	117.0			24
Research and development expense	112.4			116.8			90.5			(4.4		)	(4)	26.3			29
Total costs and expenses	6,378.6			5,546.6			4,536.6			832.0			15	1,010.0			22
Other income (expense), net	5.3			23.0			(1.4		)	(17.7		)	(77)	24.4			1,743
Net interest expense	(33.7		)	(26.6		)	(8.2		)	(7.1		)	(27)	(18.4		)	(224)
Income before income taxes	719.2			601.2			552.8			118.0			20	48.4			9
Provision for income taxes	212.6			166.4			149.3			46.2			28	17.1			11
Net income	506.6			434.8			403.5			71.8			17	31.3			8
Less: net income attributable to noncontrolling interests	(5.2		)	(4.8		)	(3.7		)	(0.4		)	(8)	(1.1		)	(30)
Net income attributable to FMC Technologies, Inc.	$	501.4		$	430.0		$	399.8		$	71.4		17%	$	30.2		8%

2013 Compared With 2012

Revenue increased by $974.8 million in 2013 compared to the prior year and reflected revenue growth in all reporting segments. Revenue in 2013 included a $136.8 million unfavorable impact of foreign currency translation. Excluding the impact of foreign currency translation, total revenue increased by $1,111.6 million year-over-year. Subsea systems and services had another strong year of order activity in 2013. The impact of the higher backlog coming into 2013, combined with robust market activity, led to increased Subsea Technologies sales year-over-year. Additionally, revenue increased year-over-year as a result of our acquisition of the remaining 55% of Schilling Robotics during the second quarter of 2012. Surface Technologies posted higher revenue in 2013 as a result of our acquisition of our completion service business in the fourth quarter of 2012 and higher conventional wellhead system sales in our surface wellhead business in the Middle East and Europe regions.

Gross profit (revenue less cost of sales) increased as a percentage of sales to 21.8% in 2013 from 21.4% in the prior year. The increase in gross profit as a percentage of sales was primarily due to increased utilization and efficiency of engineering resources in our Western Region subsea business, improved performance in our subsea services business, additional subsea contract value in 2013 related to an Angolan withholding tax adjustment, a larger remeasurement of the Multi Phase Meters contingent earn-out consideration in 2012, increased sales volumes and profitability in our Schilling Robotics business, and foreign exchange gains recognized in 2013, partially offset by charges taken on the ExxonMobil Hibernia Southern Extension project in our subsea business and the slowdown in the North American shale markets, primarily from a lack of capacity expansion, which lowered demand for our well service pumps and flowline products.

Selling, general and administrative (“SG&A”) expense increased by $97.9 million year-over-year, driven by higher bid and proposal expenses, increased sales commissions and additional staffing to support subsea service operations in our subsea systems business, the full year impact of SG&A expense as the result of our acquisition of our completion services business in the fourth quarter of 2012, and increased sales commissions in our surface wellhead business.

Other income (expense), net, reflected a $20.0 million gain related to the fair valuation of our previously held equity interest in Schilling Robotics during 2012 and $1.7 million and $1.4 million of gains related to the remeasurement of foreign currency exposures in 2013 and 2012, respectively. Further discussion of our derivative instruments is incorporated herein by reference from Note 14 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Our provision for income taxes reflected an effective tax rate of 29.8% in 2013. Excluding a charge related to withholding taxes in Angola, our effective tax rate was 26.7% in 2013. In 2012, our effective tax rate was 28.0%. The decrease in our effective tax rate from 2012 to the adjusted rate in 2013 was primarily due to a more favorable mix of earnings. Our effective tax rate can fluctuate depending on our country mix of earnings, since our foreign earnings are generally subject to lower tax rates than in the United States. In certain jurisdictions, primarily Singapore and Malaysia, our tax rate is significantly less than the relevant statutory rate due to tax holidays which are set to expire after 2018 and 2015, respectively. The difference between the effective tax rate and the statutory U.S. federal income tax rate primarily related to differing foreign and state tax rates.

2012 Compared With 2011

Revenue increased by $1,052.4 million in 2012 compared to the prior year and reflected revenue growth in all reporting segments. Revenue in 2012 included a $188.4 million unfavorable impact of foreign currency translation. Excluding the impact of foreign currency translation, total revenue increased by $1,240.8 million year-over-year. Subsea systems and services had another strong year of order activity during 2012. The impact of the higher backlog coming into 2012, combined with robust market activity, led to increased Subsea Technologies sales year-over-year. Additionally, revenue increased year-over-year as a result of our acquisition of the remaining 55% of Schilling Robotics during the second quarter of 2012. Surface Technologies posted higher revenue during 2012 from higher backlog entering the year, which resulted from increased demand for Weco^®/Chiksan^® equipment and well service pumps due to the ongoing strength of the North American oil and gas shale markets in 2011.

Gross profit (revenue less cost of sales) decreased as a percentage of sales to 21.4% in 2012 from 22.2% in the prior year. The decline in gross profit as a percentage of sales was primarily due to the $42.0 million remeasurement of the Multi Phase Meters contingent earn-out consideration in 2012, higher staffing and increased depreciation expense as a result of our expansion of our fluid control business, and certain foreign exchange losses, partially offset by charges taken in 2011 from higher project completion and post-completion costs.

SG&A expense increased by $117.0 million year-over-year, driven by higher bid and proposal expenses, increased sales commissions and additional staffing to support operations.

R&D expense increased by $26.3 million year-over-year as we continued to advance new technologies in Subsea Technologies, including subsea processing capabilities, and related to the development of our permanent magnet motor technologies.

Other income (expense), net, reflected a $20.0 million gain related to the fair valuation of our previously held equity interest in Schilling Robotics during 2012 and $1.4 million and $1.9 million of gains related to the remeasurement of foreign currency exposures in 2012 and 2011, respectively. Further discussion of our derivative instruments is incorporated herein by reference from Note 14 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Our provision for income taxes reflected an effective tax rate of 28.0% in 2012. In 2011, our effective tax rate was 27.2%. Excluding a benefit related to recognizing a retroactive holiday in Singapore in the first quarter of 2011, our effective tax rate was 28.5%. The decrease from this adjusted rate to the effective tax rate in 2012 was primarily due to changes in our international structure during 2012, partially offset by the tax impact of the remeasurement of the Multi Phase Meters contingent earn-out consideration and a less favorable mix of earnings. Our effective tax rate can fluctuate depending on our country mix of earnings, since our foreign earnings are generally subject to lower tax rates than in the United States. In certain jurisdictions, primarily Singapore and Malaysia, our tax rate is significantly less than the relevant statutory rate due to tax holidays which are set to expire after 2018 and 2015, respectively. The difference between the effective tax rate and the statutory U.S. federal income tax rate related primarily to differing foreign and state tax rates.

Operating Results of Business Segments

Segment operating profit is defined as total segment revenue less segment operating expenses. The following items have been excluded in computing segment operating profit: corporate staff expense, interest income and expense associated with corporate debt and investments, income taxes and other revenue and other (expense), net.

The following table summarizes our operating results for the years ended December 31, 2013, 2012 and 2011:



	Year Ended December 31,									Favorable/(Unfavorable)
(In millions, except percentages)	2013			2012			2011			2013 vs. 2012				2012 vs. 2011
Revenue
Subsea Technologies	$	4,726.9		$	4,006.8		$	3,289.5		$	720.1		18%	$	717.3		22%
Surface Technologies	1,806.8			1,598.1			1,310.8			208.7			13	287.3			22
Energy Infrastructure	617.2			574.1			499.0			43.1			8	75.1			15
Other revenue and intercompany eliminations	(24.7		)	(27.6		)	(0.3		)	2.9			*	(27.3		)	*
Total revenue	$	7,126.2		$	6,151.4		$	5,099.0		$	974.8		16%	$	1,052.4		21%
Net income
Segment operating profit:
Subsea Technologies	$	548.2		$	432.2		$	306.0		$	116.0		27%	$	126.2		41%
Surface Technologies	257.2			284.3			250.1			(27.1		)	(10)	34.2			14
Energy Infrastructure	74.3			68.2			63.2			6.1			9	5.0			8
Intercompany eliminations	(0.1		)	—			—			(0.1		)	*	—			*
Total segment operating profit	879.6			784.7			619.3			94.9			12	165.4			27
Corporate items:
Corporate expense	(46.3		)	(41.8		)	(39.4		)	(4.5		)	(11)	(2.4		)	(6)
Other revenue and other (expense), net	(85.6		)	(119.9		)	(22.6		)	34.3			29	(97.3		)	(431)
Net interest expense	(33.7		)	(26.6		)	(8.2		)	(7.1		)	(27)	(18.4		)	(224)
Total corporate items	(165.6		)	(188.3		)	(70.2		)	22.7			12	(118.1		)	(168)
Income before income taxes	714.0			596.4			549.1			117.6			20	47.3			9
Provision for income taxes	212.6			166.4			149.3			(46.2		)	(28)	(17.1		)	(11)
Net income attributable to FMC Technologies, Inc.	$	501.4		$	430.0		$	399.8		$	71.4		17%	$	30.2		8%

* Not meaningful

We report our results of operations in U.S. dollars; however, our earnings are generated in various currencies worldwide. For example, we generate a significant amount of revenue, and incur a significant amount of costs, in Norwegian krone, Brazilian real, Singapore dollar, Malaysian ringgit, British pound, Angolan new kwanza and the euro. The earnings of subsidiaries functioning in their local currencies are translated into U.S. dollars based upon the average exchange rate during the period, in order to provide worldwide consolidated results. While the U.S. dollar results reported reflect the actual economics of the period reported upon, the variances from prior periods include the impact of translating earnings at different rates.

Subsea Technologies

2013 Compared With 2012

Subsea Technologies’ revenue increased $720.1 million in 2013 compared to the prior year. Revenue for 2013 included a $129.1 million unfavorable impact of foreign currency translation. Excluding the impact of foreign currency translation, Subsea Technologies’ revenue increased by $849.2 million during 2013 compared to the prior year. With continued high crude oil prices, oil and gas exploration and production activity increased in 2013 when compared to the prior year, as evidenced by increased spending by oil and gas companies. This led to a stronger market for subsea products and services. We entered the year with a strong backlog and continued to have solid order activity during 2013 from high demand for subsea systems. The year-over-year increase in revenue was attributable to the conversion of backlog, combined with strong order activity in 2013. The revenue increase in 2013 was also due in part to our acquisition of the remaining 55% of Schilling Robotics in the second quarter of 2012.

Subsea Technologies’ operating profit totaled $548.2 million, or 11.6% of revenue, in 2013, compared to the prior-year’s operating profit as a percentage of revenue of 10.8%. The margin improvement was primarily driven by the following:

•

Subsea Systems - 0.9 percentage point increase due to increased utilization and efficiency of engineering resources in our Western Region business, improved results in our subsea service business, additional contract value in 2013 related to an Angolan withholding tax adjustment, lower overall research and development expenses and liquidated damage charges recognized in 2012 in Brazil, partially offset by charges taken on the ExxonMobil Hibernia Southern Extension project; and


•	Schilling Robotics - 0.1 percentage point decrease due to the gain on our previously held equity interest in Schilling Robotics recognized in 2012.

Foreign currency translation unfavorably impacted operating profit in 2013 by $14.6 million compared to the prior year.

2012 Compared With 2011

Subsea Technologies’ revenue increased $717.3 million in 2012 compared to the prior year. Revenue for 2012 included a $159.9 million unfavorable impact of foreign currency translation. Excluding the impact of foreign currency translation, total revenue increased by $877.2 million during 2012 compared to the prior year. With continued high crude oil prices, oil and gas exploration and production activity increased in 2012 when compared to the prior year, as evidenced by increased spending by oil and gas companies. This led to a stronger market for subsea products and services. We entered the year with a strong backlog and continued to have solid order activity during 2012 from high demand for subsea systems. The year-over-year increase in revenue was attributable to the conversion of backlog, combined with strong order activity in 2012. The revenue increase in 2012 was also due in part to our acquisition of the remaining 55% of Schilling Robotics in the second quarter of 2012.

Subsea Technologies’ operating profit totaled $432.2 million, or 10.8% of revenue, in 2012, compared to the prior-year’s operating profit as a percentage of revenue of 9.3%. The margin improvement was primarily driven by the following:


•	Subsea Systems - 1.1 percentage point increase due to the conversion of lower margin backlog and higher project-related and post-completion costs in 2011;


•	Schilling Robotics - 0.2 percentage point increase due to the acquisition of the remaining 55% of Schilling Robotics in the second quarter of 2012; and


•	Multi Phase Meters - 0.3 percentage point increase due to higher margins realized in 2012 from increased recognition and acceptance of our meters in the market.

Foreign currency translation unfavorably impacted operating profit in 2012 by $23.5 million compared to the prior year.

Surface Technologies

2013 Compared With 2012

Surface Technologies’ revenue increased $208.7 million in 2013 compared to the prior year. The revenue increase was driven by the acquisition of our completion service business in the fourth quarter of 2012 and our surface wellhead business in the Middle East and Europe regions due to conventional wellhead system sales. These increases were partially offset by a decrease in revenue in our fluid control business resulting from the slowdown of the North American shale markets which have decreased demand for our well service pumps and flowline products. Foreign currency translation unfavorably impacted revenue by $11.9 million in 2013 compared to the prior year.

Surface Technologies’ operating profit totaled $257.2 million, or 14.2% of revenue, in 2013, compared to the prior-year’s operating profit as a percentage of revenue of 17.8%. The margin decline was primarily driven by the following:


•	Fluid Control - 2.2 percentage point decrease due to the slowdown in the North American shale markets, primarily from a lack of capacity expansion, which lowered demand for our well service pumps and flowline products;


•	Completion Services - 1.8 percentage point decrease due to the inclusion of our completion service business and lower activity in the Canadian market which impacted results; and


•	Surface Wellhead - 0.5 percentage point increase due to strong sales of conventional wellhead systems in the Middle East and Europe.

2012 Compared With 2011

Surface Technologies’ revenue increased $287.3 million in 2012 compared to the prior year. The revenue increase was driven by strong demand for Weco^®/Chiksan^® equipment coupled with an increased demand for well service pumps in our fluid control business due to the strength in North American oil and gas shale activity in the first half of 2012. Surface wellhead also experienced revenue growth year-over-year primarily due to conventional wellhead system sales and increased services related to hydraulic fracturing activity in North America and strong market growth in the Middle East. In addition, revenue increased year-over-year due to the acquisition of our completion services business in the fourth quarter of 2012.

Surface Technologies’ operating profit totaled $284.3 million, or 17.8% of revenue, in 2012, compared to the prior-year’s operating profit as a percentage of revenue of 19.1%. The margin decline was primarily driven by the following:


•	Fluid Control - 1.0 percentage point decrease due to higher staffing and increased depreciation expense as a result of business expansion;


•	Completion Services - 0.5 percentage point decrease due to the inclusion of our completion service business and lower activity in the Canadian market which impacted results; and


•	Surface Wellhead - 0.3 percentage point increase due to strong sales of conventional wellhead systems in the Middle East, partially offset by higher warranty costs in Europe.

Energy Infrastructure

2013 Compared With 2012

Energy Infrastructure’s revenue increased $43.1 million in 2013 compared to the prior year. The increase in revenue was led by our measurement solutions business due to the strength of North American oil and gas custody and control activity and progress on a loading systems project with Technip for Shell’s Prelude development. Foreign currency translation favorably impacted revenue by $4.2 million in 2013 compared to the prior year.

Energy Infrastructure’s operating profit totaled $74.3 million, or 12.0% of revenue, in 2013, compared to the prior-year’s operating profit as a percentage of revenue of 11.9%. The margin improvement was primarily driven by the following:


•	Separation Systems - 0.6 percentage point increase due to higher sales volumes and cost reduction efforts in SG&A; and


•	Measurement Solutions - 0.7 percentage point decrease due to higher overhead costs related to growth initiatives.

2012 Compared With 2011

Energy Infrastructure’s revenue increased $75.1 million in 2012 compared to the prior year. The increase in revenue was led by our measurement solutions business due to the strength of North American oil and gas custody and control activity, the acquisition of our automation and control business in the second quarter of 2012, and increased sales volumes in our material handling business. Foreign currency translation unfavorably impacted revenue by $15.8 million in 2012 compared to the prior year.

Energy Infrastructure’s operating profit totaled $68.2 million, or 11.9% of revenue, in 2012, compared to the prior-year’s operating profit as a percentage of revenue of 12.7%. The margin decline was primarily driven by the following:


•	Separation Systems - 0.7 percentage point decrease due to higher margin projects in 2011;


•	Loading Systems - 0.7 percentage point decrease due to inventory write-offs recorded in 2012; and


•	Material Handling - 0.7 percentage point increase due to improved margins realized from project completions.

Corporate Items

2013 Compared With 2012

Our corporate items reduced earnings by $165.6 million in 2013, compared to $188.3 million in 2012. The year-over-year decrease primarily reflected the following:


•	favorable variance in foreign currency of $21.5 million;


•	favorable variance related to the remeasurement of the Multi Phase Meters contingent earn-out consideration of $13.2 million;


•	unfavorable variance related to stock-based compensation expense, primarily from the accelerated vesting of awards for retirement eligible grantees, of $13.6 million; and an


•	unfavorable variance related to higher interest expense of $7.1 million.

2012 Compared With 2011

Our corporate items reduced earnings by $188.3 million in 2012, compared to $70.2 million in 2011. The year-over-year increase primarily reflected the following:


•	unfavorable variance in foreign currency of $29.4 million;


•	unfavorable variance related to the remeasurement of the Multi Phase Meters contingent earn-out consideration of $42.0 million;


•	unfavorable variance associated with higher pension expense of $17.4 million, including $8.6 million related to the curtailment of our Norwegian defined benefit plan; and an


•	unfavorable variance related to higher interest expense of $18.4 million.

Inbound Orders and Order Backlog

Inbound orders represent the estimated sales value of confirmed customer orders received during the reporting period.



	Inbound Orders Year Ended December 31,
(In millions)	2013			2012
Subsea Technologies	$	6,510.3		$	4,567.2
Surface Technologies	2,049.1			1,519.5
Energy Infrastructure	605.7			648.1
Intercompany eliminations and other	(44.4		)	(12.9		)
Total inbound orders	$	9,120.7		$	6,721.9

Order backlog is calculated as the estimated sales value of unfilled, confirmed customer orders at the reporting date. Translation negatively affected backlog by $374.1 million and $69.1 million for the years ended December 31, 2013 and 2012, respectively.



	Order Backlog December 31,
(In millions)	2013			2012
Subsea Technologies	$	5,988.8		$	4,580.3
Surface Technologies	742.4			500.8
Energy Infrastructure	288.4			297.7
Intercompany eliminations	(21.4		)	(1.0		)
Total order backlog	$	6,998.2		$	5,377.8

Order backlog for Subsea Technologies at December 31, 2013, increased by $1,408.5 million compared to December 31, 2012, reflecting strong inbound of subsea projects in 2013. Subsea Technologies backlog of $6.0 billion at December 31, 2013, was composed of various subsea projects, including BP’s Mad Dog Phase 2; Chevron’s Wheatstone; CNR International’s Baobab Field Phase 3; ExxonMobil’s Hibernia Southern Extension and Julia; Petrobras’ tree frame agreement, Congro & Corvina, and pre-salt tree and manifold awards; Shell’s Prelude, BC-10 Phase 3 and Stones; Statoil’s Statfjord Workover System, Gullfaks South, Tyrihans, Smorbukk South Extension, Oseberg Delta, Gullfaks Rimfaksdalen and Snorre B Platform Workover System; Total’s Egina; and Tullow Ghana’s TEN. We expect to convert approximately 45% to 55% of December 31, 2013 backlog into revenue during 2014.

Order backlog for Surface Technologies at December 31, 2013, increased by $241.6 million compared to December 31, 2012. The increase was due to strong inbound orders in our Middle East and Europe surface wellhead businesses.

Order backlog for Energy Infrastructure at December 31, 2013, decreased by $9.3 million compared to December 31, 2012. The decrease in backlog was primarily due to our loading systems and automation and control businesses, partially offset by an increase in backlog in our measurement solutions and separation systems businesses.

Liquidity and Capital Resources

Substantially all of our cash balances are held outside the United States and are generally used to meet the liquidity needs of our non-U.S. operations. Most of our cash held outside the United States could be repatriated to the United States, but under current law, any such repatriation would be subject to U.S. federal income tax, as adjusted for applicable foreign tax credits. We have provided for U.S. federal income taxes on undistributed foreign earnings where we have determined that such earnings are not indefinitely reinvested.

We expect to meet the continuing funding requirements of our U.S. operations with cash generated by such U.S. operations, cash from earnings generated by non-U.S. operations that are not indefinitely reinvested and our existing credit facility. If cash held by non-U.S. operations is required for funding operations in the United States, and if U.S. tax has not previously been provided on the earnings of such operations, we would make a provision for additional U.S. tax in connection with repatriating this cash, which may be material to our cash flows and results of operations.

Net debt, or net cash, is a non-GAAP measure reflecting cash and cash equivalents, net of debt. Management uses this non-GAAP measure to evaluate our capital structure and financial leverage. We believe net debt, or net cash, is a meaningful measure that will assist investors in understanding our results and recognizing underlying trends. Net (debt) cash should not be considered as an alternative to, or more meaningful than, cash and cash equivalents as determined in accordance with GAAP or as an indicator of our operating performance or liquidity.

The following is a reconciliation of our cash and cash equivalents to net (debt) cash for the periods presented.



(In millions)	December 31, 2013			December 31, 2012
Cash and cash equivalents	$	399.1		$	342.1
Short-term debt and current portion of long-term debt	(42.5		)	(60.4		)
Long-term debt, less current portion	(1,329.8		)	(1,580.4		)
Net debt	$	(973.2	)	$	(1,298.7	)

The change in our net debt position was primarily due to cash generated from operating activities from higher income and significant improvements in our working capital position, partially offset by payments for capital expenditures and a reduction in our commercial paper position.

Cash flows for each of the years in the three-year period ended December 31, 2013, were as follows:



	Year Ended December 31,
(In millions)	2013			2012			2011
Cash provided by operating activities	$	795.4		$	138.4		$	164.8
Cash required by investing activities	(311.6		)	(1,019.9		)	(273.7		)
Cash provided (required) by financing activities	(422.3		)	881.4			141.0
Effect of exchange rate changes on cash and cash equivalents	(4.5		)	(1.8		)	(3.6		)
Increase (decrease) in cash and cash equivalents	$	57.0		$	(1.9	)	$	28.5

Operating Cash Flows

During 2013, we generated $795.4 million in cash flows from operating activities, which represented a $657.0 million increase compared to the prior year. Our cash flows from operating activities in 2012 were $26.4 million lower than 2011. The year-over-year increase in 2013 was due to a betterment in our working capital position driven by our portfolio of projects and higher income during the year. The improvement in our working capital position was primarily the result of significant advance payments and progress billings on projects in 2013 compared to the prior year. The year-over-year decrease in 2012 was due to an increase in our working capital driven by our portfolio of projects, partially offset by higher income during the year. Our working capital balances can vary significantly depending on the payment terms and timing on key contracts.

Investing Cash Flows

Our cash requirements for investing activities in 2013 were $311.6 million, primarily reflecting cash required by our capital expenditure program of $314.1 million during 2013 related to continued investments in capacity expansion and service asset investments primarily in our Subsea Technologies segment.

Our cash requirements for investing activities in 2012 were $1,019.9 million, primarily reflecting cash required by our acquisitions of the remaining 55% of Schilling Robotics, 100% of Pure Energy and 100% of CSI which amounted to $615.5 million, net of cash acquired. Additionally, our capital expenditure program required cash of $405.6 million during 2012 related to continued investments in capacity expansion, tooling, rental tools and equipment upgrades.

Financing Cash Flows

Cash required by financing activities was $422.3 million in 2013. The decrease in cash provided from financing activities from the prior year was driven by the public offering of $800.0 million aggregate principal amount of our senior notes to fund capital expenditures, acquisitions and working capital needs in 2012 and a net decrease in our commercial paper position in 2013 compared to a net increase in commercial paper in 2012.

Cash provided by financing activities was $881.4 million in 2012. The increase in cash from financing activities from the prior year was driven by the public offering of $800.0 million aggregate principal amount of our senior notes and the issuance of commercial paper to fund capital expenditures, acquisitions and working capital needs, partially offset by $91.1 million in common stock repurchases under our share repurchase authorization program and the repayment of indebtedness under our revolving credit facility.

Debt and Liquidity

Total borrowings at December 31, 2013 and 2012, comprised the following:



	December 31,
(In millions)	2013		2012
Revolving credit facility	$	—	$	100.0
Commercial paper	501.4		669.8
2.00% Notes due 2017	299.5		299.3
3.45% Notes due 2022	499.6		499.6
Term loan	25.9		26.8
Uncommitted credit facilities	31.9		22.1
Property financing	13.9		16.7
Total borrowings	$	1,372.2	$	1,634.3

Credit Facility - On March 26, 2012, we entered into a new $1.5 billion revolving credit agreement (“credit agreement”) with JPMorgan Chase Bank, N.A., as Administrative Agent. The credit agreement is a five-year, revolving credit facility expiring in March 2017. Subject to certain conditions, at our request and with the approval of the Administrative Agent, the aggregate commitments under the credit agreement may be increased by an additional $500.0 million.

Borrowings under the credit agreement bear interest at a base rate or the London interbank offered rate (“LIBOR”), at our option, plus an applicable margin. Depending on our total leverage ratio, the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 1.125% to 1.750% and (ii) in the case of base rate loans, from 0.125% to 0.750%. The base rate is the highest of (1) the prime rate announced by JPMorgan Chase Bank, N.A., (2) the Federal Funds Rate plus 0.5% or (3) one-month LIBOR plus 1.0%.

In connection with the new credit agreement, we terminated and repaid all outstanding amounts under our previously existing $600.0 million five-year revolving credit agreement and our $350.0 million three-year revolving credit agreement.

The following is a summary of our credit facility at December 31, 2013:



(In millions) Description	Amount		Debt Outstanding		Commercial Paper Outstanding (a)		Letters of Credit		Unused Capacity		Maturity
Five-year revolving credit facility	$	1,500.0	$	—	$	501.4	$	6.0	$	992.6	March 2017

______________________________


^(a)	Under our commercial paper program, we have the ability to access up to $1.0 billion of financing through our commercial paper dealers. Our available capacity under our revolving credit facility is reduced by any outstanding commercial paper.

Committed credit available under our revolving credit facility provides the ability to issue our commercial paper obligations on a long-term basis. We had $501.4 million of commercial paper issued under our facility at December 31, 2013. As we had both the ability and intent to refinance these obligations on a long-term basis, our commercial paper borrowings were classified as long-term in the accompanying consolidated balance sheet at December 31, 2013.

Among other restrictions, the terms of the credit agreement include negative covenants related to liens and a financial covenant related to the debt-to-earnings ratio. As of December 31, 2013, we were in compliance with all restrictive covenants under our revolving credit facility.

Senior Notes - On September 21, 2012, we completed the public offering of $300.0 million aggregate principal amount of 2.00% senior notes due October 2017 and $500.0 million aggregate principal amount of 3.45% senior notes due October 2022 (collectively, the “Senior Notes”). Interest on the Senior Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning April 1, 2013. Net proceeds from the offering of $793.8 million were used for the repayment of outstanding commercial paper and indebtedness under our revolving credit facility. Additional information about the Senior Notes is incorporated herein by reference from Note 9 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Outlook for 2014

Historically, we have generated our capital resources primarily through operations and, when needed, through our credit facility. The volatility in credit, equity and commodity markets creates some uncertainty for our businesses. However, management believes, based on our current financial condition, existing backlog levels and current expectations for future market conditions, that we will continue to meet our short- and long-term liquidity needs with a combination of cash on hand, cash generated from operations and access to capital markets. We expect to continue to reach payment milestones on many of our projects which will continue to improve our cash flow position. In 2014, we expect an estimated cash outlay from operations of $70.1 million related to the final payment of the Multi Phase Meters earn-out consideration obligation.

We project spending approximately $400.0 million in 2014 for capital expenditures, largely towards our subsea expansion and related growth of our subsea service offerings. We expect to make contributions of approximately $9.0 million and $21.0 million to our U.S. Non-Qualified Defined Benefit Pension Plan and international pension plans, respectively during 2014. Actual contribution amounts are dependent upon plan investment returns, changes in pension obligations, regulatory environments and other economic factors. We update our pension estimates annually or more frequently upon the occurrence of significant events. Further, we expect to continue our stock repurchases authorized by our Board of Directors, with the timing and amounts of these repurchases dependent upon market conditions and liquidity.

We have $992.6 million in capacity available under our revolving credit facility that we expect to utilize if working capital needs temporarily increase in response to market demand. We continue to evaluate acquisitions, divestitures and joint ventures that meet our strategic priorities. Our intent is to maintain a level of financing sufficient to meet these objectives.

Contractual Obligations

The following is a summary of our contractual obligations at December 31, 2013:



	Payments Due by Period
(In millions) Contractual obligations	Total payments		Less than 1 year		1-3 years		3 -5 years		After 5 years
Long-term debt ^(a)	$	1,340.3	$	10.5	$	29.1	$	801.1	$	499.6
Short-term debt	32.0		32.0		—		—		—
Interest on long-term debt ^(a)	179.3		23.3		46.5		40.5		69.0
Operating leases	599.0		113.4		177.8		121.5		186.3
Purchase obligations ^(b)	1,732.4		1,604.5		127.4		0.3		0.2
Multi Phase Meters earn-out consideration obligation	70.1		70.1		—		—		—
Pension and other post-retirement benefits ^(c)	21.0		21.0		—		—		—
Unrecognized tax benefits ^(d)	41.6		41.6		—		—		—
Total contractual obligations	$	4,015.7	$	1,916.4	$	380.8	$	963.4	$	755.1

______________________________

^(a)

Our available long-term debt is dependent upon our compliance with covenants, including negative covenants related to liens, and a financial covenant related to the debt-to-earnings ratio. Any violation of covenants or other events of default, which are not waived or cured, or changes in our credit rating could have a material impact on our ability to maintain our committed financing arrangements.

Only interest on our Senior Notes is included in the table. During 2013, we paid $27.1 million for interest charges, net of interest capitalized.

^(b)

In the normal course of business, we enter into agreements with our suppliers to purchase raw materials or services. These agreements include a requirement that our supplier provide products or services to our specifications and require us to make a firm purchase commitment to our supplier. As substantially all of these commitments are associated with purchases made to fulfill our customers’ orders, the costs associated with these agreements will ultimately be reflected in cost of sales on our consolidated statements of income.


^(c)	We expect to contribute approximately $21.0 million and $9.0 million to our international pension plans, representing primarily the U.K. and Norway qualified pension plans, and our U.S. Non-Qualified Defined Benefit Pension Plan, respectively, in 2014. Required contributions for future years depend on factors that cannot be determined at this time.

^(d)

It is reasonably possible that $41.6 million of liabilities for unrecognized tax benefits will be settled during 2014, and this amount is reflected in income taxes payable in our consolidated balance sheet as of December 31, 2013. Due to the high degree of uncertainty regarding the timing of potential future cash flows associated with remaining liabilities for unrecognized tax benefits, we are unable to make a reasonable estimate of the period in which such liabilities might be paid. Although unrecognized tax benefits are not contractual obligations, they are presented in this table because they represent demands on our liquidity.

Other Off-Balance Sheet Arrangements

The following is a summary of other off-balance sheet arrangements at December 31, 2013:



	Amount of Commitment Expiration per Period
(In millions) Other off-balance sheet arrangements	Total amount		Less than 1 year		1-3 years		3-5 years		After 5 years
Letters of credit and bank guarantees	$	819.0	$	342.4	$	224.7	$	142.6	$	109.3
Surety bonds	27.8		0.6		—		—		27.2
Total other off-balance sheet arrangements	$	846.8	$	343.0	$	224.7	$	142.6	$	136.5

As collateral for our performance on certain sales contracts or as part of our agreements with insurance companies, we are liable under letters of credit, surety bonds and other bank guarantees. In order to obtain these financial instruments, we pay fees to various financial institutions in amounts competitively determined in the marketplace. Our ability to generate revenue from certain contracts is dependent upon our ability to obtain these off-balance sheet financial instruments. These off-balance sheet financial instruments may be renewed, revised or released based on changes in the underlying commitment. Historically, our commercial commitments have not been drawn upon to a material extent; consequently, management believes it is not likely there will be claims against these commitments that will have a negative impact on our key financial ratios or our ability to obtain financing.

Critical Accounting Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the periods presented. Management has reviewed these critical accounting estimates with the Audit Committee of our Board of Directors. We believe the following critical accounting estimates used in preparing our financial statements address all important accounting areas where the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. See Note 1 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for a description of our significant accounting policies.

Percentage of Completion Method of Accounting

We recognize revenue on construction-type manufacturing projects using the percentage of completion method, where revenue is recognized as work progresses on each contract. There are several acceptable methods under U.S. generally accepted accounting principles of measuring progress toward completion. Most frequently, we use the ratio of costs incurred to date to total estimated contract costs at completion to measure progress toward completion.

We execute contracts with our customers that clearly describe the equipment, systems and/or services that we will provide and the amount of consideration we will receive. After analyzing the drawings and specifications of the contract requirements, our project engineers estimate total contract costs based on their experience with similar projects and then adjust these estimates for specific risks associated with each project, such as technical risks associated with a new design. Costs associated with specific risks are estimated by assessing the probability that conditions will arise that will affect our total cost to complete the project. After work on a project begins, assumptions that form the basis for our calculation of total project cost are examined on a regular basis and our estimates are updated to reflect the most current information and management’s best judgment.

Revenue recognized using the percentage of completion method was approximately 55%, 51% and 54% for the years ended December 31, 2013, 2012 and 2011, respectively. A significant portion of our total revenue recognized under the percentage of completion method relates to our Subsea Technologies segment, primarily for subsea exploration and production equipment projects that involve the design, engineering, manufacturing and assembly of complex, customer-specific systems. The systems are not entirely built from standard bills of material and typically require extended periods of time to design and construct.

Total estimated contract cost affects both the revenue recognized in a period as well as the reported profit or loss on a project. The determination of profit or loss on a contract requires consideration of contract revenue, change orders and claims, less costs incurred to date and estimated costs to complete. Anticipated losses on contracts are recognized in full in the period in which they are identified. Profits are recognized based on the estimated project profit multiplied by the percentage complete.

The total estimated contract cost in percentage of completion accounting is a critical accounting estimate because it can materially affect revenue and profit and requires us to make judgments about matters that are uncertain. There are many factors, including, but not limited to, the ability to properly execute the engineering and designing phases consistent with our customers’ expectations, the availability and costs of labor and resources, productivity and weather, that can affect the accuracy of our cost estimates, and ultimately, our future profitability. In the past, we have realized both lower and higher than expected margins and have incurred losses as a result of unforeseen changes in our project costs; however, historically, our estimates have been reasonably dependable regarding the recognition of revenue and profit on percentage of completion contracts. Total adjustments (representing the difference between estimated and actual results) for all contracts resulted in net increases to operating profit of 0.1% and 0.7% as a percentage of total beginning contract value for the years ended December 31, 2013 and 2012, respectively.

The amount of revenue recognized using the percentage of completion method is sensitive to changes in our estimates of total contract costs. For each contract in progress at December 31, 2013, a 1% increase or decrease in the estimated margin earned on each contract would have increased or decreased total revenue and pre-tax income by $37.0 million for the year ended December 31, 2013.

Inventory Valuation

Inventory is recorded at the lower of cost or net realizable value. In order to determine net realizable value, we evaluate each component of inventory on a regular basis to determine whether it is excess or obsolete. We record the decline in the carrying value of estimated excess or obsolete inventory as a reduction of inventory and as an expense included in cost of sales in the period in which it is identified. Our estimate of excess and obsolete inventory is a critical accounting estimate because it is highly susceptible to change from period to period. In addition, the estimate requires management to make judgments about the future demand for inventory.

In order to quantify excess or obsolete inventory, we begin by preparing a candidate listing of the components of inventory that have a quantity on hand in excess of usage within the most recent two-year period. The list is reviewed with sales, engineering, production and materials management personnel to determine whether the list of potential excess or obsolete inventory items is accurate. As part of this evaluation, management considers whether there has been a change in the market for finished goods, whether there will be future demand for on-hand inventory items and whether there are components of inventory that incorporate obsolete technology. Finally, an assessment is made of our historical usage of inventory previously written off as excess or obsolete, and a further adjustment to the estimate is made based on this historical experience. As a result, our estimate of excess or obsolete inventory is sensitive to changes in assumptions about future usage of inventory. See Note 5 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to inventory valuation adjustments.

Impairment of Long-Lived and Intangible Assets

Long-lived assets, including property, plant and equipment, identifiable intangible assets being amortized and capitalized software costs are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of the long-lived asset may not be recoverable. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If it is determined that an impairment loss has occurred, the loss is measured as the amount by which the carrying amount of the long-lived asset exceeds its fair value. The determination of future cash flows as well as the estimated fair value of long-lived assets involves significant estimates on the part of management. Because there usually is a lack of quoted market prices for long-lived assets, fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible.

Impairment of Goodwill

Goodwill is not subject to amortization but is tested for impairment on an annual basis, or more frequently if impairment indicators arise. We have established October 31 as the date of our annual test for impairment of goodwill. Reporting units with goodwill are tested for impairment by first assessing qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If after assessing the totality of events or circumstances, or based on management’s judgment, we determine it is more likely than not that the fair value of a reporting unit is less than its carrying amount, a two-step quantitative impairment test is performed.

When using the two-step quantitative impairment test, determining the fair value of a reporting unit is judgmental in nature and involves the use of significant estimates and assumptions. These estimates and assumptions include revenue growth rates and operating margins used to calculate projected future cash flows, discount rates believed to be consistent with those used by principal market participants and future economic and market conditions. Our estimates are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable and do not reflect unanticipated events and circumstances that may occur.

A lower fair-value estimate in the future for any of our reporting units could result in goodwill impairments. Factors that could trigger a lower fair-value estimate include sustained price declines, cost increases, regulatory or political environment changes, and other changes in market conditions, such as decreased prices in market-based transactions for similar assets. We have not recognized any goodwill impairment for the years ended December 31, 2013 or 2012, as the fair values of our reporting units with goodwill balances exceeded their carrying amounts. In addition, there were no negative conditions, or triggering events, that occurred in 2013 or 2012 requiring us to perform additional impairment reviews.

Accounting for Income Taxes

Our income tax expense, deferred tax assets and liabilities, and reserves for uncertain tax positions reflect management’s best assessment of estimated future taxes to be paid. We are subject to income taxes in the United States and numerous foreign jurisdictions. Significant judgments and estimates are required in determining our consolidated income tax expense.

In determining our current income tax provision, we assess temporary differences resulting from differing treatments of items for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are recorded in our consolidated balance sheets. When we maintain deferred tax assets, we must assess the likelihood that these assets will be recovered through adjustments to future taxable income. To the extent we believe recovery is not likely, we establish a valuation allowance. We record an allowance reducing the asset to a value we believe will be recoverable based on our expectation of future taxable income. We believe the accounting estimate related to the valuation allowance is a critical accounting estimate because it is highly susceptible to change from period to period. It requires management to make assumptions about our future income over the lives of the deferred tax assets, and the impact of increasing or decreasing the valuation allowance is potentially material to our results of operations.

Forecasting future income requires us to use a significant amount of judgment. In estimating future income, we use our internal operating budgets and long-range planning projections. We develop our budgets and long-range projections based on recent results, trends, economic and industry forecasts influencing our segments’ performance, our backlog, planned timing of new product launches and customer sales commitments. Significant changes in the expected realizability of a deferred tax asset would require that we adjust the valuation allowance applied against the gross value of our total deferred tax assets, resulting in a change to net income.

As of December 31, 2013, we believe that it is not more likely than not that we will generate future taxable income in certain foreign jurisdictions in which we have cumulative net operating losses and, therefore, we have provided a valuation allowance against the related deferred tax assets. As of December 31, 2013, we believe that it is more likely than not that we will have future taxable income in the United States to utilize our domestic deferred tax assets. Therefore, we have not provided a valuation allowance against any domestic deferred tax assets.

The need for a valuation allowance is sensitive to changes in our estimate of future taxable income. If our estimate of future taxable income was 25% lower than the estimate used, we would still generate sufficient taxable income to utilize such domestic deferred tax assets.

The calculation of our income tax expense involves dealing with uncertainties in the application of complex tax laws and regulations in numerous jurisdictions in which we operate. We recognize tax benefits related to uncertain tax positions when, in our judgment, it is more likely than not that such positions will be sustained on examination, including resolutions of any related appeals or litigation, based on the technical merits. We adjust our liabilities for uncertain tax positions when our judgment changes as a result of new information previously unavailable. Due to the complexity of some of these uncertainties, their ultimate resolution may result in payments that are materially different from our current estimates. Any such differences will be reflected as adjustments to income tax expense in the periods in which they are determined.

Accounting for Pensions

Our pension and other post-retirement (health care and life insurance) obligations are described in Note 11 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. In order to measure the expense and obligations associated with our pension benefits, management must make a variety of estimates, including discount rates used to value certain liabilities, expected return on plan assets set aside to fund these costs, rate of compensation increase, employee turnover rates, retirement rates, mortality rates and other factors. We update these estimates on an annual basis or more frequently upon the occurrence of significant events. These accounting estimates bear the risk of change due to the uncertainty associated with each estimate, as well as the fact that these estimates are difficult to measure. Different estimates used by management could result in our recognizing different amounts of expense over different periods of time.

Due to the specialized and statistical nature of these calculations which attempt to anticipate future events, we engage third-party specialists to assist management in evaluating our assumptions as well as appropriately measuring the costs and obligations associated with these pension benefits. The discount rate and expected return on plan assets are primarily based on investment yields available and the historical performance of our plan assets. These elements are critical accounting estimates because they are subject to management’s judgment and can materially affect net income.

The discount rate used affects the interest cost component of net periodic pension cost. The discount rate is based on rates at which the pension benefit obligation could be effectively settled on a present value basis. Discount rates are derived by identifying a theoretical settlement portfolio of long-term, high quality (“AA” rated) corporate bonds at our determination date that is sufficient to provide for the projected pension benefit payments. A single discount rate is determined that results in a discounted value of the pension benefit payments that equate to the market value of the selected bonds. The resulting discount rate is reflective of both the current interest rate environment and the pension’s distinct liability characteristics. Significant changes in the discount rate, such as those caused by changes in the yield curve, the mix of bonds available in the market, the duration of selected bonds and the timing of expected benefit payments, may result in volatility in our pension expense and pension liabilities. The weighted average discount rate used to compute net periodic benefit cost decreased to 3.90% in 2013 from 4.60% in 2012 for U.S. plans and 4.46% in 2013 from 4.54% in 2012 for international plans.

Our pension expense is sensitive to changes in our estimate of the discount rate. Holding other assumptions constant, a 50 basis point reduction in the discount rate would increase annual pension expense by approximately $8.1 million before taxes. Holding other assumptions constant, a 50 basis point increase in the discount rate would decrease annual pension expense by approximately $7.3 million before taxes.

Net periodic pension cost includes an underlying expected long-term rate of return on plan assets. Our estimate of the expected rate of return on plan assets is primarily based on the historical performance of plan assets, current market conditions, our asset allocation and long-term growth expectations. We assumed a weighted average expected rate of return for our pension plans of 9.00% in 2013 and 2012 for our U.S. plans and 7.44% in 2013 and 7.62% in 2012 for our international plans. The expected return on plan assets is recognized as part of the net periodic pension cost. The difference between the expected return and the actual return on plan assets is amortized over the expected remaining service life of employees, resulting in a lag time between the market’s performance and its impact on plan results.

Our pension expense is sensitive to changes in our estimate of the expected rate of return on plan assets. Holding other assumptions constant, a 50 basis points increase or decrease in the expected rate of return on plan assets would decrease or increase annual pension expense by approximately $3.9 million before taxes, respectively.

The actuarial assumptions and estimates made by management in determining our pension benefit obligations may differ materially from actual results as a result of changing market and economic conditions and changes in plan participants assumptions. While we believe the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations.

Determination of Fair Value in Business Combinations

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets acquired and liabilities assumed at their respective fair values. The determination of fair value requires the use of significant estimates and assumptions, and in making these determinations, management uses all available information. We have up to one year after the acquisition closing date to finalize these fair value determinations. For tangible and identifiable intangible assets acquired in a business combination, the determination of fair value utilizes several valuation methodologies including discounted cash flows which has assumptions with respect to the timing and amount of future revenue and expenses associated with an asset. The assumptions made in performing these valuations include, but are not limited to, discount rates, future revenues and operating costs, projections of capital costs, and other assumptions believed to be consistent with those used by principal market participants. Due to the specialized nature of these calculations, we engage third-party specialists to assist management in evaluating our assumptions as well as appropriately measuring the fair value of assets acquired and liabilities assumed. Any significant change in key assumptions may cause the acquisition accounting to be revised. Business combinations are described in Note 4 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Recently Issued Accounting Standards

In July 2013, the FASB issued Accounting Standards Update No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” This update requires the netting of unrecognized tax benefits against a deferred tax asset for a loss or other carryforward that would apply in settlement of the uncertain tax positions. Under the amended guidance, unrecognized tax benefits will be netted against all available same-jurisdiction loss or other tax carryforwards that would be utilized, rather than only against carryforwards that are created by the unrecognized tax benefits. The updated guidance will be applied prospectively, effective January 1, 2014. We believe the adoption of this guidance concerns disclosure only and will not have an impact on our consolidated financial position or results of operations.

Management believes that other recently issued accounting standards, which are not yet effective, will not have a material impact on our consolidated financial statements upon adoption.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are subject to financial market risks, including fluctuations in foreign currency exchange rates and interest rates. In order to manage and mitigate our exposure to these risks, we may use derivative financial instruments in accordance with established policies and procedures. We do not use derivative financial instruments where the objective is to generate profits solely from trading activities. At December 31, 2013 and 2012, our derivative holdings consisted of foreign currency forward contracts and foreign currency instruments embedded in purchase and sale contracts.

These forward-looking disclosures only address potential impacts from market risks as they affect our financial instruments and do not include other potential effects that could impact our business as a result of changes in foreign currency exchange rates, interest rates, commodity prices or equity prices.

Foreign Currency Exchange Rate Risk

We conduct operations around the world in a number of different currencies. Most of our significant foreign subsidiaries have designated the local currency as their functional currency. Our earnings are therefore subject to change due to fluctuations in foreign currency exchange rates when the earnings in foreign currencies are translated into U.S. dollars. We do not hedge this translation impact on earnings. A 10% increase or decrease in the average exchange rates of all foreign currencies at December 31, 2013, would have changed our revenue and income before income taxes attributable to FMC Technologies, Inc. by approximately 5% and 2%, respectively.

When transactions are denominated in currencies other than our subsidiaries’ respective functional currencies, we manage these exposures through the use of derivative instruments to mitigate our risk. We use foreign currency forward contracts to hedge the foreign currency fluctuation associated with firmly committed and forecasted foreign currency denominated payments and receipts. The derivative instruments associated with these anticipated transactions are designated and qualify as cash flow hedges, and as such the gains and losses associated with these instruments are recorded in other comprehensive income until such time that the underlying transactions are recognized. When an anticipated transaction in a currency other than the functional currency of an entity is recognized as an asset or liability on the balance sheet, we also hedge the foreign currency fluctuation with derivative instruments after netting our exposures worldwide. These derivative instruments do not qualify as cash flow hedges.

Occasionally, we enter into contracts or other arrangements that are subject to foreign exchange fluctuations that qualify as embedded derivative instruments. In those situations, we enter into derivative foreign exchange contracts that hedge the price fluctuations due to movements in the foreign exchange rates. These hedges are not treated as cash flow hedges.

We have prepared a sensitivity analysis of our foreign currency forward contracts hedging anticipated transactions that are accounted for as cash flow hedges. This analysis assumes that each foreign currency rate would change 10% against a stronger and then weaker U.S. dollar. A 10% increase in the value of the U.S. dollar would result in an additional loss of $118.8 million in the net fair value of cash flow hedges reflected in our consolidated balance sheet at December 31, 2013. Unless these contracts are deemed to be ineffective, changes in the derivative fair value will not have an immediate impact on our results of operations since the gains and losses associated with these instruments are recorded in other comprehensive income. When the anticipated transactions occur, these changes in value of derivatives instrument positions will be offset against changes in the value of the underlying transaction.

Interest Rate Risk

At December 31, 2013, we had unhedged variable rate debt of $501.4 million with a weighted average interest rate of 0.33%. Using sensitivity analysis to measure the impact of a 10% adverse movement in the interest rate, or three basis points, would result in an increase to interest expense of $0.2 million.

We assess effectiveness of forward foreign currency contracts designated as cash flow hedges based on changes in fair value attributable to changes in spot rates. We exclude the impact attributable to changes in the difference between the spot rate and the forward rate for the assessment of hedge effectiveness and recognize the change in fair value of this component immediately in earnings. Considering that the difference between the spot rate and the forward rate is proportional to the differences in the interest rates of the countries of the currencies being traded, we have exposure to relative changes in interest rates between countries in our results of operations. To the extent any one interest rate increases by 10% across all tenors and other countries’ interest rates remain fixed, and assuming no change in discount rates, we would expect to recognize a decrease of $2.1 million in earnings in the period of change. Based on our portfolio as of December 31, 2013, we have material positions with exposure to the interest rates in the United States, Brazil, the United Kingdom, Singapore, the European Community and Norway.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even internal control systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and reporting.

Under the supervision and with the participation of management, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective in providing this reasonable assurance as of December 31, 2013.

KPMG LLP, an independent registered public accounting firm, has audited the Company’s consolidated financial statements as of and for the three-year period ended December 31, 2013, and has issued an audit report on the Company’s internal control over financial reporting as of December 31, 2013, which is included herein.



/s/ JOHN T. GREMP		/s/ MARYANN T. SEAMAN
John T. Gremp		Maryann T. Seaman
Chairman, President and Chief Executive Officer		Senior Vice President and Chief Financial Officer

February 21, 2014

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of FMC Technologies, Inc.:

We have audited FMC Technologies, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). FMC Technologies, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the FMC Technologies, Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, FMC Technologies, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of FMC Technologies, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in stockholders’ equity for each of the years in the three-year period ended December 31, 2013, and our report dated February 21, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 21, 2014

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of FMC Technologies, Inc.:

We have audited the accompanying consolidated balance sheets of FMC Technologies, Inc. and subsidiaries (the Company) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in stockholders’ equity for each of the years in the three-year period ended December 31, 2013. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule II, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 21, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 21, 2014

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



	Twelve Months Ended December 31,
(In millions, except per share data)	2013			2012			2011
Revenue:
Product revenue	$	5,724.7		$	5,198.2		$	4,347.8
Service and other revenue	1,401.5			953.2			751.2
Total revenue	7,126.2			6,151.4			5,099.0
Costs and expenses:
Cost of product revenue	4,562.4			4,155.7			3,473.4
Cost of service and other revenue	1,009.0			677.2			492.8
Selling, general and administrative expense	694.8			596.9			479.9
Research and development expense	112.4			116.8			90.5
Total costs and expenses	6,378.6			5,546.6			4,536.6
Other income (expense), net	5.3			23.0			(1.4		)
Income before interest income, interest expense and income taxes	752.9			627.8			561.0
Interest income	0.7			(0.4		)	2.8
Interest expense	(34.4		)	(26.2		)	(11.0		)
Income before income taxes	719.2			601.2			552.8
Provision for income taxes	212.6			166.4			149.3
Net income	506.6			434.8			403.5
Net income attributable to noncontrolling interests	(5.2		)	(4.8		)	(3.7		)
Net income attributable to FMC Technologies, Inc.	$	501.4		$	430.0		$	399.8
Earnings per share attributable to FMC Technologies, Inc. (Note 3):
Basic	$	2.10		$	1.79		$	1.66
Diluted	$	2.10		$	1.78		$	1.64
Weighted average shares outstanding (Note 3):
Basic	238.3			239.7			241.2
Diluted	239.1			240.9			243.2

The accompanying notes are an integral part of the consolidated financial statements.

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Twelve Months Ended December 31,
(In millions)	2013			2012			2011
Net income	$	506.6		$	434.8		$	403.5
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments ⁽¹⁾	(99.7		)	(1.8		)	(51.1		)
Net gains (losses) on hedging instruments:
Net gains (losses) arising during the period	27.1			29.0			(3.0		)
Reclassification adjustment for net gains included in net income	(5.2		)	(2.3		)	(19.8		)
Net gains (losses) on hedging instruments ⁽²⁾	21.9			26.7			(22.8		)
Pension and other post-retirement benefits:
Net actuarial gain (loss) arising during the period	112.5			(5.1		)	(132.1		)
Prior service cost arising during the period	(0.4		)	—			(0.6		)
Reclassification adjustment for settlement losses included in net income	3.2			9.6			5.6
Reclassification adjustment for amortization of prior service credit included in net income	(0.3		)	(0.7		)	(0.8		)
Reclassification adjustment for amortization of net actuarial loss included in net income	18.2			19.3			10.5
Reclassification adjustment for amortization of transition asset included in net income	(0.1		)	(0.2		)	(0.4		)
Net pension and other post-retirement benefits ⁽³⁾	133.1			22.9			(117.8		)
Other comprehensive income (loss), net of tax	55.3			47.8			(191.7		)
Comprehensive income	561.9			482.6			211.8
Comprehensive income attributable to noncontrolling interest	(5.2		)	(4.8		)	(3.7		)
Comprehensive income attributable to FMC Technologies, Inc.	$	556.7		$	477.8		$	208.1

______________________


⁽¹⁾	Net of income tax (expense) benefit of $(1.6), $(2.2) and $5.1 for the years ended December 31, 2013, 2012 and 2011, respectively.


⁽²⁾	Net of income tax (expense) benefit of $1.0, $(12.3) and $12.9 for the years ended December 31, 2013, 2012 and 2011, respectively.


⁽³⁾	Net of income tax (expense) benefit of $(81.8), $(6.5) and $58.0 for the years ended December 31, 2013, 2012 and 2011, respectively.

The accompanying notes are an integral part of the consolidated financial statements.

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

	December 31,
(In millions, except par value data)	2013			2012
Assets
Cash and cash equivalents	$	399.1		$	342.1
Trade receivables, net of allowances of $7.4 in 2013 and $6.1 in 2012 (Note 21)	2,067.2			1,765.5
Inventories, net (Note 5)	980.4			965.1
Derivative financial instruments (Note 14)	165.9			73.4
Prepaid expenses	41.5			31.7
Deferred income taxes (Note 10)	59.1			55.9
Income taxes receivable	14.6			17.6
Other current assets	295.2			237.0
Total current assets	4,023.0			3,488.3
Investments	44.3			37.4
Property, plant and equipment, net (Note 6)	1,349.1			1,243.5
Goodwill (Note 7)	580.7			597.7
Intangible assets, net (Note 7)	315.3			347.4
Deferred income taxes (Note 10)	36.9			60.0
Derivative financial instruments (Note 14)	68.5			9.2
Other assets	187.8			119.4
Total assets	$	6,605.6		$	5,902.9
Liabilities and equity
Short-term debt and current portion of long-term debt (Note 9)	$	42.5		$	60.4
Accounts payable, trade	750.7			664.2
Advance payments and progress billings	803.2			501.6
Accrued payroll	222.0			202.0
Derivative financial instruments (Note 14)	171.3			50.4
Income taxes payable	138.1			40.2
Current portion of accrued pension and other post-retirement benefits (Note 11)	11.0			20.9
Deferred income taxes (Note 10)	66.4			67.5
Other current liabilities	409.5			363.2
Total current liabilities	2,614.7			1,970.4
Long-term debt, less current portion (Note 9)	1,329.8			1,580.4
Accrued pension and other post-retirement benefits, less current portion (Note 11)	84.0			266.5
Derivative financial instruments (Note 14)	47.1			11.1
Deferred income taxes (Note 10)	90.3			57.9
Other liabilities	103.4			163.4
Commitments and contingent liabilities (Note 18)
Stockholders’ equity (Note 13):
Preferred stock, $0.01 par value, 12.0 shares authorized; no shares issued in 2013 or 2012	—			—
Common stock, $0.01 par value, 600.0 shares authorized in 2013 and 2012; 286.3 shares issued in 2013 and 2012; and 235.8 and 237.1 shares outstanding in 2013 and 2012, respectively	1.4			1.4
Common stock held in employee benefit trust, at cost; 0.2 shares in 2013 and 2012	(7.7		)	(7.8		)
Common stock held in treasury, at cost, 50.3 and 49.0 shares in 2013 and 2012, respectively	(1,196.6		)	(1,102.6		)
Capital in excess of par value of common stock	714.7			697.2
Retained earnings	3,146.1			2,644.7
Accumulated other comprehensive loss	(340.7		)	(396.0		)
Total FMC Technologies, Inc. stockholders’ equity	2,317.2			1,836.9
Noncontrolling interests	19.1			16.3
Total equity	2,336.3			1,853.2
Total liabilities and equity	$	6,605.6		$	5,902.9

The accompanying notes are an integral part of the consolidated financial statements.

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
(In millions)	2013			2012			2011
Cash provided (required) by operating activities:
Net income	$	506.6		$	434.8		$	403.5
Adjustments to reconcile income to cash provided (required) by operating activities:
Depreciation	156.0			113.1			86.1
Amortization	53.8			33.1			21.7
Multi Phase Meters contingent earn-out consideration obligation	28.8			42.0			—
Employee benefit plan and stock-based compensation costs	93.5			110.4			77.8
Deferred income tax benefit	(20.4		)	(9.8		)	(15.1		)
Unrealized loss (gain) on derivative instruments	(5.7		)	13.5			(14.2		)
Other	1.6			(6.2		)	(6.4		)
Changes in operating assets and liabilities, net of effects of acquisitions:
Trade receivables, net	(391.0		)	(337.3		)	(286.7		)
Inventories, net	(28.9		)	(206.6		)	(162.6		)
Accounts payable, trade	103.8			83.0			214.7
Advance payments and progress billings	329.0			25.9			(95.9		)
Income taxes	77.6			(71.4		)	70.5
Payment of Multi Phase Meters earn-out consideration	(32.2		)	—			—
Accrued pension and other post-retirement benefits, net	(60.1		)	(63.1		)	(112.9		)
Other assets and liabilities, net	(17.0		)	(23.0		)	(15.7		)
Cash provided by operating activities	795.4			138.4			164.8
Cash provided (required) by investing activities:
Capital expenditures	(314.1		)	(405.6		)	(274.0		)
Acquisitions, net of cash and cash equivalents acquired	—			(615.5		)	—
Proceeds from disposal of assets	7.4			3.2			2.2
Other	(4.9		)	(2.0		)	(1.9		)
Cash required by investing activities	(311.6		)	(1,019.9		)	(273.7		)
Cash provided (required) by financing activities:
Net increase in short-term debt	8.5			13.4			0.5
Net increase (decrease) in commercial paper	(168.4		)	189.7			269.1
Proceeds from issuance of long-term debt	26.2			1,068.9			—
Repayments of long-term debt	(136.0		)	(288.8		)	(5.6		)
Purchase of treasury stock	(116.3		)	(91.1		)	(114.0		)
Payment of Multi Phase Meters earn-out consideration	(25.1		)	—			—
Payments related to taxes withheld on stock-based compensation	(17.5		)	(34.8		)	(15.5		)
Excess tax benefits	8.0			27.1			8.7
Other	(1.7		)	(3.0		)	(2.2		)
Cash provided (required) by financing activities	(422.3		)	881.4			141.0
Effect of exchange rate changes on cash and cash equivalents	(4.5		)	(1.8		)	(3.6		)
Increase (decrease) in cash and cash equivalents	57.0			(1.9		)	28.5
Cash and cash equivalents, beginning of year	342.1			344.0			315.5
Cash and cash equivalents, end of year	$	399.1		$	342.1		$	344.0

The accompanying notes are an integral part of the consolidated financial statements.

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY



(In millions)	Common Stock		Common Stock Held in Treasury and Employee Benefit Trust			Capital in Excess of Par Value of Common Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Non- controlling Interest			Total Stockholders’ Equity
Balance at December 31, 2010	$	1.4	$	(951.2	)	$	698.7		$	1,814.9	$	(252.1	)	$	10.6		$	1,322.3
Net income	—		—			—			399.8		—			3.7			403.5
Other comprehensive loss	—		—			—			—		(191.7		)	—			(191.7		)
Issuance of common stock	—		—			1.3			—		—			—			1.3
Excess tax benefits on stock-based payment arrangements	—		—			8.7			—		—			—			8.7
Taxes withheld on issuance of stock-based awards	—		—			(15.5		)	—		—			—			(15.5		)
Purchases of treasury stock (Note 13)	—		(114.0		)	—			—		—			—			(114.0		)
Reissuances of treasury stock (Note 13)	—		19.9			(19.9		)	—		—			—			—
Net purchases of common stock for employee benefit trust	—		(2.4		)	0.3			—		—			—			(2.1		)
Stock-based compensation (Note 12)	—		—			26.3			—		—			—			26.3
Other	—		—			0.1			—		—			(1.2		)	(1.1		)
Balance at December 31, 2011	$	1.4	$	(1,047.7	)	$	700.0		$	2,214.7	$	(443.8	)	$	13.1		$	1,437.7
Net income	—		—			—			430.0		—			4.8			434.8
Other comprehensive income	—		—			—			—		47.8			—			47.8
Issuance of common stock	—		—			0.7			—		—			—			0.7
Excess tax benefits on stock-based payment arrangements	—		—			27.1			—		—			—			27.1
Taxes withheld on issuance of stock-based awards	—		—			(34.8		)	—		—			—			(34.8		)
Purchases of treasury stock (Note 13)	—		(91.1		)	—			—		—			—			(91.1		)
Reissuances of treasury stock (Note 13)	—		30.4			(30.4		)	—		—			—			—
Net purchases of common stock for employee benefit trust	—		(2.0		)	0.6			—		—			—			(1.4		)
Stock-based compensation (Note 12)	—		—			34.0			—		—			—			34.0
Other	—		—			—			—		—			(1.6		)	(1.6		)
Balance at December 31, 2012	$	1.4	$	(1,110.4	)	$	697.2		$	2,644.7	$	(396.0	)	$	16.3		$	1,853.2



(In millions)	Common Stock		Common Stock Held in Treasury and Employee Benefit Trust			Capital in Excess of Par Value of Common Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Non- controlling Interest			Total Stockholders’ Equity
Balance at December 31, 2012	$	1.4	$	(1,110.4	)	$	697.2		$	2,644.7	$	(396.0	)	$	16.3		$	1,853.2
Net income	—		—			—			501.4		—			5.2			506.6
Other comprehensive income	—		—			—			—		55.3			—			55.3
Issuance of common stock	—		—			0.6			—		—			—			0.6
Excess tax benefits on stock-based payment arrangements	—		—			8.0			—		—			—			8.0
Taxes withheld on issuance of stock-based awards	—		—			(17.5		)	—		—			—			(17.5		)
Purchases of treasury stock (Note 13)	—		(116.3		)	—			—		—			—			(116.3		)
Reissuances of treasury stock (Note 13)	—		22.3			(22.3		)	—		—			—			—
Net purchases of common stock for employee benefit trust	—		0.1			1.0			—		—			—			1.1
Stock-based compensation (Note 12)	—		—			47.7			—		—			—			47.7
Other	—		—			—			—		—			(2.4		)	(2.4		)
Balance at December 31, 2013	$	1.4	$	(1,204.3	)	$	714.7		$	3,146.1	$	(340.7	)	$	19.1		$	2,336.3

The accompanying notes are an integral part of the consolidated financial statements.

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of operations—FMC Technologies, Inc. and consolidated subsidiaries (“FMC Technologies,” “we” or “us”) designs, manufactures and services technologically sophisticated systems and products for our customers in the energy industry through our business segments: Subsea Technologies, Surface Technologies and Energy Infrastructure. We have manufacturing operations worldwide, strategically located to facilitate delivery of our products, systems and services to our customers.

Basis of presentation—Our consolidated financial statements have been prepared in U.S. dollars and in accordance with U.S. generally accepted accounting principles (“GAAP”).

On February 25, 2011, our Board of Directors approved a two-for-one stock split of our outstanding shares of common stock. The stock split was completed in the form of a stock dividend that was issued on March 31, 2011 to stockholders of record at the close of business on March 14, 2011. All common share and per share information in our consolidated financial statements reflect the effects of the stock split.

Principles of consolidation—The consolidated financial statements include the accounts of FMC Technologies and its majority-owned subsidiaries and affiliates. Intercompany accounts and transactions are eliminated in consolidation.

Use of estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Such estimates include, but are not limited to, estimates of total contract profit or loss on long-term construction-type contracts; estimated realizable value on excess and obsolete inventory; estimates related to pension accounting; estimates related to fair value for purposes of assessing goodwill, long-lived assets and intangible assets for impairment; estimates related to fair value for purposes of assigning amounts to assets acquired and liabilities assumed in business combinations; estimates related to income taxes; and estimates related to contingencies, including liquidated damages.

Investments in the common stock of unconsolidated affiliates—The investments in, and the operating results of, unconsolidated affiliates are included in the consolidated financial statements on the basis of the equity method of accounting or the cost method of accounting, depending on specific facts and circumstances.

Investments in unconsolidated affiliates are assessed for impairment whenever events or changes in facts and circumstances indicate the carrying value of the investments may not be fully recoverable. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. Management’s assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. Management generally considers our investments in equity method investees to be strategic long-term investments and completes its assessments for impairment with a long-term viewpoint.

Reclassifications—Certain prior-year amounts have been reclassified to conform to the current year’s presentation.

Revenue recognition—Revenue is generally recognized once the following four criteria are met: i) persuasive evidence of an arrangement exists, ii) delivery of the equipment has occurred (which is upon shipment or when customer-specific acceptance requirements are met) or services have been rendered, iii) the price of the equipment or service is fixed and determinable, and iv) collectibility is reasonably assured. We record our sales net of any value added, sales or use tax.

For certain construction-type manufacturing and assembly projects that involve significant design and engineering efforts in order to satisfy detailed customer-supplied specifications, revenue is recognized using the percentage of completion method of accounting. Under the percentage of completion method, revenue is recognized as work progresses on each contract. We primarily apply the ratio of costs incurred to date to total estimated contract costs at completion to measure this ratio. If it is not possible to form a reliable estimate of progress toward completion, no revenue or costs are recognized until the project is complete or substantially complete. Any expected losses on construction-type contracts in progress are charged to earnings, in total, in the period the losses are identified.

Modifications to construction-type contracts, referred to as “change orders,” effectively change the provisions of the original contract, and may, for example, alter the specifications or design, method or manner of performance, equipment, materials, sites and/or period for completion of the work. If a change order represents a firm price commitment from a customer, we account for the revised estimate as if it had been included in the original estimate, effectively recognizing the pro rata impact of the new estimate on our calculation of progress toward completion in the period in which the firm commitment is received. If a change order is unpriced: (1) we include the costs of contract performance in our calculation of progress toward completion in the period in which the costs are incurred or become probable; and (2) when it is determined that the revenue is probable of recovery, we include the change order revenue, limited to the costs incurred to date related to the change order, in our calculation of progress toward completion. Unpriced change orders included in revenue were immaterial to our consolidated revenue for all periods presented. Margin is not recorded on unpriced change orders unless realization is assured beyond a reasonable doubt. The assessment of realization may be based upon our previous experience with the customer or based upon our receipt of a firm price commitment from the customer.

Progress billings are generally issued upon completion of certain phases of the work as stipulated in the contract. Revenue in excess of progress billings are reported in trade receivables on the consolidated balance sheets. Progress billings and cash collections in excess of revenue recognized on a contract are classified as advance payments and progress billings within current liabilities on the consolidated balance sheets.

Shipping and handling costs—Shipping and handling costs are recorded as cost of product revenue in our consolidated statements of income. Shipping and handling costs billed to customers are recorded as a component of revenue.

Cash equivalents—Cash equivalents are highly-liquid, short-term instruments with original maturities of three months or less from their date of purchase.

Trade receivables, net of allowances—An allowance for doubtful accounts is provided on trade receivables equal to the estimated uncollectible amounts. This estimate is based on historical collection experience and a specific review of each customer’s trade receivable balance.

Inventories—Inventories are stated at the lower of cost or net realizable value. Inventory costs include those costs directly attributable to products, including all manufacturing overhead, but excluding costs to distribute. Cost is determined on the last-in, first-out (“LIFO”) basis for all significant domestic inventories, except certain inventories relating to construction-type contracts, which are stated at the actual production cost incurred to date, reduced by the portion of these costs identified with revenue recognized. The first-in, first-out (“FIFO”) method is used to determine the cost for all other inventories.

Investments—The appropriate classification of investments in marketable equity securities is determined at the time of purchase and re-evaluated as of each subsequent reporting date. Securities classified as available-for-sale are carried at fair value with unrealized holding gains and losses on these securities recognized in accumulated other comprehensive income (loss), net of related income tax. We did not have any available-for-sale securities at December 31, 2013 or 2012.

Securities classified as trading securities are carried at fair value with gains and losses on these securities recognized through other income (expense), net. Trading securities are comprised primarily of marketable equity mutual funds that approximate a portion of our liability under our Non-Qualified Savings and Investment Plan (“Non-Qualified Plan”).

Property, plant, and equipment—Property, plant, and equipment is recorded at cost. Depreciation is principally provided on the straight-line basis over the estimated useful lives of the assets (land improvements—20 to 35 years; buildings—20 to 50 years; and machinery and equipment—3 to 20 years). Gains and losses are realized upon the sale or retirement of assets and are recorded in other income (expense), net on our consolidated statements of income. Maintenance and repair costs are expensed as incurred. Expenditures that extend the useful lives of property, plant and equipment are capitalized and depreciated over the estimated new remaining life of the asset.

Impairment of property, plant, and equipment—Property, plant and equipment are reviewed for impairment whenever events or changes in circumstances indicate the carrying value of the long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If it is determined that an impairment loss has occurred, the impairment loss is measured as the amount by which the carrying value of the long-lived asset exceeds its fair value.

Long-lived assets held for sale are reported at the lower of carrying value or fair value less cost to sell.

Capitalized software costs—Other assets on the consolidated balance sheets include the capitalized cost of internal use software (including Internet websites). The assets are stated at cost less accumulated amortization. These software costs include significant purchases of software and internal and external costs incurred during the application development stage of software projects. These costs are amortized on a straight-line basis over the estimated useful lives of the assets. For internal use software, the useful lives range from three to ten years. For Internet website costs, the estimated useful lives do not exceed three years.

Goodwill and other intangible assets—Goodwill is not subject to amortization but is tested for impairment on an annual basis (or more frequently if impairment indicators arise). We have established October 31 as the date of our annual test for impairment of goodwill. Reporting units with goodwill are tested for impairment by first assessing qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If after assessing the totality of events or circumstances, or based on management’s judgment, we determine it is more likely than not that the fair value of a reporting unit is less than its carrying amount, a two-step impairment test is performed. The first step compares the fair value of the reporting unit (measured as the present value of expected future cash flows) to its carrying amount. If the fair value of the reporting unit is less than its carrying amount, a second step is performed. In this step, the fair value of the reporting unit is allocated to its assets and liabilities to determine the implied fair value of goodwill, which is used to measure the impairment loss. We have not recognized any impairment for the years ended December 31, 2013 or 2012, as the fair values of our reporting units with goodwill balances exceeded our carrying amounts. In addition, there were no negative conditions, or triggering events, that occurred in 2013 or 2012 requiring us to perform additional impairment reviews.

Our acquired intangible assets are amortized on a straight-line basis over their estimated useful lives, which generally range from 7 to 40 years. Our acquired intangible assets do not have indefinite lives. Intangible assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of the intangible asset may not be recoverable. The carrying amount of an intangible asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If it is determined that an impairment loss has occurred, the loss is measured as the amount by which the carrying amount of the intangible asset exceeds its fair value.

Fair value measurements—We record our financial assets and financial liabilities at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the reporting date. The fair value framework requires the categorization of assets and liabilities into three levels based upon the assumptions (inputs) used to price the assets or liabilities. Level 1 provides the most reliable measure of fair value, whereas Level 3 generally requires significant management judgment. The three levels are defined as follows:


•	Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities.


•	Level 2: Observable inputs other than quoted prices included in Level 1. For example, quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in inactive markets.


•	Level 3: Unobservable inputs reflecting management’s own assumptions about the assumptions market participants would use in pricing the asset or liability.

Income taxes—Current income taxes are provided on income reported for financial statement purposes, adjusted for transactions that do not enter into the computation of income taxes payable in the same year. Deferred tax assets and liabilities are measured using enacted tax rates for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities. A valuation allowance is established whenever management believes that it is more likely than not that deferred tax assets may not be realizable.

U.S. income taxes are not provided on our equity in undistributed earnings of foreign subsidiaries or affiliates to the extent we have determined that the earnings are indefinitely reinvested. U.S. income taxes are provided on such earnings in the period in which we can no longer support that such earnings are indefinitely reinvested.

We classify interest expense and penalties recognized on underpayments of income taxes as income tax expense.

Stock-based employee compensation—We measure stock-based compensation expense on restricted stock awards based on the market price at the grant date and the number of shares awarded. The stock-based compensation expense for each award is recognized ratably over the applicable service period, after taking into account estimated forfeitures, or the period beginning at the start of the service period and ending when an employee becomes eligible for retirement.

Common stock held in employee benefit trust—Shares of our common stock are purchased by the plan administrator of the Non-Qualified Plan and placed in a trust owned by us. Purchased shares are recorded at cost and classified as a reduction of stockholders’ equity on the consolidated balance sheets.

Earnings per common share (“EPS”)—Basic EPS is computed using the weighted-average number of common shares outstanding during the year. Diluted EPS gives effect to the potential dilution of earnings that could have occurred if additional shares were issued for stock option exercises and restricted stock under the treasury stock method. The treasury stock method assumes proceeds that would be obtained upon exercise of common stock options and issuance of restricted stock are used to buy back outstanding common stock at the average market price during the period.

Warranty obligations—We provide warranties of various lengths and terms to certain of our customers based on standard terms and conditions and negotiated agreements. Estimated cost of warranties are accrued at the time revenue is recognized for products where reliable, historical experience of warranty claims and costs exists or when additional specific obligations are identified. The obligation reflected in other current liabilities on the consolidated balance sheets is based on historical experience by product and considers failure rates and the related costs in correcting a product failure. Should actual product failure rates or repair costs differ from our current estimates, revisions to the estimated warranty liability would be required.

Foreign currency—Financial statements of operations for which the U.S. dollar is not the functional currency, and are located in non-highly inflationary countries, are translated into U.S. dollars prior to consolidation. Assets and liabilities are translated at the exchange rate in effect at the balance sheet date, while income statement accounts are translated at the average exchange rate for each period. For these operations, translation gains and losses are recorded as a component of accumulated other comprehensive income (loss) in stockholders’ equity until the foreign entity is sold or liquidated. For operations in highly inflationary countries and where the local currency is not the functional currency, inventories, property, plant and equipment, and other non-current assets are converted to U.S. dollars at historical exchange rates, and all gains or losses from conversion are included in net income. Foreign currency effects on cash, cash equivalents and debt in hyperinflationary economies are included in interest income or expense.

Derivative instruments—Derivatives are recognized on the consolidated balance sheets at fair value, with classification as current or non-current based upon the maturity of the derivative instrument. Changes in the fair value of derivative instruments are recorded in current earnings or deferred in accumulated other comprehensive income (loss), depending on the type of hedging transaction and whether a derivative is designated as, and is effective as, a hedge. Each instrument is accounted for individually and assets and liabilities are not offset.

Hedge accounting is only applied when the derivative is deemed to be highly effective at offsetting changes in anticipated cash flows of the hedged item or transaction. Changes in fair value of derivatives that are designated as cash flow hedges are deferred in accumulated other comprehensive income (loss) until the underlying transactions are recognized in earnings. At such time, related deferred hedging gains or losses are also recorded in operating earnings on the same line as the hedged item. Effectiveness is assessed at the inception of the hedge and on a quarterly basis. Effectiveness of forward contract cash flow hedges are assessed based solely on changes in fair value attributable to the change in the spot rate. The change in the fair value of the contract related to the change in forward rates is excluded from the assessment of hedge effectiveness. Changes in this excluded component of the derivative instrument, along with any ineffectiveness identified, are recorded in operating earnings as incurred. We document our risk management strategy and hedge effectiveness at the inception of, and during the term of, each hedge.

We also use forward contracts to hedge foreign currency assets and liabilities, for which we do not apply hedge accounting. The changes in fair value of these contracts are recognized in other income (expense), net on our consolidated statements of income, as they occur and offset gains or losses on the remeasurement of the related asset or liability.

Cash flows from derivative contracts are reported in the consolidated statements of cash flows in the same categories as the cash flows from the underlying transactions.

NOTE 2. RECENTLY ADOPTED ACCOUNTING STANDARDS

Effective January 1, 2013, we adopted Accounting Standards Update (“ASU”) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” and ASU No. 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” issued by the Financial Accounting Standards Board (“FASB”). These updates require management to disclose both gross information and net information of recognized derivative instruments, repurchase agreements and securities borrowing and lending transactions offset in the consolidated balance sheet or subject to an agreement similar to an enforceable master netting arrangement. The updated guidance is to be applied retrospectively, effective January 1, 2013. The adoption of these updates concern disclosure only and did not have any financial impact on our consolidated financial statements.

Effective January 1, 2013, we adopted ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” issued by the FASB. This update requires management to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under GAAP to be reclassified in its entirety to net income. For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, we are required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts. The updated guidance is to be applied prospectively, effective January 1, 2013. The adoption of this update concerns disclosure only and did not have any financial impact on our consolidated financial statements.

NOTE 3. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted earnings per share calculation was as follows:



	Year Ended December 31,
(In millions, except per share data)	2013		2012		2011
Net income attributable to FMC Technologies, Inc.	$	501.4	$	430.0	$	399.8
Weighted average number of shares outstanding	238.3		239.7		241.2
Dilutive effect of restricted stock units and stock options	0.8		1.2		2.0
Total shares and dilutive securities	239.1		240.9		243.2

Basic earnings per share attributable to FMC Technologies, Inc.	$	2.10	$	1.79	$	1.66
Diluted earnings per share attributable to FMC Technologies, Inc.	$	2.10	$	1.78	$	1.64

NOTE 4. BUSINESS COMBINATIONS

Schilling Robotics, LLC—On January 3, 2012, we exercised our option to purchase the remaining 55% of outstanding shares of Schilling Robotics, LLC (“Schilling Robotics”), a Delaware limited liability company, and closed the transaction on April 25, 2012. Schilling Robotics is a supplier of advanced robotic intervention products, including a line of remotely operated vehicle systems (“ROV”), manipulator systems and subsea control systems. The acquisition of the remaining interests in Schilling Robotics is allowing us to grow in the expanding subsea environment, where demand for ROVs and the need for maintenance activities of subsea equipment is expected to increase.

Prior to April 25, 2012, we owned 45% of Schilling Robotics. Upon the closing of this transaction, we owned 100% of Schilling Robotics which is included among the consolidated subsidiaries reported in our Subsea Technologies segment. The acquisition-date fair value of our previously held equity interest in Schilling Robotics was $144.9 million with the fair value primarily estimated through an income approach valuation. In 2012 we recorded a gain of $20.0 million in other income (expense), net on the consolidated statement of income related to the fair value remeasurement of our previously held equity interest in Schilling Robotics.

The purchase price with respect to the remaining outstanding shares was determined by applying the multiple of our market capital relative to our earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the year ended December 31, 2011 (determined in accordance with the terms of the unitholders agreement), to the EBITDA generated by Schilling Robotics during the year ended December 31, 2011 (subject to certain adjustments in accordance with the terms of the unitholders agreement). The consideration for the remaining outstanding shares was paid in cash.

Control Systems International, Inc.—On April 30, 2012, we acquired 100% of Control Systems International, Inc. (“CSI”) which is included among the consolidated subsidiaries reported in our Energy Infrastructure segment. Our acquisition of CSI is enhancing our automation and controls technologies and is benefiting production and processing businesses such as measurement solutions through comprehensive fuel terminal and pipeline automation systems. Additionally, the acquired technologies support our long-term strategy to expand our subsea production and processing systems.

Pure Energy Services Ltd.—On October 1, 2012, we acquired 100% of Pure Energy Services Ltd. (“Pure Energy”) which is included among the consolidated subsidiaries reported in our Surface Technologies segment. Based in Calgary, Alberta, Canada, and operating in multiple field locations in both Canada and the United States, Pure Energy is a provider of fracturing flowback services and wireline services. The acquisition of Pure Energy is complementing the existing products and services of our Surface Technologies segment and is creating client value by providing an integrated well site solution.

The acquisition-date fair value of the consideration transferred for each business combination consisted of the following:



(In millions)	Schilling Robotics		CSI			Pure Energy		Total
Cash	$	282.8	$	49.0	⁽¹⁾	$	287.0	$	618.8
Previously held equity interest	144.9		—			—		144.9
Purchase price withheld	—		10.0		⁽²⁾	—		10.0
Total consideration transferred	$	427.7	$	59.0		$	287.0	$	773.7

_______________________


⁽¹⁾	Includes anticipated recovery of negative working capital. During 2012 and 2013, we received payment of negative working capital amounts.

⁽²⁾

Represents the portion of the purchase price withheld ("holdback") by FMC Technologies pursuant to the terms of the stock purchase agreement. The holdback amount will be held and maintained by FMC Technologies as security for the payment of any and all amounts to which CSI indemnifies us, including final working capital adjustments and other indemnifications as listed in the stock purchase agreement. FMC Technologies may deduct from the holdback any eligible amounts and pay CSI the net amount three years after the closing date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition dates.



(In millions)	Schilling Robotics			CSI			Pure Energy			Total
Assets:
Cash	$	3.9		$	0.3		$	0.2		$	4.4
Accounts receivable	22.4			8.2			44.8			75.4
Inventory	50.6			0.1			3.3			54.0
Other current assets	2.1			0.2			2.1			4.4
Property, plant and equipment	21.7			0.2			162.2			184.1
Intangible assets	145.9			35.1			58.2			239.2
Other long-term assets	0.7			—			—			0.7
Total identifiable assets acquired	247.3			44.1			270.8			562.2
Liabilities:
Current liabilities	(33.4		)	(15.8		)	(38.1		)	(87.3		)
Long-term debt	—			—			(18.6		)	(18.6		)
Deferred income taxes	—			—			(12.6		)	(12.6		)
Other long-term liabilities	(1.9		)	—			—			(1.9		)
Total liabilities assumed	(35.3		)	(15.8		)	(69.3		)	(120.4		)
Net identifiable assets acquired	212.0			28.3			201.5			441.8
Goodwill	215.7			30.7			85.5			331.9
Net assets acquired	$	427.7		$	59.0		$	287.0		$	773.7

The goodwill recognized is primarily attributable to expected synergies and assembled workforce acquired in Schilling Robotics, CSI and Pure Energy. During 2013, there were immaterial purchase accounting adjustments recognized in goodwill, including an increase of $0.3 million for Schilling Robotics and a decrease of $0.9 million for Pure Energy. The majority of the combined goodwill recognized for Schilling Robotics and CSI is deductible for tax purposes. Goodwill recognized for Pure Energy is not deductible for tax purposes.

The identifiable intangible assets acquired include the following:



	Schilling Robotics			CSI			Pure Energy
(In millions, except amortization periods)	Fair Value		Wgtd. Avg. Amortization Period (in years)	Fair Value		Wgtd. Avg. Amortization Period (in years)	Fair Value		Wgtd. Avg. Amortization Period (in years)
Technology	$	38.9	12	$	17.0	10	$	—	—
Trademarks/trade name	25.4		20	2.8		15	—		—
Customer relationships	42.9		20	15.3		15	57.6		20
Base technology – technical know-how	38.7		15	—		—	—		—
Non-compete agreements	—		—	—		—	0.6		2
Total identifiable intangible assets acquired	$	145.9		$	35.1		$	58.2

We recognized $1.2 million of acquisition-related costs that were expensed in the year ended December 31, 2012 related to the Schilling Robotics, CSI and Pure Energy acquisitions. These costs were recognized as selling, general and administrative expense in the consolidated statement of income. Revenue and net income of Schilling Robotics, CSI and Pure Energy from the acquisition dates to December 31, 2012 included in our consolidated statements of income were $94.6 million, $19.7 million and $67.3 million of revenue, respectively, and $3.1 million, $2.4 million and $2.7 million of net income, respectively.

Pro Forma Impact of Acquisitions (unaudited)

The following unaudited supplemental pro forma results present consolidated information as if the acquisitions had been completed as of January 1, 2011. The 2012 pro forma results include: (i) $10.1 million of amortization for acquired intangible assets, (ii) $10.7 million in inventory fair value step-up amortization for Schilling Robotics, and (iii) $1.2 million of acquisition-related costs. The pro forma results do not include any potential synergies, cost savings or other expected benefits of the acquisitions. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the acquisitions had been consummated as of January 1, 2011, nor are they indicative of future results.



	Twelve Months Ended December 31,
(In millions)	2012 Pro Forma		2011 Pro Forma
Revenue	$	6,394.4	$	5,512.8
Net income	$	446.0	$	444.3

NOTE 5. INVENTORIES

Inventories consisted of the following:



	December 31,
(In millions)	2013			2012
Raw materials	$	186.3		$	188.4
Work in process	141.4			146.4
Finished goods	830.3			788.8
	1,158.0			1,123.6
LIFO and valuation adjustments	(177.6		)	(158.5		)
Inventory, net	$	980.4		$	965.1

Net inventories accounted for under the LIFO method totaled $336.4 million and $342.2 million at December 31, 2013 and 2012, respectively. The current replacement costs of LIFO inventories exceeded their recorded values by $91.5 million and $88.7 million at December 31, 2013 and 2012, respectively. In 2013 there was a reduction in certain LIFO inventories which were carried at costs lower than current replacement costs. The result was a decrease in the cost of sales by $0.1 million for 2013. There were no reductions to the base LIFO inventory in 2012 or 2011.

NOTE 6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	December 31,
(In millions)	2013			2012
Land and land improvements	$	83.0		$	71.3
Buildings	379.4			350.9
Machinery and equipment	1,438.6			1,314.4
Construction in process	218.3			150.6
	2,119.3			1,887.2
Accumulated depreciation	(770.2		)	(643.7		)
Property, plant and equipment, net	$	1,349.1		$	1,243.5

Depreciation expense was $156.0, million, $113.1 million and $86.1 million in 2013, 2012 and 2011, respectively. The amount of interest cost capitalized was $0.7 million, $1.4 million and $0.5 million in 2013, 2012 and 2011, respectively.

NOTE 7. GOODWILL AND INTANGIBLE ASSETS

Goodwill —The carrying amount of goodwill by business segment was as follows:



(In millions)	Subsea Technologies			Surface Technologies			Energy Infrastructure			Total
December 31, 2012	$	342.3		$	97.1		$	158.3		$	597.7
Direct drive systems transfer ⁽¹⁾	66.9			—			(66.9		)	—
Purchase accounting adjustments	0.3			(0.9		)	—			(0.6		)
Translation	(12.6		)	(3.8		)	—			(16.4		)
December 31, 2013	$	396.9		$	92.4		$	91.4		$	580.7

_______________________


⁽¹⁾	Beginning in the third quarter of 2013, direct drive systems is reported as a product line in Subsea Technologies. See additional disclosure in Note 19.

Intangible assets—The components of intangible assets were as follows:



	December 31,
	2013				2012
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	148.6	$	27.7	$	152.3	$	19.6
Patents and acquired technology	221.8		56.5		223.7		40.7
Trademarks	36.2		7.6		36.4		5.6
Other	6.0		5.5		6.1		5.2
Total intangible assets	$	412.6	$	97.3	$	418.5	$	71.1

We did not have any additions to our intangible assets during 2013. Additions to our intangible assets during 2012 included $145.9 million, $35.1 million and $58.2 million associated with our acquisitions of Schilling Robotics, CSI and Pure Energy, respectively. Refer to Note 4 for further disclosure related to business combinations.

All of our acquired identifiable intangible assets are subject to amortization and, where applicable, foreign currency translation adjustments. We recorded $26.9 million, $20.8 million and $11.3 million in amortization expense related to intangible assets during the years ended December 31, 2013, 2012 and 2011, respectively. During the years 2014 through 2018, annual amortization expense is expected to be as follows: $26.0 million in 2014, $25.3 million in 2015, $24.8 million in 2016, $24.1 million in 2017, $23.8 million in 2018 and $191.3 million thereafter.

NOTE 8. SALE LEASEBACK TRANSACTION

In March 2007, we sold and leased back property in Houston, Texas, consisting of land, offices and production facilities primarily related to the Subsea Technologies and Surface Technologies segments. We received net proceeds of $58.1 million in connection with the sale. The carrying value of the property sold was $20.3 million. We accounted for the transaction as a sale leaseback resulting in (i) first quarter 2007 recognition of $1.3 million of the $37.4 million gain on the transaction and (ii) the deferral of the remaining $36.1 million of the gain, which will be amortized to rent expense over a noncancellable ten-year lease term. The deferred gain is presented in other liabilities in the consolidated balance sheet. The lease expires in 2022 and provides for two 5-year optional extensions as well as the option to terminate the lease in 2017, subject to a $3.3 million fee. Annual rent of $4.2 million escalates 2.0% per year. The lease was recorded as an operating lease.

NOTE 9. DEBT

Credit facility—On March 26, 2012, we entered into a new $1.5 billion revolving credit agreement (“credit agreement”) with JPMorgan Chase Bank, N.A., as Administrative Agent. The credit agreement is a five-year, revolving credit facility expiring in March 2017. Subject to certain conditions, at our request and with the approval of the Administrative Agent, the aggregate commitments under the credit agreement may be increased by an additional $500.0 million.

Senior Notes—On September 21, 2012, we completed the public offering of $300.0 million aggregate principal amount of 2.00% senior notes due October 2017 (the “2017 Notes”) and $500.0 million aggregate principal amount of 3.45% senior notes due October 2022 (the “2022 Notes” and, collectively with the 2017 Notes, the “Senior Notes”). Interest on the Senior Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning April 1, 2013. Net proceeds from the offering of $793.8 million were used for the repayment of outstanding commercial paper and indebtedness under our revolving credit facility.

The terms of the Senior Notes are governed by the indenture (the “Base Indenture”), dated as of September 21, 2012 between FMC Technologies and U.S. Bank National Association, as trustee (the “Trustee”), as amended and supplemented by the First Supplemental Indenture between FMC Technologies and the Trustee (the “First Supplemental Indenture”) relating to the issuance of the 2017 Notes and the Second Supplemental Indenture between FMC Technologies and the Trustee (the “Second Supplemental Indenture”) relating to the issuance of the 2022 Notes.

At any time prior to their maturity in the case of the 2017 Notes, and at any time prior to July 1, 2022, in the case of the 2022 Notes, we may redeem some or all of the Senior Notes at the redemption prices specified in the First Supplemental Indenture and Second Supplemental Indenture, respectively. At any time on or after July 1, 2022, we may redeem some or all of the 2022 Notes at the redemption price equal to 100% of the principal amount of the 2022 Notes redeemed. The Senior Notes are our senior unsecured obligations. The Senior Notes will rank equally in right of payment with all of our existing and future unsubordinated debt, and will rank senior in right of payment to all of our future subordinated debt.

Commercial paper—Under our commercial paper program, we have the ability to access $1.0 billion of short-term financing through our commercial paper dealers subject to the limit of unused capacity of our revolving credit agreement. Commercial paper borrowings are issued at market interest rates. Commercial paper borrowings as of December 31, 2013, had a weighted average interest rate of 0.33%.

Term loan—In August 2013, we entered into a R$60.7 million term loan agreement in Brazil maturing on August 15, 2016, with Itaú BBA., as Administrative Agent. Under the loan agreement, interest accrues at an annual rate of 5.50%. Principal is due at maturity and interest is paid quarterly.

Property financing—In September 2004, we entered into agreements for the sale and leaseback of an office building having a net book value of $8.5 million. Under the terms of the agreement, the building was sold for $9.7 million in net proceeds and leased back under a 10-year lease. We have subleased this property to a third party under a lease agreement that is being accounted for as an operating lease. We have accounted for the transaction as a financing transaction and are amortizing the related obligation using an effective annual interest rate of 5.37%. In addition, property financing includes our obligations under capital lease arrangements.

Uncommitted credit—We have uncommitted credit lines at many of our international subsidiaries for immaterial amounts. We utilize these facilities to provide a more efficient daily source of liquidity. The effective interest rates depend upon the local national market.

Short-term debt and current portion of long-term debt—Short-term debt and current portion of long-term debt consisted of the following:



	December 31,
(In millions)	2013		2012
Term loan	$	—	$	26.8
Property financing	10.5		5.0
Foreign uncommitted credit facilities	31.9		22.1
Other	0.1		6.5
Total short-term debt and current portion of long-term debt	$	42.5	$	60.4

Long-term debt—Long-term debt consisted of the following:



	December 31,
(In millions)	2013			2012
Revolving credit facility	$	—		$	100.0
Commercial paper ⁽¹⁾	501.4			669.8
2.00% Notes due 2017	299.5			299.3
3.45% Notes due 2022	499.6			499.6
Term loan	25.9			26.8
Property financing	13.9			16.7
Total long-term debt	1,340.3			1,612.2
Less: current portion	(10.5		)	(31.8		)
Long-term debt, less current portion	$	1,329.8		$	1,580.4

_______________________

⁽¹⁾

At December 31, 2013 and 2012, committed credit available under our revolving credit facility provided the ability to refinance our commercial paper obligations on a long-term basis. As we have both the ability and intent to refinance these obligations on a long-term basis, our commercial paper borrowings were classified as long-term in the consolidated balance sheets at December 31, 2013 and 2012.

Maturities of total long-term debt as of December 31, 2013, are payable as follows: $10.5 million in 2014, $2.0 million in 2015, $27.1 million in 2016, $801.0 million in 2017, $0.1 million in 2018, and $499.6 million in 2022.

NOTE 10. INCOME TAXES

Domestic and foreign components of income before income taxes are shown below:



	Year Ended December 31,
(In millions)	2013		2012		2011
Domestic	$	150.7	$	125.5	$	132.7
Foreign	563.3		470.9		416.4
Income before income taxes attributable to FMC Technologies, Inc.	$	714.0	$	596.4	$	549.1

The provision for income taxes consisted of:



	Year Ended December 31,
(In millions)	2013			2012			2011
Current:
Federal	$	77.8		$	41.5		$	26.7
State	5.6			2.9			3.3
Foreign	149.6			131.8			134.4
Total current	233.0			176.2			164.4
Deferred:
Increase in the valuation allowance for deferred tax assets	0.5			0.5			0.2
Decrease of deferred tax liability for change in tax rates	(4.3		)	(1.3		)	(1.4		)
Other deferred tax (benefit) expense	(16.6		)	(9.0		)	(13.9		)
Total deferred	(20.4		)	(9.8		)	(15.1		)
Provision for income taxes	$	212.6		$	166.4		$	149.3

Significant components of our deferred tax assets and liabilities were as follows:



	December 31,
(In millions)	2013			2012
Deferred tax assets attributable to:
Accrued expenses	$	56.6		$	47.6
Foreign tax credit carryforwards	14.0			2.6
Accrued pension and other post-retirement benefits	26.5			109.1
Stock-based compensation	25.3			24.3
Net operating loss carryforwards	47.8			31.5
Inventories	25.9			21.1
Norwegian correction tax	61.9			71.0
Foreign exchange	3.7			5.2
Deferred tax assets	261.7			312.4
Valuation allowance	(4.7		)	(4.3		)
Deferred tax assets, net of valuation allowance	257.0			308.1
Deferred tax liabilities attributable to:
Revenue in excess of billings on contracts accounted for under the percentage of completion method	137.0			147.1
U.S. tax on foreign subsidiaries’ undistributed earnings not indefinitely reinvested	43.5			40.6
Property, plant and equipment, goodwill and other assets	137.2			129.9
Deferred tax liabilities	317.7			317.6
Net deferred tax assets (liabilities)	$	(60.7	)	$	(9.5	)

At December 31, 2013 and 2012, the carrying amount of net deferred tax assets and the related valuation allowance included the impact of foreign currency translation adjustments. Included in our deferred tax assets at December 31, 2013 were U.S. foreign tax credit carryforwards of $14.0 million, which, if not utilized, will begin to expire after 2015. Realization of these deferred tax assets is dependent on the generation of sufficient U.S. taxable income prior to the above date. Based on long-term forecasts of operating results, management believes that it is more likely than not that domestic earnings over the forecast period will result in sufficient U.S. taxable income to fully realize these deferred tax assets. In its analysis, management has considered the effect of foreign deemed dividends and other expected adjustments to domestic earnings that are required in determining U.S. taxable income. Foreign earnings taxable to us as dividends, including deemed dividends for U.S. tax purposes, were $196.2 million, $118.3 million and $169.3 million, in 2013, 2012 and 2011, respectively. Also included in deferred tax assets are tax benefits related to net operating loss carryforwards attributable to foreign entities. If not utilized, these net operating loss carryforwards will begin to expire in 2015. Management believes it is more likely than not that we will not be able to utilize certain of these operating loss carryforwards before expiration; therefore, we have established a valuation allowance against the related deferred tax assets.

The following table presents a summary of changes in our unrecognized tax benefits and associated interest and penalties:



(In millions)	Federal, State and Foreign Tax			Accrued Interest and Penalties			Total Gross Unrecognized Income Tax Benefits
Balance at December 31, 2010	$	40.6		$	4.4		$	45.0
Additions for tax positions related to prior years	4.6			2.9			7.5
Reductions for tax positions due to settlements	(5.0		)	(1.1		)	(6.1		)
Reductions due to a lapse of the statute of limitations	(0.3		)	—			(0.3		)
Balance at December 31, 2011	$	39.9		$	6.2		$	46.1
Additions for tax positions related to prior years	(0.1		)	2.1			2.0
Reductions for tax positions due to settlements	(9.3		)	(1.9		)	(11.2		)
Balance at December 31, 2012	$	30.5		$	6.4		$	36.9
Additions for tax positions related to prior years	3.1			0.4			3.5
Additions for tax positions related to current year	3.5			0.3			3.8
Balance at December 31, 2013	$	37.1		$	7.1		$	44.2

At December 31, 2013, 2012 and 2011, there were $41.7 million, $36.4 million and $42.2 million, respectively, of unrecognized tax benefits that if recognized would affect the annual effective tax rate.

It is reasonably possible that within twelve months unrecognized tax benefits related to certain tax reporting positions taken in prior periods could decrease by up to $41.6 million, due to either the expiration of the statute of limitations in certain jurisdictions or the resolution of current income tax examinations, or both.

Our U.S. federal income tax returns for our 2010 and 2011 tax years are under examination by the IRS. In conjunction with this examination, no adjustments to such years’ taxable income have been proposed by the IRS as of December 31, 2013. However, management believes that we are adequately reserved for any matters that may arise from this examination.

In April 2013 we filed a protest with the IRS Appeals Office with respect to proposed adjustments to our federal income tax returns for our 2007, 2008 and 2009 tax years related to our treatment of intercompany transfer pricing. The ultimate outcome of this matter is uncertain. However, management believes we are adequately reserved for this matter as of December 31, 2013.

The following tax years and thereafter remain subject to examination: 2003 for Norway, 2008 for Brazil and 2007 for the United States.

The effective income tax rate was different from the statutory U.S. federal income tax rate due to the following:



	Year Ended December 31,
	2013		2012		2011
Statutory U.S. federal income tax rate	35	%	35	%	35	%
Net difference resulting from:
Foreign earnings subject to different tax rates	(13	)	(12	)	(9	)
Foreign earnings subject to U.S. tax	2		4		1
Nondeductible Multi Phase Meters earn-out adjustments	1		2		—
Net change in unrecognized tax benefits	—		—		1
Settlement of foreign audits	1		—		—
Foreign withholding taxes	3		—		—
Other	1		(1	)	(1	)
Effective income tax rate	30	%	28	%	27	%

We have provided U.S. income taxes on $1,292.0 million of cumulative undistributed earnings of certain foreign subsidiaries where we have determined that the foreign subsidiaries’ earnings are not indefinitely reinvested. No provision for U.S. income taxes has been recorded on earnings of foreign subsidiaries that are indefinitely reinvested. The cumulative balance of foreign earnings with respect to which no provision for U.S. income taxes has been recorded was $1,524.4 million at December 31, 2013. The amount of applicable U.S. income taxes that would be incurred if these earnings were repatriated is approximately $440.0 million.

We benefit from income tax holidays in Singapore and Malaysia which will expire after 2018 for Singapore and 2015 for Malaysia. For the years ended December 31, 2013 and 2012, these tax holidays reduced our provision for income taxes by $12.7 million, or $0.05 per share on a diluted basis, and $9.6 million, or $0.04 per share on a diluted basis, respectively. In the first quarter of 2011, we recognized a retroactive benefit of approximately $7.3 million, or $0.03 per share on a diluted basis, related to tax holidays in Singapore which were retroactive to January 1, 2009.

NOTE 11. PENSION AND OTHER POST-RETIREMENT BENEFIT PLANS

We have funded and unfunded defined benefit pension plans which provide defined benefits based on years of service and final average salary. In October 2009, the Board of Directors amended the U.S. Qualified and Non-Qualified Defined Benefit Pension Plans (“U.S. Pension Plans”) to freeze participation in the U.S. Pension Plans for all new nonunion employees hired on or after January 1, 2010, and current nonunion employees with less than five years of vesting service as of December 31, 2009. For current nonunion employees with less than five years of vesting service as of December 31, 2009, benefits accrued under the U.S. Pension Plans and earned as of that date were frozen based on credited service and pay as of December 31, 2009.

Foreign-based employees are eligible to participate in FMC Technologies-sponsored or government-sponsored benefit plans to which we contribute. Several of the foreign defined benefit pension plans sponsored by us provide for employee contributions; the remaining plans are noncontributory.

We have other post-retirement benefit plans covering substantially all of our U.S. employees who were hired prior to January 1, 2003. The post-retirement health care plans are contributory; the post-retirement life insurance plans are noncontributory.

We are required to recognize the funded status of defined benefit post-retirement plans as an asset or liability in the consolidated balance sheet and recognize changes in that funded status in comprehensive income in the year in which the changes occur. Further, we are required to measure the plan’s assets and its obligations that determine its funded status as of the date of the consolidated balance sheet. We have applied this guidance to our domestic pension and other post-retirement benefit plans as well as for many of our non-U.S. plans, including those in the United Kingdom, Norway, Germany, France and Canada. Pension expense measured in compliance with GAAP for the other non-U.S. pension plans is not materially different from the locally reported pension expense.

The funded status of our U.S. Pension Plans, certain foreign pension plans and U.S. post-retirement health care and life insurance benefit plans, together with the associated balances recognized in our consolidated financial statements as of December 31, 2013 and 2012, were as follows:



	Pensions												Other Post-retirement Benefits
	2013						2012						2013			2012
(In millions)	U.S.			Int’l			U.S.			Int’l
Accumulated benefit obligation	$	513.3		$	360.1		$	614.1		$	290.4
Projected benefit obligation at January 1	$	692.9		$	372.3		$	597.8		$	454.5		$	8.7		$	8.8
Service cost	16.5			14.7			14.6			37.2			0.1			0.1
Interest cost	25.8			16.1			26.9			21.4			0.2			0.4
Actuarial (gain) loss	(119.8		)	45.6			86.5			(1.8		)	(1.7		)	—
Amendments	—			0.6			—			—			—			—
Curtailments	—			—			—			(49.0		)	—			—
Settlements	(11.1		)	—			—			(108.6		)	—			—
Foreign currency exchange rate changes	—			(2.5		)	—			25.9			—			—
Plan participants’ contributions	—			2.2			—			2.0			—			—
Benefits paid	(19.3		)	(10.2		)	(32.9		)	(9.3		)	(0.6		)	(0.6		)
Projected benefit obligation at December 31	585.0			438.8			692.9			372.3			6.7			8.7
Fair value of plan assets at January 1	462.5			327.9			406.0			362.1			—			—
Actual return on plan assets	115.2			52.2			57.5			30.6			—			—
Company contributions	29.5			30.1			31.9			30.8			0.6			0.6
Foreign currency exchange rate changes	—			(1.4		)	—			20.3			—			—
Settlements	(11.1		)	—			—			(108.6		)	—			—
Plan participants’ contributions	—			2.2			—			2.0			—			—
Benefits paid	(19.3		)	(10.2		)	(32.9		)	(9.3		)	(0.6		)	(0.6		)
Fair value of plan assets at December 31	576.8			400.8			462.5			327.9			—			—
Funded status of the plans (liability) at December 31	$	(8.2	)	$	(38.0	)	$	(230.4	)	$	(44.4	)	$	(6.7	)	$	(8.7	)



	Pensions												Other Post-retirement Benefits
	2013						2012						2013			2012
(In millions)	U.S.			Int’l			U.S.			Int’l
Other assets	$	38.3		$	3.8		$	—		$	3.9		$	—		$	—
Current portion of accrued pension and other post-retirement benefits	(9.1		)	(1.3		)	(19.1		)	(1.1		)	(0.6		)	(0.7		)
Accrued pension and other post-retirement benefits, net of current portion	(37.4		)	(40.5		)	(211.3		)	(47.2		)	(6.1		)	(8.0		)
Funded status recognized in the consolidated balance sheets at December 31	$	(8.2	)	$	(38.0	)	$	(230.4	)	$	(44.4	)	$	(6.7	)	$	(8.7	)

The following table summarizes the amounts in accumulated other comprehensive (income) loss that have not been recognized as components of net periodic benefit cost for the years ended December 31, 2013, 2012 and 2011:



	Pensions										Other Post-retirement Benefits
	2013					2012					2013			2012
(In millions)	U.S.		Int’l			U.S.		Int’l
Amounts recognized in accumulated other comprehensive (income) loss:
Unrecognized actuarial (gain) loss	$	130.1	$	113.6		$	355.0	$	103.3		$	(3.2	)	$	(1.7	)
Unrecognized prior service (credit) cost	0.1		1.5			0.1		1.0			—			(0.5		)
Unrecognized transition asset	—		(0.4		)	—		(0.5		)	—			—
Accumulated other comprehensive (income) loss at December 31	$	130.2	$	114.7		$	355.1	$	103.8		$	(3.2	)	$	(2.2	)

The following tables summarize the projected and accumulated benefit obligations and fair values of plan assets where the projected or accumulated benefit obligation exceeds the fair value of plan assets at December 31, 2013 and 2012:



	Pensions								Other Post-retirement Benefits
	2013				2012				2013		2012
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded projected benefit obligation:
Aggregate projected benefit obligation	$	46.4	$	151.8	$	692.9	$	285.1	$	6.7	$	8.7
Aggregate fair value of plan assets	$	—	$	110.1	$	462.5	$	236.9	$	—	$	—



	Pensions								Other Post-retirement Benefits
	2013				2012				2013	2012
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded accumulated benefit obligation:
Aggregate accumulated benefit obligation	$	36.2	$	28.9	$	614.1	$	31.3
Aggregate fair value of plan assets	$	—	$	9.0	$	462.5	$	9.3

The following table summarizes the components of net periodic benefit cost (income) for the years ended December 31, 2013, 2012 and 2011:



	Pensions																		Other Post-retirement Benefits
	2013						2012						2011						2013			2012			2011
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l
Components of net annual benefit cost (income):
Service cost	$	16.5		$	14.7		$	14.6		$	37.2		$	12.0		$	29.5		$	0.1		$	0.1		$	0.1
Interest cost	25.8			16.1			26.9			21.4			26.1			20.3			0.2			0.4			0.4
Expected return on plan assets	(41.6		)	(23.7		)	(39.9		)	(26.4		)	(38.2		)	(24.5		)	—			—			—
Settlement cost	5.1			—			5.6			8.5			8.9			—			—			—			—
Amortization of transition asset	—			(0.1		)	—			(0.2		)	—			(0.5		)	—			—			—
Amortization of prior service cost (credit)	(0.1		)	0.1			(0.1		)	0.1			(0.1		)	0.1			(0.5		)	(1.1		)	(1.3		)
Amortization of net actuarial loss (gain)	26.6			5.3			23.9			8.1			12.9			5.0			(0.2		)	(0.2		)	(0.2		)
Net periodic benefit cost (income)	$	32.3		$	12.4		$	31.0		$	48.7		$	21.6		$	29.9		$	(0.4	)	$	(0.8	)	$	(1.0	)

The following table summarizes changes in plan assets and benefit obligations recognized in other comprehensive income (loss) for the years ended December 31, 2013, 2012 and 2011:



	Pensions																		Other Post-retirement Benefits
	2013						2012						2011						2013			2012			2011
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l
Changes in plan assets and benefit obligations recognized in other comprehensive income (loss):
Net actuarial gain (loss) arising during period	$	193.3		$	(15.6	)	$	(68.9	)	$	53.8		$	(137.3	)	$	(61.9	)	$	1.7		$	—		$	(0.5	)
Prior service cost arising during period	—			(0.6		)	—			—			(0.9		)	—			—			—			—
Settlements	5.1			—			5.6			8.5			—			—			—			—			—
Amortization of net actuarial loss (gain)	26.6			5.3			23.9			8.0			21.8			5.0			(0.2		)	(0.2		)	(0.2		)
Amortization of prior service cost (credit)	(0.1		)	0.1			(0.1		)	0.1			(0.1		)	0.1			(0.5		)	(1.1		)	(1.3		)
Amortization of transition asset	—			(0.1		)	—			(0.2		)	—			(0.5		)	—			—			—
Total recognized in other comprehensive income (loss)	$	224.9		$	(10.9	)	$	(39.5	)	$	70.2		$	(116.5	)	$	(57.3	)	$	1.0		$	(1.3	)	$	(2.0	)

Included in accumulated other comprehensive income (loss) at December 31, 2013, are noncash, pretax charges which have not yet been recognized in net periodic benefit cost (income). The estimated amounts that will be amortized from the portion of each component of accumulated other comprehensive income (loss) as a component of net period benefit cost (income), during the next fiscal year are as follows:



	Pensions						Other Post-retirement Benefits
(In millions)	U.S.			Int’l
Net actuarial losses (gains)	$	12.2		$	6.8		$	(0.2	)
Prior service cost (credit)	$	(0.1	)	$	0.1		$	—
Transition asset	$	—		$	(0.1	)	$	—

Key assumptions—The following weighted-average assumptions were used to determine the benefit obligations:



	Pensions								Other Post-retirement Benefits
	2013				2012				2013		2012
	U.S.		Int’l		U.S.		Int’l
Discount rate	5.10	%	4.30	%	3.90	%	4.46	%	5.10	%	3.90	%
Rate of compensation increase	4.00	%	4.29	%	4.00	%	3.97	%	—		—

The following weighted-average assumptions were used to determine net periodic benefit cost:



	Pensions												Other Post-retirement Benefits
	2013				2012				2011				2013		2012		2011
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Discount rate	3.90	%	4.46	%	4.60	%	4.54	%	5.39	%	5.00	%	3.90	%	4.60	%	5.40	%
Rate of compensation increase	4.00	%	3.98	%	4.00	%	4.05	%	4.00	%	4.20	%	—		—		—
Expected rate of return on plan assets	9.00	%	7.44	%	9.00	%	7.62	%	9.00	%	6.98	%	—		—		—

Our estimate of expected rate of return on plan assets is primarily based on the historical performance of plan assets, current market conditions, our asset allocation and long-term growth expectations.

Plan assets—Our pension investment strategy emphasizes maximizing returns consistent with balancing risk. Excluding our international plans with insurance-based investments, 89% of our total pension plan assets represent the U.S. qualified plan, the U.K. plan and the Canadian plan. These plans are primarily invested in equity securities to maximize the long-term returns of the plans. The investment managers of these assets, including the hedge funds and limited partnerships, use Graham and Dodd fundamental investment analysis to select securities that have a margin of safety between the price of the security and the estimated value of the security. This value-oriented approach tends to mitigate the risk of a large equity allocation.

The following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2013 and 2012.


•	Cash is valued at cost, which approximates fair value.

•

Equity securities are comprised of common stock, preferred stock, registered investment companies and common/collective trusts. The fair values of equity securities are valued at the closing price reported on the active market on which the securities are traded. The fair values of registered investment companies and common/collective trusts are valued based on quoted market prices, which represent the net asset value (“NAV”) of shares held, and primarily include investments in equity securities.


•	The fair values of hedge funds are valued using the NAV as determined by the administrator or custodian of the fund.


•	The fair values of limited partnerships are valued using the NAV as determined by the administrator or custodian of the fund.


•	Insurance contracts are valued at book value, which approximates fair value, and is calculated using the prior-year balance plus or minus investment returns and changes in cash flows.


•	Emerging market bonds are comprised of registered investment companies. The fair values of registered investment companies are valued based on quoted market prices, which represent the NAV of shares held.

Our pension plan assets measured at fair value are as follows at December 31, 2013 and 2012. Please refer to “Fair value measurements” in Note 1 to these consolidated financial statements for a description of the levels.



	U.S.								International
December 31, 2013 (In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Cash	$	32.4	$	32.4	$	—	$	—	$	1.1	$	1.1	$	—	$	—
Equity securities:
U.S. companies:
Large cap	169.9		169.9		—		—		60.7		60.7		—		—
Mid cap	12.1		12.1		—		—		0.1		0.1		—		—
Small cap	98.0		98.0		—		—		—		—		—		—
International companies	142.9		142.9		—		—		231.9		231.9		—		—
Hedge funds	64.9		—		—		64.9		—		—		—		—
Limited partnerships	52.1		—		—		52.1		—		—		—		—
Insurance contracts	—		—		—		—		107.0		—		107.0		—
Emerging market bonds	4.5		4.5		—		—		—		—		—		—
Total assets	$	576.8	$	459.8	$	—	$	117.0	$	400.8	$	293.8	$	107.0	$	—
December 31, 2012 (In millions)
Cash	$	35.7	$	35.7	$	—	$	—	$	1.0	$	1.0	$	—	$	—
Equity securities:
U.S. companies:
Large cap	127.0		127.0		—		—		47.2		47.2		—		—
Mid cap	9.4		9.4		—		—		0.1		0.1		—		—
Small cap	73.7		73.7		—		—		—		—		—		—
International companies	116.4		116.4		—		—		182.3		182.3		—		—
Hedge funds	55.6		—		—		55.6		—		—		—		—
Limited partnerships	40.1		—		—		40.1		—		—		—		—
Insurance contracts	—		—		—		—		97.3		—		97.3		—
Emerging market bonds	4.6		4.6		—		—		—		—		—		—
Total assets	$	462.5	$	366.8	$	—	$	95.7	$	327.9	$	230.6	$	97.3	$	—

The summary of changes in the fair value of the pension plan Level 3 assets for the years ended December 31, 2013 and 2012 is as follows:



(In millions)	Level 3 Assets
Balance at December 31, 2011	$	86.1
Realized gains	0.8
Unrealized gains relating to instruments still held at the reporting date	9.7
Purchases, sales, and settlements, net	(0.9		)
Balance at December 31, 2012	$	95.7
Unrealized gains relating to instruments still held at the reporting date	21.3
Balance at December 31, 2013	$	117.0

Contributions—We expect to contribute approximately $21.0 million to our international pension plans, representing primarily the U.K. and Norway qualified pension plans, and approximately $9.0 million to our U.S. Non-Qualified Defined Benefit Pension Plan in 2014. All of the contributions are expected to be in the form of cash. In 2013 and 2012, we contributed $59.6 million and $62.7 million to the pension plans, respectively, which included $18.0 million and $13.5 million, respectively, to the U.S. Qualified Defined Benefit Pension Plan.

Estimated future benefit payments—The following table summarizes expected benefit payments from our various pension and post-retirement benefit plans through 2023. Actual benefit payments may differ from expected benefit payments.



	Pensions				Other Post-retirement Benefits
(In millions)	U.S.		International
2014	$	28.2	$	10.5	$	0.6
2015	$	22.7	$	11.6	$	0.6
2016	$	24.6	$	11.9	$	0.6
2017	$	38.5	$	12.7	$	0.6
2018	$	28.1	$	14.5	$	0.6
2019-2023	$	172.9	$	93.6	$	2.7

Savings plans—The FMC Technologies, Inc. Savings and Investment Plan (“Qualified Plan”), a qualified salary reduction plan under Section 401(k) of the Internal Revenue Code, is a defined contribution plan. Additionally, we have a non-qualified deferred compensation plan, the Non-Qualified Plan, which allows certain highly compensated employees the option to defer the receipt of a portion of their salary. We match a portion of the participants’ deferrals to both plans. In October 2009, the Board of Directors approved amendments to the U.S. Qualified Plan and U.S. Non-Qualified Plan (“Amended Plans”). Under the Amended Plans, we are required to make a nonelective contribution every pay period to all new nonunion employees hired on or after January 1, 2010, and current nonunion employees with less than five years of vesting service as of December 31, 2009. The vesting schedule for the nonelective contribution under the Amended Plans is three years of vesting service with FMC Technologies.

Participants in the Non-Qualified Plan earn a return based on hypothetical investments in the same options as our 401(k) plan, including FMC Technologies stock. Changes in the market value of these participant investments are reflected as an adjustment to the deferred compensation liability with an offset to other income (expense), net. As of December 31, 2013 and 2012, our liability for the Non-Qualified Plan was $38.5 million and $34.4 million, respectively, and was recorded in other non-current liabilities. We hedge the financial impact of changes in the participants’ hypothetical investments by purchasing the investments that the participants have chosen. With the exception of FMC Technologies stock, which is maintained at its cost basis, changes in the fair value of these investments are recognized as an offset to other income (expense), net. As of December 31, 2013 and 2012, we had investments for the Non-Qualified Plan totaling $29.1 million and $26.0 million, respectively, at fair market value and FMC Technologies stock held in trust of $7.7 million and $7.8 million, respectively, at its cost basis. Please refer to Note 15 to these consolidated financial statements for fair value disclosure of the Non-Qualified Plan investments.

We recognized expense of $23.5 million, $18.4 million and $14.6 million, for matching contributions to these plans in 2013, 2012 and 2011, respectively. Additionally, we recognized expense of $16.2 million, $11.8 million, and $8.4 million for nonelective contributions in 2013, 2012 and 2011, respectively.

NOTE 12. STOCK-BASED COMPENSATION

We sponsor a stock-based compensation plan, which is described below, and have primarily granted awards in the form of nonvested stock units (also known as restricted stock units in the plan document) and stock options. The compensation expense for awards under the plan is as follows:



	Year Ended December 31,
(In millions)	2013		2012		2011
Stock-based compensation expense	$	47.7	$	34.0	$	26.3
Income tax benefits related to stock-based compensation expense	$	16.2	$	11.5	$	8.9

Stock-based compensation expense is recognized over the lesser of the stated vesting period (three or four years) or the period until the employee reaches age 62 (the retirement eligible age under the plan). As of December 31, 2013, a portion of the stock-based compensation expense related to outstanding awards remains to be recognized in future periods. The compensation expense related to nonvested awards to employees yet to be recognized totaled $40.6 million for restricted stock units. These costs are expected to be recognized over a weighted average period of 1.4 years.

Incentive compensation and stock plan—The Amended and Restated FMC Technologies, Inc. Incentive Compensation and Stock Plan (the “Plan”) provides certain incentives and awards to officers, employees, directors and consultants of FMC Technologies or its affiliates. The Plan allows our Board of Directors to make various types of awards to non-employee directors and the Compensation Committee (the “Committee”) of the Board of Directors to make various types of awards to other eligible individuals. Awards include management incentive awards, stock options, stock appreciation rights, performance units, stock units, restricted stock or other awards authorized under the Plan. All awards are subject to the Plan’s provisions.

Under the Plan, 48.0 million shares of our common stock were authorized for awards. These shares are in addition to shares previously granted by FMC Corporation and converted into approximately 18.0 million shares of our common stock. As of December 31, 2013, 3.2 million shares were reserved to satisfy existing awards and 20.9 million shares were available for future awards.

Management incentive awards may be awards of cash, common stock, restricted stock or a combination thereof. Grants of stock options may be incentive and/or nonqualified stock options. The exercise price for options are determined by the Committee but cannot be less than the fair market value of our common stock at the grant date. Restricted stock and restricted stock unit grants specify any applicable performance goals, the time and rate of vesting and such other provisions as determined by the Committee. Restricted stock unit grants generally vest after three to four years of service. Additionally, most awards immediately vest upon a change of control as defined in the Plan document.

Under the Plan, our Board of Directors has the authority to grant non-employee directors stock options, restricted stock and restricted stock units. Unless otherwise determined by our Board of Directors, awards to non-employee directors generally vest on the date of our annual stockholder meeting following the date of grant. Restricted stock units are not settled until a director ceases services to the Board of Directors. At December 31, 2013, outstanding awards to active and retired non-employee directors included 826 thousand stock units.

Restricted stock units—A summary of the nonvested restricted stock units to employees as of December 31, 2013, and changes during the year is presented below:



(Shares in thousands)	Shares		Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2012	2,745		$	37.43
Granted	935		$	53.01
Vested	(1,159	)	$	27.16
Cancelled/forfeited	(57	)	$	43.17
Nonvested at December 31, 2013	2,464		$	48.04

For current year performance-based awards, the payout was dependent upon our performance relative to a peer group of companies with respect to earnings growth and return on investment for the year ended December 31, 2013. Based on results for the performance period, the payout will be 343 thousand shares at the vesting date in January 2016. Compensation cost was measured for 2013 based on the actual outcome of the performance conditions.

For current year market-based awards, the payout was contingent upon our performance relative to the same peer group of companies with respect to total stockholder return (“TSR”) for the year ended December 31, 2013. In 2012, the Committee modified the payout with respect to the TSR metric to make it possible to have a payout regardless of whether our TSR for the year is positive or negative. If our TSR for any given year is not positive, the payout with respect to TSR is limited to the target previously established by the Committee. Based on results for the performance period, the payout will be 86 thousand shares. Compensation cost for these awards was calculated using the grant date fair market value, as estimated using a Monte Carlo simulation, and is not subject to change based on future events.

The following summarizes values for restricted stock unit activity to employees:



	Year Ended December 31,
	2013		2012		2011
Weighted average grant date fair value of restricted stock units granted	$	53.01	$	49.84	$	40.84
Vest date fair value of restricted stock units vested (in millions)	$	51.5	$	100.8	$	47.3

On January 2, 2014, restricted stock units vested and approximately 0.7 million shares were issued to employees.

NOTE 13. STOCKHOLDERS’ EQUITY

Capital stock —The following is a summary of our capital stock activity for the years ended December 31, 2013, 2012 and 2011:



(Number of shares in thousands)	Common Stock Issued	Common Stock Held in Employee Benefit Trust		Common Stock Held in Treasury
December 31, 2010	286,318	132		46,545
Stock awards	—	—		(975	)
Treasury stock purchases	—	—		2,746
Net stock purchased for (sold from) employee benefit trust	—	37		—
December 31, 2011	286,318	169		48,316
Stock awards	—	—		(1,393	)
Treasury stock purchases	—	—		2,138
Net stock purchased for (sold from) employee benefit trust	—	27		—
December 31, 2012	286,318	196		49,061
Stock awards	—	—		(998	)
Treasury stock purchases	—	—		2,255
Net stock purchased for (sold from) employee benefit trust	—	(16	)	—
December 31, 2013	286,318	180		50,318

The plan administrator of the Non-Qualified Plan purchases shares of our common stock on the open market. Such shares are placed in a trust owned by FMC Technologies.

As of August 2007, our Board of Directors had authorized the repurchase of up to 30 million shares of our outstanding common stock through open market purchases. As a result of the two-for-one stock split completed on March 31, 2011, the authorization was increased to 60 million shares. In December 2011, the Board of Directors authorized an extension of our repurchase program, adding 15 million shares, for a total of 75 million shares.

We repurchased $116.3 million, $91.1 million and $114.0 million of common stock during 2013, 2012 and 2011, respectively, under the authorized repurchase program. As of December 31, 2013, approximately 12.9 million shares remained available for purchase under the current program which may be executed from time to time in the open market. We intend to hold repurchased shares in treasury for general corporate purposes, including issuances under our employee incentive compensation and stock plans. Treasury shares are accounted for using the cost method.

On May 12, 2011, we amended our Amended and Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 300 million to 600 million shares.

No cash dividends were paid on our common stock in 2013, 2012 or 2011.

Accumulated other comprehensive loss—Accumulated other comprehensive loss consisted of the following:



(In millions)	Foreign Currency Translation			Hedging			Defined Pension and Other Post-Retirement Benefits			Accumulated Other Comprehensive Loss
December 31, 2011	$	(102.8	)	$	(16.7	)	$	(324.3	)	$	(443.8	)
Other comprehensive income (loss) before reclassifications, net of tax	(1.8		)	29.0			(5.1		)	22.1
Reclassification adjustment for net (gains) losses included in net income, net of tax	—			(2.3		)	28.0			25.7
Other comprehensive income (loss), net of tax	(1.8		)	26.7			22.9			47.8
December 31, 2012	(104.6		)	10.0			(301.4		)	(396.0		)
Other comprehensive income (loss) before reclassifications, net of tax	(99.7		)	27.1			112.1			39.5
Reclassification adjustment for net (gains) losses included in net income, net of tax	—			(5.2		)	21.0			15.8
Other comprehensive income (loss), net of tax	(99.7		)	21.9			133.1			55.3
December 31, 2013	$	(204.3	)	$	31.9		$	(168.3	)	$	(340.7	)

Reclassifications out of accumulated other comprehensive loss—Reclassifications out of accumulated other comprehensive loss consisted of the following:



	Twelve Months Ended
(In millions)	December 31, 2013
Details about Accumulated Other Comprehensive Loss Components	Amount Reclassified out of Accumulated Other Comprehensive Loss			Affected Line Item in the Consolidated Statement of Income
Gains (losses) on hedging instruments
Foreign exchange contracts:	$	(11.7	)	Revenue
	14.8			Costs of sales
	—			Selling, general and administrative expense
	3.1			Income before income taxes
	2.1			Income tax (expense) benefit
	$	5.2		Net income
Defined pension and other post-retirement benefits
Settlements	$	(5.1	)	^(a)
Amortization of actuarial loss	(31.7		)	^(a)
Amortization of prior service credit	0.5			^(a)
Amortization of transition asset	0.1			^(a)
	(36.2		)	Income before income taxes
	15.2			Income tax (expense) benefit
	$	(21.0	)	Net income

_______________________


^(a)	These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 11 for additional details).

NOTE 14. DERIVATIVE FINANCIAL INSTRUMENTS

We hold derivative financial instruments for the purpose of hedging the risks of certain identifiable and anticipated transactions. The types of risks hedged are those relating to the variability of future earnings and cash flows caused by movements in foreign currency exchange rates and interest rates. We hold the following types of derivative instruments:

Foreign exchange rate forward contracts – The purpose of these instruments is to hedge the risk of changes in future cash flows of anticipated purchase or sale commitments denominated in foreign currencies. At December 31, 2013, we held the following material positions:



	Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Argentinian peso	(110.4	)	(16.9	)
Brazilian real	(118.8	)	(50.7	)
British pound	139.7		231.1
Canadian dollar	46.5		43.8
Chinese renminbi	89.3		14.8
Euro	176.7		243.1
Kuwaiti dinar	(7.2	)	(25.6	)
Malaysian ringgit	109.0		33.3
Norwegian krone	3,621.9		596.9
Polish zloty	30.1		10.0
Russian ruble	(1,771.2	)	(53.9	)
Singapore dollar	184.5		146.8
Swedish krona	134.7		21.0
Swiss franc	15.8		17.7
U.S. dollar	(1,186.2	)	(1,186.2	)

Foreign exchange rate instruments embedded in purchase and sale contracts – The purpose of these instruments is to match offsetting currency payments and receipts for particular projects, or comply with government restrictions on the currency used to purchase goods in certain countries. At December 31, 2013, our portfolio of these instruments included the following material positions:



	Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Brazilian real	(54.8	)	(23.4	)
British pound	9.9		16.3
U.S. dollar	11.0		11.0

The purpose of our foreign currency hedging activities is to manage the volatility associated with anticipated foreign currency purchases and sales created in the normal course of business. We primarily utilize forward exchange contracts with maturities of less than three years.

Our policy is to hold derivatives only for the purpose of hedging risks and not for trading purposes where the objective is solely to generate profit. Generally, we enter into hedging relationships such that changes in the fair values or cash flows of the transactions being hedged are expected to be offset by corresponding changes in the fair value of the derivatives. For derivative instruments that qualify as a cash flow hedge, the effective portion of the gain or loss of the derivative, which does not include the time value component of a forward currency rate, is reported as a component of other comprehensive income (“OCI”) and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings.

The following table of all outstanding derivative instruments is based on estimated fair value amounts that have been determined using available market information and commonly accepted valuation methodologies. Refer to Note 15 to these consolidated financial statements for further disclosures related to the fair value measurement process. Accordingly, the estimates presented may not be indicative of the amounts that we would realize in a current market exchange and may not be indicative of the gains or losses we may ultimately incur when these contracts settle or mature.



	December 31, 2013				December 31, 2012
(In millions)	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	$	149.3	$	152.5	$	29.2	$	23.2
Long-term – Derivative financial instruments	65.4		44.1		5.7		8.3
Total derivatives designated as hedging instruments	214.7		196.6		34.9		31.5
Derivatives not designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	16.6		18.8		44.2		27.2
Long-term – Derivative financial instruments	3.1		3.0		3.5		2.8
Total derivatives not designated as hedging instruments	19.7		21.8		47.7		30.0
Total derivatives	$	234.4	$	218.4	$	82.6	$	61.5

We recognized gains of $0.1 million, $4.4 million and $0.9 million on cash flow hedges for the years ended December 31, 2013, 2012 and 2011, respectively, due to hedge ineffectiveness as it was probable that the original forecasted transaction would not occur. Cash flow hedges of forecasted transactions, net of tax, resulted in accumulated other comprehensive gains of $31.9 million and $10.0 million at December 31, 2013 and 2012, respectively. We expect to transfer an approximate $10.5 million gain from accumulated OCI to earnings during the next 12 months when the anticipated transactions actually occur. All anticipated transactions currently being hedged are expected to occur by the end of 2016.

The following tables present the impact of derivative instruments in cash flow hedging relationships and their location within the accompanying consolidated statements of income.



	Gain (Loss) Recognized in OCI (Effective Portion)
	Year Ended December 31,
(In millions)	2013		2012		2011
Interest rate contracts	$	—	$	1.6	$	1.2
Foreign exchange contracts	24.1		41.9		(10.2		)
Total	$	24.1	$	43.5	$	(9.0	)



Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Gain (Loss) Reclassified From Accumulated OCI into Income (Effective Portion)
	Year Ended December 31,
(In millions)	2013			2012			2011
Foreign exchange contracts:
Revenue	$	(11.7	)	$	6.6		$	26.8
Cost of sales	14.8			(1.9		)	(0.5		)
Selling, general and administrative expense	—			(0.2		)	0.5
Total	$	3.1		$	4.5		$	26.8



Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	Year Ended December 31,
(In millions)	2013			2012			2011
Foreign exchange contracts:
Revenue	$	2.7		$	13.7		$	24.8
Cost of sales	(11.0		)	(17.6		)	(17.5		)
Total	$	(8.3	)	$	(3.9	)	$	7.3

Instruments that are not designated as hedging instruments are executed to hedge the effect of exposures in the consolidated balance sheets, and occasionally forward foreign currency contracts or currency options are executed to hedge exposures which do not meet all of the criteria to qualify for hedge accounting.



Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income on Derivatives (Instruments Not Designated as Hedging Instruments)
	Year Ended December 31,
(In millions)	2013			2012			2011
Foreign exchange contracts:
Revenue	$	0.6		$	4.9		$	16.2
Cost of sales	(0.2		)	(0.2		)	(1.5		)
Other income (expense), net	(15.0		)	6.4			(3.1		)
Total	$	(14.6	)	$	11.1		$	11.6

Balance Sheet Offsetting—We execute derivative contracts only with counterparties that consent to a master netting agreement which permits net settlement of the gross derivative assets against gross derivative liabilities. Each instrument is accounted for individually and assets and liabilities are not offset. As of December 31, 2013, we had no collateralized derivative contracts. The following tables present both gross information and net information of recognized derivative instruments:



	December 31, 2013							December 31, 2012
(In millions)	Gross Amount Recognized		Gross Amounts Not Offset Permitted Under Master Netting Agreements			Net Amount		Gross Amount Recognized		Gross Amounts Not Offset Permitted Under Master Netting Agreements			Net Amount
Derivative assets	$	234.4	$	(198.5	)	$	35.9	$	82.6	$	(47.1	)	$	35.5



	December 31, 2013							December 31, 2012
(In millions)	Gross Amount Recognized		Gross Amounts Not Offset Permitted Under Master Netting Agreements			Net Amount		Gross Amount Recognized		Gross Amounts Not Offset Permitted Under Master Netting Agreements			Net Amount
Derivative liabilities	$	218.4	$	(198.5	)	$	19.9	$	61.5	$	(47.1	)	$	14.4

NOTE 15. FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis were as follows:



	December 31, 2013								December 31, 2012
(In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Assets
Investments:
Equity securities	$	21.2	$	21.2	$	—	$	—	$	17.2	$	17.2	$	—	$	—
Fixed income	13.2		13.2		—		—		11.6		11.6		—		—
Money market fund	3.8		—		3.8		—		2.6		—		2.6		—
Stable value fund	1.0		—		1.0		—		1.3		—		1.3		—
Other	2.4		2.4		—		—		2.9		2.9		—		—
Derivative financial instruments:
Foreign exchange contracts	234.4		—		234.4		—		82.6		—		82.6		—
Total assets	$	276.0	$	36.8	$	239.2	$	—	$	118.2	$	31.7	$	86.5	$	—
Liabilities
Derivative financial instruments:
Foreign exchange contracts	218.4		—		218.4		—		61.5		—		61.5		—
Contingent earn-out consideration	70.1		—		—		70.1		105.3		—		—		105.3
Total liabilities	$	288.5	$	—	$	218.4	$	70.1	$	166.8	$	—	$	61.5	$	105.3

Investments—The fair value measurement of our equity securities, fixed income and other investment assets is based on quoted prices that we have the ability to access in public markets. Our stable value fund and money market fund are valued at the net asset value of the shares held at the end of the year, which is based on the fair value of the underlying investments using information reported by the investment advisor at year-end. Certain prior-year amounts have been reclassified to conform to the current year's presentation. See Note 11 to these consolidated financial statements for additional disclosure related to our non-qualified deferred compensation plan investments.

Derivative financial instruments—We use the income approach as the valuation technique to measure the fair value of foreign currency derivative instruments on a recurring basis. This approach calculates the present value of the future cash flow by measuring the change from the derivative contract rate and the published market indicative currency rate, multiplied by the contract notional values. Credit risk is then incorporated by reducing the derivative’s fair value in asset positions by the result of multiplying the present value of the portfolio by the counterparty’s published credit spread. Portfolios in a liability position are adjusted by the same calculation; however, a spread representing our credit spread is used. Our credit spread and the credit spread of other counterparties not publicly available are approximated by using the spread of similar companies in the same industry, of similar size and with the same credit rating.

At the present time, we have no credit-risk-related contingent features in our agreements with the financial institutions that would require us to post collateral for derivative positions in a liability position.

See Note 14 to these consolidated financial statements for additional disclosure related to derivative financial instruments.

Multi Phase Meters contingent earn-out consideration—We determined the fair value of the contingent earn-out consideration using a discounted cash flow model. The key assumptions used in applying the income approach are the expected profitability and debt, net of cash, of the acquired company during the earn-out period and the discount rate which approximates our debt credit rating. The fair value measurement is based upon significant inputs not observable in the market. Changes in the value of the contingent earn-out consideration are recorded as cost of service or other revenue in our consolidated statements of income.

Changes in the fair value of our Level 3 contingent earn-out consideration obligation were as follows:



	December 31,
(In millions)	2013			2012
Balance at beginning of year	$	105.3		$	57.5
Remeasurement adjustment	28.7			42.0
Payment	(57.3		)	—
Foreign currency translation adjustment	(6.6		)	5.8
Balance at end of year	$	70.1		$	105.3

Fair value of debt—At December 31, 2013, the fair value, based on Level 1 quoted market rates, of our 2.00% Notes due 2017 and 3.45% Notes due 2022 (collectively, “Senior Notes”) was approximately $767.6 million as compared to the $800.0 million face value of the debt, net of issue discounts, recorded in the consolidated balance sheet.

Other fair value disclosures—The carrying amounts of cash and cash equivalents, trade receivables, accounts payable, short-term debt, commercial paper, debt associated with our term loan, revolving credit facility as well as amounts included in other current assets and other current liabilities that meet the definition of financial instruments, approximate fair value.

Credit risk—By their nature, financial instruments involve risk including credit risk for non-performance by counterparties. Financial instruments that potentially subject us to credit risk primarily consist of trade receivables and derivative contracts. We manage the credit risk on financial instruments by transacting only with what management believes are financially secure counterparties, requiring credit approvals and credit limits, and monitoring counterparties’ financial condition. Our maximum exposure to credit loss in the event of non-performance by the counterparty is limited to the amount drawn and outstanding on the financial instrument. Allowances for losses on trade receivables are established based on collectability assessments. We mitigate credit risk on derivative contracts by executing contracts only with counterparties that consent to a master netting agreement which permits the net settlement of the gross derivative assets against the gross derivative liabilities.

NOTE 16. RELATED PARTY TRANSACTIONS

John Bean Technologies Corporation (“JBT”)—On July 31, 2008, the spin-off of our FoodTech and Airport Systems businesses to our stockholders was accomplished through a tax-free dividend of all outstanding shares of JBT, now an independent public company traded on the New York Stock Exchange (symbol “JBT”).

We entered into certain agreements which defined key provisions related to the spin-off and the relationship between the two companies after the spin-off, including, among others, a Separation and Distribution Agreement, dated July 31, 2008, between FMC Technologies and JBT (the “JBT Separation and Distribution Agreement”) and a tax sharing agreement, dated July 31, 2008, between FMC Technologies and JBT (the “JBT Tax Sharing Agreement”). The JBT Separation and Distribution Agreement required us to contribute certain business segments and their associated assets and liabilities to JBT. As a result of the contribution, we have no interest in JBT’s assets and business and, subject to certain exceptions described below, generally have no obligation with respect to JBT’s liabilities. Similarly, JBT has no interest in our assets and generally has no obligation with respect to our liabilities related to retained businesses after the distribution. We generally made no representations or warranties as to the assets, businesses or liabilities transferred or assumed as part of the contribution, and generally made the transfers on an “as is, where is” basis. JBT agreed to use its reasonable best efforts to cause us to be released from all of FMC Technologies’ obligations to guarantee or otherwise support any liabilities or obligations of JBT not later than July 31, 2010. All such obligations have expired, been released or are subject to a novation agreement. In addition, JBT agreed to reimburse and otherwise indemnify and hold us harmless for any and all costs and charges associated with, and such liabilities or obligations of, JBT or any guarantee to third parties not terminated prior to July 31, 2008.

As parties to the JBT Separation and Distribution Agreement, FMC Technologies and JBT each indemnify the other party from liabilities arising from their respective businesses or contracts, from liabilities arising from breach of the JBT Separation and Distribution Agreement and from certain claims made prior to the spin-off of JBT (Note 18).

The JBT Tax Sharing Agreement sets forth the responsibilities of the parties with respect to, among other things, liabilities for federal, state, local and foreign taxes for periods before and including the spin-off, the preparation and filing of tax returns for such periods and disputes with taxing authorities regarding taxes for such periods. The JBT Tax Sharing Agreement also provides that JBT will indemnify us for any tax liability we may incur as a result of any action taken by JBT after the spin-off that causes the distribution to not qualify as tax-free for U.S. federal income tax purposes under the terms of the private letter ruling received from the IRS. We will indemnify JBT against any tax liability in the case any action taken by us causes the distribution to not qualify as tax-free.

FMC Corporation—FMC Technologies was a subsidiary of FMC Corporation until the distribution of FMC Technologies’ common stock by FMC Corporation, which was completed on December 31, 2001.

In June 2001, FMC Corporation contributed to us substantially all of the assets and liabilities of the businesses that comprise FMC Technologies (the “Separation”). FMC Technologies and FMC Corporation entered into certain agreements that defined key provisions related to the Separation and the ongoing relationship between the two companies after the Separation. These agreements included a Separation and Distribution Agreement, dated May 31, 2001 (the “SDA”), and a Tax Sharing Agreement, which provided that FMC Technologies and FMC Corporation would make payments between them as appropriate to properly allocate tax liabilities for pre-Separation periods.

As parties to the SDA, FMC Corporation and FMC Technologies each indemnify the other party from liabilities arising from their respective businesses or contracts, from liabilities arising from breach of the SDA, from certain claims made prior to our spin-off from FMC Corporation and for claims related to discontinued operations (Note 18).

NOTE 17. WARRANTY OBLIGATIONS

Warranty cost and accrual information is as follows:



	December 31,
(In millions)	2013			2012
Balance at beginning of year	$	15.4		$	25.7
Expenses for new warranties	27.0			26.4
Adjustments to existing accruals	1.5			3.5
Claims paid	(25.9		)	(40.2		)
Balance at end of year	$	18.0		$	15.4

NOTE 18. COMMITMENTS AND CONTINGENT LIABILITIES

Commitments associated with leases—We lease office space, manufacturing facilities and various types of manufacturing and data processing equipment. Leases of real estate generally provide for payment of property taxes, insurance and repairs by us. Substantially all of our leases are classified as operating leases. Rent expense under operating leases amounted to $149.7 million, $133.9 million and $100.6 million in 2013, 2012 and 2011, respectively.

At December 31, 2013, future minimum rental payments under noncancellable operating leases were:



	(In millions)
2014	$	113.4
2015	92.2
2016	85.6
2017	64.4
2018	57.1
Thereafter	186.3
Total	599.0
Less income from subleases	4.7
Net minimum operating lease payments	$	594.3

Contingent liabilities associated with guarantees—In the ordinary course of business with customers, vendors and others, we issue standby letters of credit, performance bonds, surety bonds and other guarantees. These financial instruments at December 31, 2013, represented $785.7 million for guarantees of our future performance and $61.1 million of bank guarantees and letters of credit to secure a portion of our existing financial obligations. The majority of these financial instruments expire within three years, and we expect to replace them through the issuance of new or the extension of existing letters of credit and surety bonds.

Management believes the ultimate resolution of our known contingencies will not materially affect our consolidated financial position, results of operations, or cash flows.

Contingent liabilities associated with legal matters—We are involved in various pending or potential legal actions in the ordinary course of our business. Management is unable to predict the ultimate outcome of these actions, because of the inherent uncertainty of litigation. However, management believes that the most probable, ultimate resolution of these matters will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

In addition, under the SDA between FMC Corporation and FMC Technologies, which contains key provisions relating to our 2001 spin-off from FMC Corporation, FMC Corporation is required to indemnify us for certain claims made prior to the spin-off, as well as for other claims related to discontinued operations. We expect that FMC Corporation will bear responsibility for the majority of these claims. Under the JBT Separation and Distribution Agreement, which contains key provisions relating to the spin-off of the Airport and FoodTech businesses from us in 2008, JBT is required to indemnify us for certain claims made prior to the spin-off, as well as for other claims related to JBT products or business operations. Some of these claims may include those described in this paragraph involving FMC Corporation. While the ultimate responsibility for claims involving FMC Technologies, FMC Corporation or JBT cannot yet be determined due to lack of identification of the products or premises involved, we expect that FMC Corporation will bear responsibility for a majority of these claims initiated subsequent to the spin-off and that JBT will bear responsibility for other claims initiated subsequent to the spin-off.

Contingent liabilities associated with liquidated damages—Some of our contracts contain penalty provisions that require us to pay liquidated damages if we are responsible for the failure to meet specified contractual milestone dates and the applicable customer asserts a conforming claim under these provisions. These contracts define the conditions under which our customers may make claims against us for liquidated damages. Based upon the evaluation of our performance and other commercial and legal analysis, management believes we have appropriately accrued for probable liquidated damages at December 31, 2013 and 2012, and that the ultimate resolution of such matters will not materially affect our consolidated financial position, results of operations, or cash flows.

NOTE 19. BUSINESS SEGMENTS

We report the results of operations in the following segments: Subsea Technologies, Surface Technologies and Energy Infrastructure. Management’s determination of our reporting segments was made on the basis of our strategic priorities within each segment and corresponds to the manner in which our chief operating decision maker reviews and evaluates operating performance to make decisions about resources to be allocated to the segment.

Our reportable segments are:


•	Subsea Technologies—designs and manufactures products and systems and provides services used by oil and gas companies involved in deepwater exploration and production of crude oil and natural gas.

•

Surface Technologies—designs and manufactures systems and provides services used by oil and gas companies involved in land and offshore exploration and production of crude oil and gas; designs, manufactures and supplies technologically advanced high pressure valves and fittings for oilfield service companies; and also provides fracturing flowback and wireline services for exploration companies in the oil and gas industry.


•	Energy Infrastructure—manufactures and supplies liquid and gas measurement and transportation equipment and systems to customers involved in the production, transportation and processing of crude oil, natural gas and petroleum-based refined products and the mining industry.

Beginning in the third quarter of 2013 and in conjunction with management's efforts to accelerate the development and commercialization of subsea boosting technology for subsea markets, our direct drive systems technology development, previously reported in Energy Infrastructure, is now reported in Subsea Technologies. All prior-year information has been adjusted to reflect the current presentation.

Total revenue by segment includes intersegment sales, which are made at prices approximating those that the selling entity is able to obtain on external sales. Segment operating profit is defined as total segment revenue less segment operating expenses. The following items have been excluded in computing segment operating profit: corporate staff expense, net interest income (expense) associated with corporate debt facilities, income taxes, and other revenue and other expense, net.

Segment revenue and segment operating profit



	Year Ended December 31,
(In millions)	2013			2012			2011
Segment revenue
Subsea Technologies ⁽¹⁾	$	4,726.9		$	4,006.8		$	3,289.5
Surface Technologies	1,806.8			1,598.1			1,310.8
Energy Infrastructure	617.2			574.1			499.0
Other revenue ⁽²⁾and intercompany eliminations	(24.7		)	(27.6		)	(0.3		)
Total revenue	$	7,126.2		$	6,151.4		$	5,099.0
Income before income taxes:
Segment operating profit:
Subsea Technologies	$	548.2		$	432.2		$	306.0
Surface Technologies	257.2			284.3			250.1
Energy Infrastructure	74.3			68.2			63.2
Intercompany eliminations	(0.1		)	—			—
Total segment operating profit	879.6			784.7			619.3
Corporate items:
Corporate expense ⁽³⁾	(46.3		)	(41.8		)	(39.4		)
Other revenue ⁽²⁾ and other expense, net ⁽⁴⁾	(85.6		)	(119.9		)	(22.6		)
Net interest expense	(33.7		)	(26.6		)	(8.2		)
Total corporate items	(165.6		)	(188.3		)	(70.2		)
Income before income taxes attributable to FMC Technologies, Inc.	$	714.0		$	596.4		$	549.1

______________________________

⁽¹⁾

We had one customer in our Subsea Technologies segment that comprised approximately $875.9 million of our consolidated revenue for the year ended December 31, 2013. We had one customer in our Subsea Technologies segment that comprised approximately $625.9 million of our consolidated revenue for the year ended December 31, 2012, and two customers in our Subsea Technologies segment that comprised approximately $633.5 million and $540.7 million of our consolidated revenue for the year ended December 31, 2011.


⁽²⁾	Other revenue comprises certain unrealized gains and losses on derivative instruments related to unexecuted sales contracts.


⁽³⁾	Corporate expense primarily includes corporate staff expenses.


⁽⁴⁾	Other expense, net, generally includes stock-based compensation, other employee benefits, LIFO adjustments, certain foreign exchange gains and losses, and the impact of unusual or strategic transactions not representative of segment operations.

Segment operating capital employed and segment assets



	December 31,
(In millions)	2013			2012
Segment operating capital employed ⁽¹⁾:
Subsea Technologies	$	2,126.3		$	2,050.7
Surface Technologies	1,139.1			1,185.3
Energy Infrastructure	345.4			336.6
Total segment operating capital employed	3,610.8			3,572.6
Segment liabilities included in total segment operating capital employed ⁽²⁾	2,272.8			1,824.2
Corporate ⁽³⁾	722.0			506.1
Total assets	$	6,605.6		$	5,902.9
Segment assets:
Subsea Technologies	$	3,923.6		$	3,452.3
Surface Technologies	1,484.0			1,487.9
Energy Infrastructure	496.4			474.8
Intercompany eliminations	(20.4		)	(18.2		)
Total segment assets	5,883.6			5,396.8
Corporate ⁽³⁾	722.0			506.1
Total assets	$	6,605.6		$	5,902.9

______________________________


⁽¹⁾	FMC Technologies’ management views segment operating capital employed, which consists of assets, net of its liabilities, as the primary measure of segment capital. Segment operating capital employed excludes debt, certain investments, pension liabilities, income taxes and LIFO and valuation adjustments.


⁽²⁾	Segment liabilities included in total segment operating capital employed consist of trade and other accounts payable, advance payments and progress billings, accrued payroll and other liabilities.


⁽³⁾	Corporate includes cash, LIFO adjustments, deferred income tax balances, property, plant and equipment not associated with a specific segment, pension assets and the fair value of derivative financial instruments.

Geographic segment information

Geographic segment sales were identified based on the location where our products and services were delivered. Geographic segment long-lived assets represent property, plant and equipment, net.



	Year Ended December 31,
(In millions)	2013		2012		2011
Revenue (by location of customer):
United States	$	1,940.4	$	1,541.6	$	1,156.4
Norway	1,217.7		1,231.1		966.0
Brazil	689.0		561.2		541.9
Angola	516.0		598.0		514.4
Australia	461.0		377.2		87.8
All other countries	2,302.1		1,842.3		1,832.5
Total revenue	$	7,126.2	$	6,151.4	$	5,099.0



	December 31,
(In millions)	2013		2012		2011
Long-lived assets:
United States	$	443.4	$	424.0	$	238.7
Norway	223.3		197.4		169.7
Brazil	166.3		161.4		126.2
United Kingdom	137.2		92.9		58.9
Malaysia	100.8		91.5		60.9
All other countries	278.1		276.3		113.5
Total long-lived assets	$	1,349.1	$	1,243.5	$	767.9

Other business segment information



	Capital Expenditures Year Ended December 31,						Depreciation and Amortization Year Ended December 31,						Research and Development Expense Year Ended December 31,
(In millions)	2013		2012		2011		2013		2012		2011		2013			2012		2011
Subsea Technologies	$	235.0	$	257.9	$	182.1	$	119.5	$	89.3	$	70.3	$	87.1		$	93.9	$	72.6
Surface Technologies	70.1		110.1		79.7		68.0		38.8		23.0		15.6			12.2		8.3
Energy Infrastructure	8.3		10.3		10.3		16.5		14.0		11.2		12.2			10.7		9.6
Corporate	0.7		27.3		1.9		5.8		4.1		3.3		(2.5		)	—		—
Total	$	314.1	$	405.6	$	274.0	$	209.8	$	146.2	$	107.8	$	112.4		$	116.8	$	90.5

NOTE 20. QUARTERLY INFORMATION (UNAUDITED)



	2013								2012
(In millions, except per share data)	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Revenue	$	2,047.8	$	1,724.5	$	1,707.9	$	1,646.0	$	1,840.9	$	1,419.0	$	1,494.9	$	1,396.6
Cost of sales	1,560.3		1,353.8		1,350.1		1,307.2		1,449.8		1,099.1		1,180.3		1,103.7
Net income	179.1		117.4		106.5		103.6		121.4		100.5		113.2		99.7
Net income attributable to FMC Technologies, Inc.	$	177.8	$	116.0	$	105.2	$	102.4	$	120.4	$	98.9	$	111.9	$	98.8
Basic earnings per share ⁽¹⁾	$	0.75	$	0.49	$	0.44	$	0.43	$	0.50	$	0.41	$	0.47	$	0.41
Diluted earnings per share ⁽¹⁾	$	0.74	$	0.49	$	0.44	$	0.43	$	0.50	$	0.41	$	0.46	$	0.41

______________________________


⁽¹⁾	Basic and diluted EPS are computed independently for each of the periods presented. Accordingly, the sum of the quarterly EPS amounts may not agree to the annual total.

NOTE 21. OTHER INFORMATION



	Year Ended December 31,
(In millions)	2013		2012		2011
Supplemental disclosures of cash flow information:
Cash paid for interest (net of interest capitalized)	$	27.1	$	18.5	$	10.9
Cash paid for income taxes (net of refunds received)	$	137.3	$	225.4	$	83.3



	December 31,
(In millions)	2013		2012
Other reportable information:
Revenue in excess of progress billings on contracts accounted for under the percentage of completion method included in trade receivables	$	777.0	$	627.7
Trading securities included in investments	$	41.6	$	35.6
Net capitalized software costs included in other assets	$	56.9	$	50.8

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2013, and under the direction of our principal executive officer and principal financial officer, we have evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. Based upon this evaluation, we have concluded as of December 31, 2013, that our disclosure controls and procedures were:


i)	effective in ensuring that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and


ii)	effective in ensuring that information required to be disclosed in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal controls over financial reporting identified in the evaluation for the quarter ended December 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act.

Management’s Annual Report on Internal Control over Financial Reporting

This report is included in Part II, Item 8 of this Annual Report on Form 10-K and is incorporated herein by reference.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding our directors is incorporated herein by reference from the section entitled “Our Board of Directors” of our Proxy Statement for the 2014 Annual Meeting of Stockholders.

Our Board of Directors has three standing committees: an Audit Committee, a Compensation Committee and a Nominating and Governance Committee. Each of these committees operates pursuant to a written charter setting out the functions and responsibilities of the committee. The charters for the Audit Committee, the Compensation Committee and the Nominating and Governance Committee of the Board of Directors may be found on our website at www.fmctechnologies.com under “About Us—Corporate Governance” and are also available in print to any stockholder upon request without charge by submitting a written request to our Senior Vice President, General Counsel and Secretary, FMC Technologies, Inc., 5875 North Sam Houston Parkway West, Houston, Texas 77086. Information regarding shareholder nominating procedures is incorporated herein by reference from the section entitled “Corporate Governance—Committees of the Board of Directors—Nominating and Governance Committee” of the Proxy Statement for the 2014 Annual Meeting of Stockholders. Information concerning audit committee financial experts on the Audit Committee of the Board of Directors is incorporated herein by reference from the section entitled “Corporate Governance—Committees of the Board of Directors—Audit Committee” of the Proxy Statement for the 2014 Annual Meeting of Stockholders.

Information regarding our executive officers is presented in the section entitled “Executive Officers of the Registrant” in Part I, Item 1 of this Annual Report on Form 10-K.

Information regarding compliance by our directors and executive officers with Section 16(a) of the Securities and Exchange Act of 1934, as amended, is incorporated herein by reference from the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” of our Proxy Statement for the 2014 Annual Meeting of Stockholders.

We have adopted a Code of Business Conduct and Ethics (the “Code”), which is applicable to our principal executive officer and other senior financial officers, who include our principal financial officer, principal accounting officer or controller, and persons performing similar functions. The Code may be found on our website at www.fmctechnologies.com under “About Us—Corporate Governance” and is available in print to stockholders without charge by submitting a request to the address set forth above. To the extent required by SEC rules, we intend to disclose any amendments to this Code and any waiver of a provision of the Code for the benefit of our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, on our website within four business days following any such amendment of waiver, or within any other period that may be required under SEC rules from time to time.

ITEM 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated herein by reference from the sections entitled “Director Compensation,” “Corporate Governance—Compensation Committee Interlocks and Insider Participation in Compensation Decisions” and “Executive Compensation” of our Proxy Statement for the 2014 Annual Meeting of Stockholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item is incorporated herein by reference from the section entitled “Security Ownership of Our Management and Holders of More Than 5% of Outstanding Shares of Common Stock” of our Proxy Statement for the 2014 Annual Meeting of Stockholders. Additionally, Equity Plan Compensation Information is presented in Part II, Item 5 of this Annual Report on Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this item is incorporated herein by reference from the sections entitled “Transactions with Related Persons” and “Corporate Governance—Director Independence” of our Proxy Statement for the 2014 Annual Meeting of Stockholders.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by this item is incorporated herein by reference from the section entitled “Proposal to Ratify the Appointment of KPMG LLP as Our Independent Registered Public Accounting Firm for 2014 (Item 2 on the Proxy Card)” of our Proxy Statement for the 2014 Annual Meeting of Stockholders.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES


(a)	The following documents are filed as part of this Annual Report on Form 10-K:


1.	The following consolidated financial statements of FMC Technologies, Inc. and subsidiaries are filed as part of this Annual Report on Form 10-K under Part II, Item 8:

Management’s Report on Internal Control over Financial Reporting

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012, and 2011

Consolidated Balance Sheets as of December 31, 2013 and 2012

Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011

Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2013, 2012 and 2011

Notes to Consolidated Financial Statements


2.	Financial Statement Schedule and related Report of Independent Registered Public Accounting Firm:

See “Schedule II—Valuation and Qualifying Accounts” and the related Report of Independent Registered Public Accounting Firm included herein. All other schedules are omitted because of the absence of conditions under which they are required or because information called for is shown in the consolidated financial statements and notes thereto in Part II, Item 8 of this Annual Report on Form 10-K.


3.	Exhibits:

See “Index of Exhibits” filed as part of this Annual Report on Form 10-K.

Schedule II—Valuation and Qualifying Accounts




(In thousands)			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts ^(a)			Deductions and Other ^(b)		Balance at End of Period
Year ended December 31, 2011:
Allowance for doubtful accounts	$	11,035	$	(1,050	)	$	(179	)	$	2,007	$	7,799
Valuation allowance for deferred tax assets	$	3,455	$	766		$	(29	)	$	495	$	3,697
Year ended December 31, 2012:
Allowance for doubtful accounts	$	7,799	$	1,753		$	71		$	3,477	$	6,146
Valuation allowance for deferred tax assets	$	3,697	$	1,732		$	9		$	1,173	$	4,265
Year ended December 31, 2013:
Allowance for doubtful accounts	$	6,146	$	3,038		$	144		$	1,887	$	7,441
Valuation allowance for deferred tax assets	$	4,265	$	1,779		$	(15	)	$	1,302	$	4,727

______________________________


^(a)	“Additions charged to other accounts” includes translation adjustments and allowances acquired through business combinations.


^(b)	“Deductions and other” includes write-offs, net of recoveries, and reductions in the allowances credited to expense.

See accompanying Report of Independent Registered Public Accounting Firm.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.



	FMC TECHNOLOGIES, INC. (Registrant)

	By:	/S/ MARYANN T. SEAMAN
		Maryann T. Seaman Senior Vice President and Chief Financial Officer

Date: February 21, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.



Date		Signature

February 21, 2014		/S/ JOHN T. GREMP
		John T. Gremp Chairman, President and Chief Executive Officer (Principal Executive Officer)

February 21, 2014		/S/ MARYANN T. SEAMAN
		Maryann T. Seaman Senior Vice President and Chief Financial Officer (Principal Financial Officer)

February 21, 2014		/S/ JAY A. NUTT
		Jay A. Nutt Vice President and Controller (Principal Accounting Officer)

February 21, 2014		/S/ MIKE R. BOWLIN
		Mike R. Bowlin, Director

February 21, 2014		/S/ ELEAZAR DE CARVALHO FILHO
		Eleazar De Carvalho Filho, Director

February 21, 2014		/S/ CLARENCE P. CAZALOT, JR.
		Clarence P. Cazalot, Jr., Director

February 21, 2014		/S/ C. MAURY DEVINE
		C. Maury Devine, Director

February 21, 2014		/S/ CLAIRE S. FARLEY
		Claire S. Farley, Director

February 21, 2014		/S/ THOMAS M. HAMILTON
		Thomas M. Hamilton, Director

February 21, 2014		/S/ PETER MELLBYE
		Peter Mellbye, Director

February 21, 2014		/S/ EDWARD J. MOONEY
		Edward J. Mooney, Director

February 21, 2014		/S/ JOSEPH H. NETHERLAND
		Joseph H. Netherland, Director

February 21, 2014		/S/ RICHARD A. PATTAROZZI
		Richard A. Pattarozzi, Director

February 21, 2014		/S/ JAMES M. RINGLER
		James M. Ringler, Director

INDEX OF EXHIBITS



Exhibit No.		Exhibit Description
2.1		Separation and Distribution Agreement by and between FMC Corporation and FMC Technologies, Inc., dated as of May 31, 2001 (incorporated by reference from Exhibit 2.1 to the Form S-1/A filed on June 6, 2001) (Registration No. 333-55920).
2.2		Separation and Distribution Agreement by and between FMC Technologies, Inc. and John Bean Technologies Corporation, dated July 31, 2008 (incorporated by reference from Exhibit 2.1 to the Current Report on Form 8-K filed on August 6, 2008) (File No. 001-16489).
2.2.a		Amendment, dated October 25, 2010, by and between FMC Technologies, Inc. and John Bean Technologies Corporation that amends the Separation and Distribution Agreement by and between FMC Technologies, Inc. and John Bean Technologies Corporation, dated July 31, 2008 (incorporated by reference from Exhibit 2.2.a to the Quarterly Report on Form 10-Q filed on November 3, 2010) (File No. 001-16489).
2.3		Arrangement Agreement dated August 17, 2012 between FMC Technologies, Inc. and Pure Energy Services Ltd. (incorporated by reference from Exhibit 2.1 to the Current Report on Form 8-K filed on August 20, 2012) (File No. 001-16489)).
3.1		Restated Certificate of Incorporation of FMC Technologies, Inc. (incorporated by reference from Exhibit 3.1 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
3.2		Amended and Restated Bylaws of FMC Technologies, Inc. (incorporated by reference from Exhibit 3.1 to the Current Report on Form 8-K filed on December 11, 2013) (File No. 001-16489).
4.1		Form of Specimen Certificate for FMC Technologies, Inc. Common Stock (incorporated by reference from Exhibit 4.1 to the Form S-1/A filed on May 4, 2001) (Registration No. 333-55920).
4.2		Indenture, dated September 21, 2012 between FMC Technologies, Inc. and U.S. Bank National Association, as trustee (incorporated by reference from Exhibit 4.1 to the Current Report on Form 8-K filed on September 25, 2012) (File No. 001-16489).
4.2.a		First Supplemental Indenture, dated September 21, 2012 between FMC Technologies, Inc. and U.S. Bank National Association, as trustee (incorporated by reference from Exhibit 4.2 to the Current Report on Form 8-K filed on September 25, 2012) (File No. 001-16489).
4.2.b		Form of 2.00% Senior Notes due 2017 (incorporated by reference from Exhibit 4.3 to the Current Report on Form 8-K filed on September 25, 2012) (File No. 001-16489).
4.2.c		Second Supplemental Indenture, dated September 21, 2012 between FMC Technologies, Inc. and U.S. Bank National Association, as trustee (incorporated by reference from Exhibit 4.4 to the Current Report on Form 8-K filed on September 25, 2012) (File No. 001-16489).
4.2.d		Form of 3.45% Senior Notes due 2022 (incorporated by reference from Exhibit 4.5 to the Current Report on Form 8-K filed on September 25, 2012) (File No. 001-16489).
10.1		Tax Sharing Agreement by and among FMC Corporation and FMC Technologies, Inc., dated as of May 31, 2001 (incorporated by reference from Exhibit 10.1 to the Form S-1/A filed on June 6, 2001) (Registration No. 333-55920).
10.2		Employee Benefits Agreement by and between FMC Corporation and FMC Technologies, Inc., dated as of May 30, 2001 (incorporated by reference from Exhibit 10.2 to the Form S-1/A filed on June 6, 2001) (Registration No. 333-55920).
10.3		Transition Services Agreement between FMC Corporation and FMC Technologies, Inc., dated as of May 31, 2001 (incorporated by reference from Exhibit 10.3 to the Form S-1/A filed on June 6, 2001) (Registration No. 333-55920).
10.4*		Amended and Restated FMC Technologies, Inc. Incentive Compensation and Stock Plan, dated February 21, 2013. (incorporated by reference from Exhibit 10.4 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
10.4.a*		First Amendment of the Amended and Restated FMC Technologies, Inc. Incentive Compensation and Stock Plan, dated October 3, 2013.
10.5*		Form of Grant Agreement for Long Term Incentive Restricted Stock Grant Pursuant to the Amended and Restated FMC Technologies, Inc. Incentive Compensation and Stock Plan (Employee) (incorporated by reference from Exhibit 10.1to the Current Report on Form 8-K filed on February 28, 2012 (File No. 001-16489).
10.6*		Form of Grant Agreement for Long Term Incentive Restricted Stock Grant Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (Non-Employee Director) (incorporated by reference from Exhibit 10.4e to the Quarterly Report on Form 10-Q filed on May 10, 2005) (File No. 001-16489).
10.7*		Form of Grant Agreement for Key Manager Restricted Stock Grant Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (incorporated by reference from Exhibit 10.4f to the Quarterly Report on Form 10-Q filed on May 10, 2005) (File No. 001-16489).
10.8*		Form of Grant Agreement for Non-Qualified Stock Option Grant Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (Employee) (incorporated by reference from Exhibit 10.4g to the Quarterly Report on Form 10-Q filed on May 10, 2005) (File No. 001-16489).
10.9*		Form of Grant Agreement for Non-Qualified Stock Option Grant Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (Non-Employee Director) (incorporated by reference from Exhibit 10.4h to the Quarterly Report on Form 10-Q filed on May 10, 2005) (File No. 001-16489).
10.10*		Form of Grant Agreement for Stock Appreciation Rights Grant Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (incorporated by reference from Exhibit 10.4i to the Quarterly Report on Form 10-Q filed on May 10, 2005) (File No. 001-16489).
10.11*		Form of Grant Agreement for Performance Units Grant Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (incorporated by reference from Exhibit 10.4j to the Quarterly Report on Form 10-Q filed on May 10, 2005) (File No. 001-16489).
10.12*		Form of Long Term Incentive Performance Share Restricted Stock Agreement Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (incorporated by reference from Exhibit 10.4.k to the Quarterly Report on Form 10-Q filed on May 9, 2006) (File No. 001-16489).
10.13*		Form of Long Term Incentive Performance Share Restricted Stock Agreement Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan (incorporated by reference from Exhibit 10.4.i to the Annual Report on Form 10-K filed on March 1, 2010) (File No 001-16489).
10.14*		Form of Long Term Incentive Restricted Stock Unit Agreement Pursuant to the FMC Technologies, Inc. Incentive Compensation and Stock Plan for Employees of FMC Technologies SA (incorporated by reference from Exhibit 10.4.j to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.15*		Form of FMC Technologies, Inc. Executive Severance Agreement. (incorporated by reference from Exhibit 10.15 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
10.16*		Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part I Salaried and Nonunion Hourly Employees’ Retirement Plan, dated January 1, 2013. (incorporated by reference from Exhibit 10.16 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
10.17*		Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part II Union Hourly Employees’ Retirement Plan, dated January 1, 2013. (incorporated by reference from Exhibit 10.17 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
10.18*		FMC Technologies, Inc. Salaried Employees’ Equivalent Retirement Plan, dated January 1, 2009 (incorporated by reference from Exhibit 10.7 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.18.a*		First Amendment to the FMC Technologies, Inc. Salaried Employees’ Equivalent Retirement Plan, dated October 29, 2009 (incorporated by reference from Exhibit 10.7 to the Quarterly Report on Form 10-Q filed on November 3, 2009) (File No. 001-16489).
10.18.b*		Second Amendment to the FMC Technologies, Inc. Salaried Employees’ Equivalent Retirement Plan, dated June 22, 2010. (incorporated by reference from Exhibit 10.18 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
10.19*		FMC Technologies, Inc. Equivalent Retirement Plan Grantor Trust Agreement, dated July 31, 2001 (incorporated by reference from Exhibit 10.7.a to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.20*		Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated January 1, 2013. (incorporated by reference from Exhibit 10.20 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
10.20.a*		First Amendment to the Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated December 20, 2013.
10.20.b*		Second Amendment to the Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated February 7, 2014.
10.21*		FMC Technologies, Inc. Savings and Investment Plan Trust Agreement, dated September 28, 2001 (incorporated by reference from Exhibit 10.8.a to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.22*		Amended and Restated FMC Technologies, Inc. Non-Qualified Savings and Investment Plan, dated January 1, 2009 (incorporated by reference from Exhibit 10.9 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.22.a*		First Amendment to the FMC Technologies, Inc. Non-Qualified Savings and Investment Plan, dated October 29, 2009 (incorporated by reference from Exhibit 10.9 the Quarterly Report on Form 10-Q filed on November 3, 2009) (File No. 001-16489).
10.23*		FMC Technologies, Inc. Non-Qualified Savings and Investment Plan Trust Agreement, dated September 28, 2001 (incorporated by reference from Exhibit 10.9.a to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.24		Commercial Paper Dealer Agreement 4(2) Program between Banc of America Securities LLC and FMC Technologies Inc., dated as of January 24, 2003 (incorporated by reference from Exhibit 10.10 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.25		Commercial Paper Dealer Agreement 4(2) Program between Wells Fargo Brokerage Services, LLC and FMC Technologies, Inc., dated as of December 21, 2007 (incorporated by reference from Exhibit 10.11 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.26		Commercial Paper Dealer Agreement 4(2) Program between J.P. Morgan Securities Inc. and FMC Technologies, Inc., dated as of March 7, 2008 (incorporated by reference from Exhibit 10.12 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.27		Commercial Paper Dealer Agreement 4(2) Program between Citigroup Global Markets Inc. and FMC Technologies, Inc., dated as of January 2010 (incorporated by reference from Exhibit 10.13 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.28		Commercial Paper Dealer Agreement 4(2) Program between RBS Securities Inc. and FMC Technologies, Inc., dated as of July 13, 2012. (incorporated by reference from Exhibit 10.28 to the Annual Report on Form 10-K filed on February 22, 2013) (File No. 001-16489).
10.29		Issuing and Paying Agency Agreement by and between Wells Fargo Bank, National Association and FMC Technologies, Inc., dated as of January 3, 2004 (incorporated by reference from Exhibit 10.14 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.30		$1,500,000,000 Credit Agreement, dated as of March 26, 2012, by and among FMC Technologies, Inc., as Borrower; JPMorgan Chase Bank, N.A., as Administrative Agent; The Royal Bank of Scotland plc, as Syndication Agent; The Bank of Tokyo-Mitsubishi UFJ, Ltd., DNB Bank ASA, Grand Cayman Branch, and Wells Fargo Bank, National Association, as Co-Documentation Agents; J.P. Morgan Securities LLC, RBS Securities Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd., DNB Markets, Inc. and Wells Fargo Securities, LLC, as Joint Bookrunners and Co-Lead Arrangers; and the other lenders party thereto (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on March 27, 2012) (File No. 001-16489).
10.31		Tax Sharing Agreement by and among FMC Technologies, Inc. and its affiliates and John Bean Technologies Corporation and its affiliates, dated July 31, 2008 (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on August 6, 2008) (File No. 001-16489).
10.32		Securities Purchase Agreement by and among FMC Technologies, Inc., Schilling Robotics, Inc., Schilling Robotics, LLC and Tyler Schilling, dated December 24, 2008 (incorporated by reference from Exhibit 10.15 to the Annual Report on Form 10-K filed on February 27, 2009) (File No. 001-16489).
10.33.a		Securities Purchase Agreement by and among FMC Technologies, Inc., Schilling Robotics, Inc., Schilling Robotics, LLC and Tyler Schilling, dated April 25, 2012 (incorporated by reference from Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on July 27, 2012) (File No. 001-16489).
10.34		Unitholders Agreement by and between FMC Technologies, Inc., Schilling Robotics, Inc. and Tyler Schilling, dated December 26, 2008 (incorporated by reference from Exhibit 10.16 to the Annual Report on Form 10-K filed on February 27, 2009) (File No. 001-16489).
10.35		Amended and Restated Operating Agreement by and among FMC Technologies, Inc., Schilling Robotics, Inc., Schilling Robotics Newco, LLC, Schilling Robotics, LLC and Tyler Schilling, dated December 26, 2008 (incorporated by reference from Exhibit 10.17 to the Annual Report on Form 10-K filed on February 27, 2009) (File No. 001-16489).
10.36		Purchase Agreement, dated September 9, 2009, by and between FMC Technologies, Inc., Direct Drive Systems, Inc., (“DDS”), each stakeholder in DDS signatory thereto (each, a “Seller”) and Vatche Artinian as the Sellers’ Representative (incorporated by reference from Exhibit 10.10 to the Quarterly Report on Form 10-Q filed on November 3, 2009) (File No. 001-16489).
10.37		Form of Voting and Support Agreement dated August 17, 2012 between FMC Technologies, Inc. and the directors and officers of Pure Energy Services Ltd. (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on August 20, 2012) (File No. 001-16489).
21.1		Significant Subsidiaries of the Registrant.
23.1		Consent of Independent Registered Public Accounting Firm.
31.1		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) and Rule 15d-14(a).
31.2		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) and Rule 15d-14(a).
32.1**		Certification of Chief Executive Officer Under Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. 1350.
32.2**		Certification of Chief Financial Officer Under Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. 1350.
101.INS		XBRL Instance Document
101.SCH		XBRL Schema Document
101.CAL		XBRL Calculation Linkbase Document
101.DEF		XBRL Definition Linkbase Document
101.LAB		XBRL Label Linkbase Document
101.PRE		XBRL Presentation Linkbase Document

______________________________

* Indicates a management contract or compensatory plan or arrangement

** Furnished with this Form 10-K