Edgar Filing: FMC TECHNOLOGIES INC

FMC.2014.12.31-10K

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, 2014



¨	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. ý

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, 2014, by the closing price on such day of $61.07 as reported on the New York Stock Exchange, was $7,923,489,042.*

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of February 18, 2015 was 231,444,593.

DOCUMENTS INCORPORATED BY REFERENCE



DOCUMENT	FORM 10-K REFERENCE
Portions of Proxy Statement for the 2015 Annual Meeting of Stockholders	Part III



*	Excludes 105,363,947 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, 2014. 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	45
Item 8. Financial Statements and Supplementary Data	46
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 27A of the Securities Act of 1933, as amended, and 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 risks and uncertainties (some of which are significant or beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, Item 1A “Risk Factors” of this Annual Report on Form 10-K. 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. Prior to 2012 we owned 45% of Schilling Robotics, and the acquisition of the remaining 55% 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 flowback services and wireline services. The acquisition of Pure Energy is complementing the existing products and services of our Surface Technologies segment and is expected to create 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 technologies to support our long-term strategy to expand our subsea production and processing systems. Additional 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 2014 we completed the sale of our equity interests and assets primarily representing a product line of our material handling business to Syntron Material Handling, LLC, an affiliate of Levine Leichtman Capital Partners Private Capital Solutions II, L.P. Additional financial information is incorporated herein by reference from Note 5 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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 2015 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 6, 2015, we expect our Proxy Statement for the 2015 Annual Meeting of Stockholders will be available on our website under “Investors—Financial Information—SEC Filings.” Similarly, on the same date, we expect our 2014 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 primarily market our products 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 technologies. 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%, 63% and 62% of our consolidated revenue in 2014, 2013 and 2012, respectively.

Schilling Robotics. We design and manufacture ROVs and 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 support and services such as product training, pilot simulator training, spare parts, technical assistance and logistics support.

Multi Phase Meters. We design and manufacture multiphase and wetgas meters with applications that include production and surface well testing, reservoir monitoring, remote operation of entire fields, 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’ field properties 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.

Petrobras is a key customer for the Subsea Technologies segment. During early 2014, Brazilian authorities triggered an investigation into Petrobras wholly unrelated to FMC Technologies. As a result of the investigation at Petrobras, our operational performance may be affected by any significant changes in Petrobras’ operational activities. As part of our strong customer relationship, we are working with Petrobras to delay certain deliveries of product in 2015 which may affect our cash flows. During 2014, we did not take any bad debt charges related to this customer.

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. No single Subsea Technologies customer accounted for 10% or more of our 2014 consolidated revenue.

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 design, manufacture and supply technologically advanced high pressure valves, pumps and fittings used in stimulation activities for oilfield service companies and provide flowback and wireline services for exploration and production companies in the oil and gas industry.

Principal Products and Services

Surface Wellhead. We provide a full range of drilling, completion and production wellhead systems for both standard and custom-engineered applications. Surface wellhead production systems, or trees, are used to control and regulate the flow of crude oil and natural gas from the well. Our surface wellhead 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 manifolds and trees and flow back equipment for timely and cost-effective well completion.

Surface wellhead represented approximately 15%, 14% and 13% of our consolidated revenue in 2014, 2013 and 2012, respectively.

Fluid Control. We design and manufacture flowline products, under the Weco^®/Chiksan^® trademarks, 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 plc. Our flowline products are used in equipment that pumps fluid into a well during the well construction and 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 35 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%, 8% and 12% of our consolidated revenue in 2014, 2013 and 2012, respectively.

Completion Services. We provide flowback services, cased hole electric wireline and slickline services, specialty logging services, pressure transient analysis, and well optimization 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 offers flowback services that provide our customers the well services necessary for the recovery of solids, 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 2014, 2013 or 2012 consolidated revenue.

Competition

Surface Technologies 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, manufacture and supply measurement products for the worldwide oil and gas industry. Our flow computers and control systems manage and monitor liquid and gas measurement for applications such as custody transfer, fiscal measurement and batch loading and deliveries. Our floating production, storage and off-loading metering systems provide the precision and reliability required for measuring large flow rates characteristic of marine loading operations. Our measurement systems provide many 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 to ensure processes operate efficiently while reducing operating costs and minimizing the risk associated with custody transfer.

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 provide transfer loading solutions using Chiksan loading arms and Chiksan swivel joint technologies capable of diverse applications. While our marine systems are typically constructed on a fixed jetty platform, we 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. Both our land- and marine- based loading and transfer systems are capable of handling a wide range of products including petroleum products, liquefied natural gas (“LNG”) and chemical products.

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. One of the business’ primary product, 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.

Dependence on Key Customers

No single Energy Infrastructure customer accounted for 10% or more of our 2014, 2013 or 2012 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 enable 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 our customers’ fields. We continue to expand the portfolio of solutions in order to deliver a complete production system for high pressure, high temperature (“HPHT”) applications. In 2014 we entered into a joint development agreement with several major operators to develop common standards for subsea production equipment capable of operating at pressures as high as 20,000 psi and temperatures up to 350º F. We believe standardization is an important element in improving execution, optimizing resources, lowering life cycle costs and providing superior long-term value. This agreement is expected to result in standardized materials, processes and interfaces and is expected to deliver improved reliability and operability over the life of the field. During 2014 we continued work to complete the portfolio of capabilities to support these applications with systems for high integrity pressure protection (“HIPPS”) and completion workover risers (“CWOR”). Also in 2014, our third generation of ultra-heavy duty work class ROVs, the UHD-III, was completed and delivered to the market. This recent evolution of ROV technology features a new hydraulic pumping system capable of operating underwater valves in emergency situations, a tool dynamic positioning system, and a high definition Ethernet video system enhancing vehicle operation for ROV pilots.

In addition to the development of new technology for challenging fields, we also seek to develop solutions that will help operators maximize recovery from existing subsea fields. We continue to advance the development of 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, development work progressed on a pump system capable of operating at higher pressures and temperatures compared to solutions currently available in the market.

Standardization of subsea equipment is key to achieve reductions in cost and improved performance. In 2014 our next generation Master Control Station featuring our proprietary User Configurable Open System (UCOS^®) software was completed, installed and commissioned offshore. The modular UCOS software platform allows for greater flexibility and scalability and will be utilized as the standard for control system applications in subsea production, processing and workover systems. Additionally, the next generation of standard electric and hydraulic actuators were completed and delivered for field application. The E3 hydraulic actuator features design improvements that will offer improved reliability. The G2i electric actuator was designed for improved manufacturability and qualified according to the highest industrial standards. The G2i electric actuator will be a key component in subsea production and processing systems.

We are also expanding our subsea services portfolio to provide more services that maximize production and recovery over the life of the field. In January 2015, we completed the construction of a fourth riserless light well intervention (“RLWI”) system capable of operating at water depths up to 6,000 ft. RLWI is a cost-effective, rigless 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 our integrated shale operations. Development work was completed on de-sanding technology designed to improve the performance of flowback operations. Pilot units were produced and successfully tested in the field. Our fluid control business also completed development and launched the ePRV, an electronic pressure relief valve. The ePRV is the first fully electronic pressure relief valve for the pressure pumping market, providing improved accuracy and serviceability. Additional investments in Surface Technologies were directed toward the expansion of capabilities to support shallow water production. The JXT (Jack-Up X-mas Tree) and JXT-3 designs were delivered to the field. 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 loading systems business unit completed development on an all-electric marine loading arm. The electric drives are easier to maintain and more efficient to operate compared to existing hydraulic arms.

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 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 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 1,330 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 150 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, 2014, we had approximately 20,300 full-time employees, consisting of approximately 6,900 in the United States and 13,400 in non-U.S. locations. Less than 2% of our U.S. employees are represented by labor unions.

The Iran Threat Reduction and Syria Human Rights Act of 2012

The Iran Threat Reduction and Syria Human Rights Act of 2012 amended Section 13 of the Exchange Act and requires disclosure when a company knowingly engages in specified prohibited activities involving Iran. We had no such activities to report during the year ended December 31, 2014.

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 20, 2015, the executive officers of FMC Technologies, together with the offices held by them, their business experience and their ages, are as follows:



Name	Age	Current Position and Business Experience
John T. Gremp	63	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)
Maryann T. Seaman	52	Executive Vice President and Chief Financial Officer (2014) Senior Vice President and Chief Financial Officer (2011) Vice President—Treasurer and Deputy Chief Financial Officer (2010)
Bradley D. Beitler	61	Vice President—Technology (2009)
Sanjay Bhatia	45	Vice President—Corporate Development (2012) Director of Business Development (2007)
Tore Halvorsen	60	Senior Vice President—Subsea Technologies (2011) Senior Vice President—Global Subsea Production Systems (2007)
Jay A. Nutt	51	Vice President and Controller (2009)
Johan Pfeiffer	50	Vice President—Surface Technologies (2011) Vice President—Global Surface Wellhead (2010)
Douglas J. Pferdehirt	51	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)
Dianne Ralston	48	Senior Vice President, General Counsel, and Secretary (2015) Executive Vice President, General Counsel, and Secretary for Weatherford International plc (2014) Deputy General Counsel—Corporate for Schlumberger Limited (2012) Deputy General Counsel— Government Affairs, Litigation, and IP Enforcement for Schlumberger Limited (2010)
Mark J. Scott	61	Vice President—Administration (2010)

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 ten 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 in our backlog. 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, such potential liabilities could have a material adverse effect on our business, results of operations, financial condition or cash flows.

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 Brazilian Anti-Bribery Act (also known as the Brazilian Clean Company Act), 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 in the United States and regulations in foreign countries 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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, or the issuance of orders enjoining operations. These laws and regulations, as well as the adoption of new legal requirements or 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/or promulgating legislation and regulations that are focused on restricting emissions commonly referred to as greenhouse gas (“GHG”) emissions. For instance, under the U.S. Clean Air Act, the U.S. Environmental Protection Agency (“EPA”) has made findings that GHG emissions endanger public health and the environment, resulting in the EPA’s adoption of regulations requiring construction and operating permit reviews of certain stationary sources with major emissions of GHGs, which reviews may require the installation of best available control technologies typically approved by the states and the monitoring and annual 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, in June 2014, the EPA, acting under President Obama’s Climate Action Plan, proposed its Clean Power Plan, which would set U.S. state-by-state guidelines for power plants to reduce their carbon emissions and cut pollution, nitrogen oxides and sulfur dioxide. To the extent our customers are subject to these or other similar proposed or newly enacted laws and regulations, the additional costs incurred by our customers to comply with such laws and regulations could impact their ability or desire to continue to operate at current or anticipated levels, which would negatively impact their demand for our systems and services. In addition, any new laws or regulations establishing cap-and-trade and those that favor the increased use of non-fossil fuels may dampen demand for oil and gas production and lead to lower spending by our customers for our systems and services. Similarly, to the extent we are or become subject to any of these or other similar proposed or newly enacted laws and regulations, we expect that our efforts to monitor, report and comply with such laws and regulations, and any related taxes imposed on companies by such programs, will increase our cost of doing business and may have a material adverse effect on our financial condition and results of operation.

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. For example, the U.S. Department of the Interior has issued proposed regulations that would apply to hydraulic fracturing operations on wells that are subject to federal oil and gas leases and that would impose requirements regarding the disclosure of chemicals used in the hydraulic fracturing process, as well as requirements to obtain certain federal approvals before proceeding with hydraulic fracturing at a well site. This and other similar state and foreign regulatory initiatives, if adopted, would establish additional levels of regulation for our customers that could make it more difficult for our customers to complete natural gas and oil wells and could adversely affect the demand for our equipment and services, 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 countries in which we conduct business could adversely affect our business or results of operations.

We operate manufacturing facilities in the United States and in various countries across the world. Instability and unforeseen changes in any of the 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, 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. Moreover, certain currencies, specifically currencies in countries such as Angola and Nigeria where we have expanding operations, do not actively trade in the global foreign exchange markets and may subject us to increased foreign currency exposures. 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 position or results of operations.

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, particularly in light of the current industry environment where customers may seek to improve their returns or cash flows.

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. 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 conducted required due diligence activities for the 2013 calendar year and filed our first Form SD report with the SEC in June 2014. While the conflict minerals rule continues in effect as adopted, there remains uncertainty regarding how the conflict minerals rule, and our compliance obligations, will be affected in the future. Specifically, the Court of Appeals for the D.C. Circuit largely upheld the conflict minerals rule in April 2014, but in November 2014, it granted the SEC’s and Amnesty International’s petitions for rehearing regarding certain disclosure requirements of the rule. Additional requirements under the 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, 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.

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. Although no such material incidents have occurred to date, 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.

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 deterioration in future expected profitability or cash flows could result in an impairment of our recorded goodwill.

Goodwill is tested for impairment on an annual basis, or more frequently when impairment indicators arise. 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 changes in customer demand, cost increases, regulatory or political environment changes, and other changes in market conditions, such as decreased prices in similar market-based transactions, which could impact future earnings of the reporting unit.

At December 31, 2014, recorded goodwill of $75.8 million was associated with our completion services reporting unit. The recent decline in crude oil prices has introduced some uncertainty associated with certain key assumptions used in estimating fair value of the reporting unit. Depressed crude oil prices for a prolonged period of time may adversely affect the economics of certain of our customers’ projects, particularly for shale-related projects in North America, and may reduce the demand for completion services, negatively impacting the financial results of the reporting unit. Management is monitoring the overall market, specifically crude oil prices, and its effect on the estimates and assumptions used in our goodwill impairment test for completion services, which may require re-evaluation and could result in an impairment of goodwill for this reporting unit.

At December 31, 2014, recorded goodwill of $30.7 million was associated with our automation and control reporting unit. During 2014 the automation and control reporting unit realized significantly lower sales volumes, leading to negative operating results for the year and creating some uncertainty regarding future demand for certain products. Management has undertaken efforts to integrate the reporting unit’s UCOS^®product with our Master Control Station in our subsea systems business to promote cost and efficiency savings in our subsea product offering by utilizing the UCOS^® Master Control Station as the standard for control system applications in subsea production, processing and workover systems. Management is evaluating the realizability of these savings and its effect on the estimates and assumptions used in our goodwill impairment test for automation and control, which may require re-evaluation and could result in an impairment of goodwill for this reporting unit.

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 24 significant production facilities in 14 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, 2014:



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

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

*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.”



	2014								2013
	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Common stock price:
High	$	57.00	$	63.52	$	61.89	$	53.27	$	59.34	$	58.35	$	58.73	$	54.39
Low	$	42.75	$	54.21	$	52.16	$	48.37	$	47.78	$	52.38	$	48.50	$	42.97



Closing stock price at December 31, 2014	$	46.84
Closing stock price at February 18, 2015	$	42.76
Number of common stockholders of record at February 18, 2015	2,937

We have not declared or paid cash dividends in 2014 or 2013, and we do not currently have a plan to pay cash dividends in the future.

As of December 31, 2014, 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	—	$	—	23,564,891	(1)
Equity compensation plans not approved by security holders	—	—		—
Total	—	$	—	23,564,891	(1)

______________________________


⁽¹⁾	The table includes shares of our common stock available for future issuance under the Amended and Restated FMC Technologies, Inc. Incentive Compensation and Stock Plan. This number includes 3,414,910 shares available for issuance for nonvested stock awards that vest after December 31, 2014.

We had no unregistered sales of equity securities during the year ended December 31, 2014.

The following table summarizes repurchases of our common stock during the three months ended December 31, 2014.

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, 2014 – October 31, 2014	180,088	$	52.16	179,678	10,319,609
November 1, 2014 – November 30, 2014	384,163	$	54.81	383,883	9,935,726
December 1, 2014 – December 31, 2014	1,903,324	$	45.96	1,903,094	8,032,632
Total	2,467,575	$	47.79	2,466,655	8,032,632

______________________________

^(a)

Represents 2,466,655 shares of common stock repurchased and held in treasury and 920 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 25,910 shares of registered common stock held in this trust, as directed by the beneficiaries, during the three months ended December 31, 2014.

^(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.

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, 2014. This information should be read in conjunction with Part I, Item 1 “Business,” Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition 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	2014		2013		2012		2011		2010
Statement of income data:
Total revenue	$	7,942.6	$	7,126.2	$	6,151.4	$	5,099.0	$	4,125.6
Total costs and expenses	$	6,874.1	$	6,378.6	$	5,546.6	$	4,536.6	$	3,574.0
Income from continuing operations	$	705.3	$	506.6	$	434.8	$	403.5	$	378.3
Net income attributable to FMC Technologies, Inc.	$	699.9	$	501.4	$	430.0	$	399.8	$	375.5

Earnings per share from continuing operations attributable to FMC Technologies, Inc.: ⁽¹⁾
Basic earnings per share	$	2.96	$	2.10	$	1.79	$	1.66	$	1.55
Diluted earnings per share	$	2.95	$	2.10	$	1.78	$	1.64	$	1.53

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



(In millions) As of December 31	2014			2013			2012			2011			2010
Balance sheet data:
Total assets	$	7,175.6		$	6,605.6		$	5,902.9		$	4,271.0		$	3,644.2
Net (debt) cash ⁽²⁾	$	(670.1	)	$	(973.2	)	$	(1,298.7	)	$	(279.6	)	$	(47.8	)
Long-term debt, less current portion	$	1,297.2		$	1,329.8		$	1,580.4		$	36.0		$	351.1
Total FMC Technologies, Inc. stockholders’ equity	$	2,456.3		$	2,317.2		$	1,836.9		$	1,424.6		$	1,311.7



(In millions) Years Ended December 31	2014		2013		2012		2011		2010
Other financial information:
Capital expenditures	$	404.4	$	314.1	$	405.6	$	274.0	$	112.5
Cash flows provided by operating activities of continuing operations	$	892.5	$	795.4	$	138.4	$	164.8	$	194.8
Segment operating capital employed ⁽³⁾	$	3,672.7	$	3,610.8	$	3,572.6	$	2,204.2	$	1,722.8
Order backlog ⁽⁴⁾	$	6,619.4	$	6,998.2	$	5,377.8	$	4,876.4	$	4,171.5

______________________________


⁽¹⁾	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. All per share information presented has been adjusted to reflect the stock split.


⁽²⁾	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.

⁽³⁾

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.


⁽⁴⁾	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 and 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. A discussion and analysis of our consolidated results and the results of each of our segments for the years ended December 31, 2014, 2013 and 2012 follows.

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 capital 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. 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.

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 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 closely working with our customers, we enhance our competitive advantage, improve our operating results and strengthen our market positions. Evaluating our share of subsea tree awards during the year is one way 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 aim to 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 2014, approximately 72% 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. Based on the increasing focus by international oil companies on deepwater development and production, 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 Outlook. We operate in the commodity-driven, cyclical oil and gas industry. Since the beginning of 2011 and until the fourth quarter of 2014, the industry operated in an environment where crude oil prices largely avoided this cycle with WTI crude oil prices averaging approximately $96 per barrel over this period. With crude oil prices at such levels, many discoveries were economical for operators to develop. During the fourth quarter of 2014, crude oil prices significantly declined due to continued growth in U.S. oil production, weakened outlooks for the global economy and continued strong international crude oil supply, especially from OPEC’s unexpected decision to maintain oil production levels. As a result of the weaker crude oil price environment, many crude oil development prospects are or are becoming less economical for many operators, leading to an expected downturn in demand for our products and services and an overall weaker demand for oilfield services. While the downturn we now face in our industry is significant, we believe the predominantly supply-driven, current market imbalance will undergo the corrective measures necessary for the recovery of commodity prices in the long term. Although the timing of the recovery of crude oil prices is dependent on many variables, we believe as long-term demand rises and production naturally declines, commodity prices will recover and our customers will begin to increase their investments in new sources of oil production. Our improved execution in 2014 has set the stage for us to overcome the challenges in the industry in 2015, and while certain reductions to our headcount in the coming year are necessary to protect our profitability, the measures we expect to take will align with our long-term growth strategies.

Subsea Technologies. All of our businesses will be negatively affected by the decline in crude oil prices, but the timing will be different for each. Our 2014 subsea order activity, specifically during the fourth quarter related to Chevron’s Agbami Phase 3 project, Eni’s Block 15/06 East Hub development and Wintershall’s Maria, led to another year of strong subsea project backlog as of December 31, 2014. However, in reaction to the decline in crude oil prices, many of our customers have announced reductions to their capital spending in 2015, and we are preparing for the anticipated slowing of subsea orders in the coming year. We expect subsea revenue in 2015 to be relatively flat when compared to 2014 in large part from our conversion of existing backlog, partially offset by lower 2015 inbound expectations and the impact of a strong U.S. dollar. Our focus in the coming year will concentrate on leveraging our global capabilities and reducing operating costs. In the long-term, we continue to believe deepwater development will remain a significant part of our customers’ portfolios. A critical part of our long-term strategy to maintain our subsea market leadership is to continue to invest in the technologies required to develop our customers’ challenging assets and further expand our capabilities focused on increasing reservoir production over the life of the field. However, given the critical need to reduce costs over the short-term, we are focused on offering cost-effective approaches to our customers’ project developments, including customer acceptance of new technologies and acceptance of business models to help achieve their cost-reduction goals. Part of this strategy includes standardization of subsea production equipment as operators understand the cost and scheduling benefits that standardization brings to their projects.

Given the recent decline in crude oil prices and the capital budget reductions by our customers, we expect that growth related to subsea services in 2015 to be relatively flat when compared to 2014. However, we continue to focus on subsea processing and subsea services as key long-term 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. When crude oil prices recover to levels that support economic field development and the overall oil and gas market recovers, operators will continue to seek ways to reduce costs associated with developing their deepwater assets, and we believe our continued focus on subsea processing and subsea services, particularly in subsea boosting and well intervention solutions, will be critical parts of our continued growth and success. Overall, 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 in the coming year.

Surface Technologies. The improved operational results we realized in 2014 were the result of North American surface technologies orders recovering from the slowdown that began in 2012 and that continued into mid 2013. However, provided the recent decline in commodity prices, and consequently, the decline in rig counts, we are preparing for decreased North American land activity in 2015, which will affect our surface wellhead, fluid control and completion services businesses in North America. Absent a recovery of oil and gas prices in the second half of 2015, we believe that commodity prices in 2016 may be at a level to allow recovery in North American activity. In 2015 we expect to continue efforts to integrate our North American surface wellhead and completion services businesses to strengthen our market presence and service offerings which we believe will bring increased value to our customers. Our international surface wellhead business delivered strong operational results from continued strength in international markets in 2014, and we expect this strength to continue in 2015 as a result of our strong international surface wellhead backlog.

CONSOLIDATED RESULTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012



	Year Ended December 31,									Change
(In millions, except percentages)	2014			2013			2012			2014 vs. 2013				2013 vs. 2012
Revenue	$	7,942.6		$	7,126.2		$	6,151.4		$	816.4		11%	$	974.8		16%
Costs and expenses:
Cost of sales	5,999.8			5,571.4			4,832.9			428.4			8	738.5			15
Selling, general and administrative expense	750.6			694.8			596.9			55.8			8	97.9			16
Research and development expense	123.7			112.4			116.8			11.3			10	(4.4		)	(4)
Total costs and expenses	6,874.1			6,378.6			5,546.6			495.5			8	832.0			15
Gain on sale of Material Handling Products	84.3			—			—			84.3			*	—			*
Other income (expense), net	(54.0		)	5.3			23.0			(59.3		)	*	(17.7		)	*
Net interest expense	(32.5		)	(33.7		)	(26.6		)	1.2			4	(7.1		)	(27)
Income before income taxes	1,066.3			719.2			601.2			347.1			48	118.0			20
Provision for income taxes	361.0			212.6			166.4			148.4			70	46.2			28
Net income	705.3			506.6			434.8			198.7			39	71.8			17
Less: net income attributable to noncontrolling interests	(5.4		)	(5.2		)	(4.8		)	(0.2		)	(4)	(0.4		)	(8)
Net income attributable to FMC Technologies, Inc.	$	699.9		$	501.4		$	430.0		$	198.5		40%	$	71.4		17%

_______________________

*Not meaningful

2014 Compared With 2013

Revenue increased by $816.4 million in 2014 compared to the prior year. Revenue in 2014 included a $218.4 million unfavorable impact of foreign currency translation. Excluding the impact of foreign currency translation, total revenue increased by $1,034.8 million year-over-year. Subsea systems and services had another solid year of order activity in 2014. The impact of higher backlog coming into 2014, combined with strong market activity, led to increased Subsea Technologies sales year-over-year. Surface Technologies posted higher revenue in 2014 due to conventional wellhead system sales in our surface wellhead business in both domestic and international markets and due to increased sales in our fluid control business as demand for our well service pumps and flowline products recovered from the slowdown of the North American shale markets experienced in the prior year.

Gross profit (revenue less cost of sales) increased as a percentage of sales to 24.5% in 2014 from 21.8% in the prior year. The increase in gross profit as a percentage of sales was primarily due to higher margin backlog conversion in our Western Region subsea business, higher volumes in subsea services across all regions and the remeasurement of the Multi Phase Meters earn-out consideration in 2013, partially offset by additional contract value in 2013 related to an Angolan withholding tax adjustment. Additionally, gross profit as a percentage of revenue increased as a result of higher volumes and higher margin projects in the Middle East and Europe surface wellhead regions and due to increased demand for our well service pumps and flowline products in our fluid control business.

Selling, general and administrative (“SG&A”) expense increased by $55.8 million year-over-year, driven by higher project tendering costs and reorganization expenses in our subsea business, increased sales commissions, costs associated with terminating a representative agreement in our surface wellhead business and bonus accruals.

During 2014 we recognized a net $84.3 million gain on the sale of our Material Handling Products business. Further information of the sale is incorporated herein by reference from Note 5 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Other income (expense), net, reflected a $33.4 million loss related to the remeasurement of an intercompany foreign currency transaction and other foreign currency losses primarily due to the strengthening of the U.S. dollar in 2014. Further discussion of our derivative instruments is incorporated herein by reference from Note 15 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 34.0% and 29.8% in 2014 and 2013, respectively. Excluding a retroactive benefit related to the American Taxpayer Relief Act of 2012 recorded in the first quarter of 2013, our effective tax rate was 30.7% in 2013. The increase in our effective tax rate in 2014 from the adjusted rate in 2013 was primarily due changes in Norwegian tax law effective from 2014 and an unfavorable change in 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.

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.

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 15 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.

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, net interest income (expense) associated with corporate debt facilities, income taxes, and other revenue and other expense, net. Information about amounts included in corporate items 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.

The following table summarizes our operating results for the years ended December 31, 2014, 2013 and 2012:



	Year Ended December 31,									Favorable/(Unfavorable)
(In millions, except percentages)	2014			2013			2012			2014 vs. 2013				2013 vs. 2012
Revenue
Subsea Technologies	$	5,266.4		$	4,726.9		$	4,006.8		$	539.5		11%	$	720.1		18%
Surface Technologies	2,130.7			1,806.8			1,598.1			323.9			18	208.7			13
Energy Infrastructure	557.4			617.2			574.1			(59.8		)	(10)	43.1			8
Other revenue and intercompany eliminations	(11.9		)	(24.7		)	(27.6		)	12.8			*	2.9			*
Total revenue	$	7,942.6		$	7,126.2		$	6,151.4		$	816.4		11%	$	974.8		16%
Net income
Segment operating profit:
Subsea Technologies	$	748.2		$	548.2		$	432.2		$	200.0		36%	$	116.0		27%
Surface Technologies	393.0			257.2			284.3			135.8			53	(27.1		)	(10)
Energy Infrastructure	52.5			74.3			68.2			(21.8		)	(29)	6.1			9
Intercompany eliminations	(0.3		)	(0.1		)	—			(0.2		)	*	(0.1		)	*
Total segment operating profit	1,193.4			879.6			784.7			313.8			36	94.9			12
Corporate items:
Corporate expense	(66.3		)	(46.3		)	(41.8		)	(20.0		)	(43)	(4.5		)	(11)
Other revenue and other (expense), net	(33.7		)	(85.6		)	(119.9		)	51.9			61	34.3			29
Net interest expense	(32.5		)	(33.7		)	(26.6		)	1.2			4	(7.1		)	(27)
Total corporate items	(132.5		)	(165.6		)	(188.3		)	33.1			20	22.7			12
Income before income taxes	1,060.9			714.0			596.4			346.9			49	117.6			20
Provision for income taxes	361.0			212.6			166.4			(148.4		)	(70)	(46.2		)	(28)
Net income attributable to FMC Technologies, Inc.	$	699.9		$	501.4		$	430.0		$	198.5		40%	$	71.4		17%

_______________________

*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

2014 Compared With 2013

Subsea Technologies’ revenue increased $539.5 million in 2014 compared to the prior year. Revenue for 2014 included a $178.5 million unfavorable impact of foreign currency translation. Excluding the impact of foreign currency translation, Subsea Technologies’ revenue increased by $718.0 million during 2014 compared to the prior year. We entered the year with a strong backlog. During the first half of 2014, high crude oil prices led to solid oil and gas exploration and production activity when compared to the prior year; however, a decline in oil prices that began in mid-2014 and which significantly further declined in the fourth quarter of 2014 has unfavorably affected the subsea market. Despite the late 2014 decline in crude oil prices, we had solid order activity during 2014 from high demand for subsea systems and services. The year-over-year increase in revenue was attributable to the conversion of backlog and solid order activity in 2014.

Subsea Technologies’ operating profit totaled $748.2 million, or 14.2% of revenue, in 2014, compared to the prior-year’s operating profit as a percentage of revenue of 11.6%. The margin improvement was primarily driven by our Western Region subsea business from higher margin project backlog conversion and higher volumes in subsea services, particularly in the Gulf of Mexico, partially offset by additional contract value in 2013 related to an Angolan withholding tax adjustment.

Foreign currency translation unfavorably impacted operating profit in 2014 by $24.9 million compared to the prior year.

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 our subsea systems business from 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. This increase was partially offset by the recognition of the gain on our previously held equity interest in Schilling Robotics in 2012.

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

Surface Technologies

2014 Compared With 2013

Surface Technologies’ revenue increased $323.9 million in 2014 compared to the prior year. The revenue increase was driven by international growth in our surface wellhead business, primarily in the Middle East and Europe regions. Additionally, revenue in North America increased as the North American shale markets had higher activity compared to the prior year which drove additional demand for our well service pumps and flowline products in our fluid control business and surface wellhead products and services. Foreign currency translation unfavorably impacted revenue by $35.9 million in 2014 compared to the prior year.

Surface Technologies’ operating profit totaled $393.0 million, or 18.4% of revenue, in 2014, compared to the prior-year’s operating profit as a percentage of revenue of 14.2%. The margin improvement was primarily driven by the following:


•	Surface Wellhead - 2.5 percentage point increase due to higher volumes and higher margin projects in the Middle East and Europe regions; and


•	Fluid Control - 1.7 percentage point increase due to increased demand for our well service pumps and flowline products resulting from the improved North American shale markets in 2014.

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.

Energy Infrastructure

2014 Compared With 2013

Energy Infrastructure’s revenue decreased $59.8 million in 2014 compared to the prior year. The decrease in revenue was due to the sale of our Material Handling Products business in the second quarter of 2014. Foreign currency translation unfavorably impacted revenue by $4.1 million in 2014 compared to the prior year.

Energy Infrastructure’s operating profit totaled $52.5 million, or 9.4% of revenue, in 2014, compared to the prior-year’s operating profit as a percentage of revenue of 12.0%. The margin decline was primarily driven by the following:


•	Automation and Control - 2.0 percentage point decrease due to lower sales volumes and the execution of lower margin projects; and


•	Material Handling - 1.1 percentage point decrease due to the sale of our Material Handling Products business in the second quarter of 2014.

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.

Corporate Items

2014 Compared With 2013

Our corporate items reduced earnings by $132.5 million in 2014, compared to $165.6 million in 2013. The year-over-year decrease primarily reflected the following:


•	favorable variance related to the gain on sale of our Material Handling Products business of $84.3 million;


•	favorable variance related to the remeasurement of the Multi Phase Meters earn-out consideration of $25.1 million;


•	unfavorable variance in foreign currency, primarily related to an intercompany foreign currency loss, of $59.9 million; and an


•	unfavorable variance related to higher corporate staff expenses, primarily from increased bonus accruals, of $20.0 million.

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.

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)	2014			2013
Subsea Technologies	$	5,547.1		$	6,510.3
Surface Technologies	2,070.4			2,049.1
Energy Infrastructure	473.3			605.7
Intercompany eliminations and other	(6.2		)	(44.4		)
Total inbound orders	$	8,084.6		$	9,120.7

Order backlog is calculated as the estimated sales value of unfilled, confirmed customer orders at the reporting date. Translation negatively affected backlog by $520.8 million and $374.1 million for the years ended December 31, 2014 and 2013, respectively.



	Order Backlog December 31,
(In millions)	2014			2013
Subsea Technologies	$	5,793.1		$	5,988.8
Surface Technologies	654.2			742.4
Energy Infrastructure	187.0			288.4
Intercompany eliminations	(14.9		)	(21.4		)
Total order backlog	$	6,619.4		$	6,998.2

Order backlog for Subsea Technologies at December 31, 2014, decreased by $195.7 million compared to December 31, 2013, primarily due to the negative impact of foreign exchange translation. Subsea Technologies backlog of $5.8 billion at December 31, 2014, was composed of various subsea projects, including BP’s Mad Dog Phase 2 and Shah Deniz Stage 2; Chevron’s Agbami; CNR International’s Baobab Field Phase 3; Eni’s Block 15/06 East Hub and Jangkrik; ExxonMobil’s Julia; Petrobras’ tree frame agreement and pre-salt tree and manifold award; Statoil’s Snorre B Platform Workover System; Total’s Edradour and Egina; Tullow Ghana’s TEN; and Wintershall’s Maria. We expect to convert approximately 50% to 55% of December 31, 2014 backlog into revenue during 2015.

Order backlog for Surface Technologies at December 31, 2014 decreased by $88.2 million compared to December 31, 2013. The decrease was due to high conversion of backlog in the Middle East and the negative impact of foreign exchange translation.

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 revolving 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, 2014			December 31, 2013
Cash and cash equivalents	$	638.8		$	399.1
Short-term debt and current portion of long-term debt	(11.7		)	(42.5		)
Long-term debt, less current portion	(1,297.2		)	(1,329.8		)
Net debt	$	(670.1	)	$	(973.2	)

The change in our net debt position was primarily due to cash generated from operating activities from higher income from operations, partially offset by changes in our working capital position, payments for capital expenditures and increased treasury stock purchases.

Cash flows for each of the years in the three-year period ended December 31, 2014, were as follows:



	Year Ended December 31,
(In millions)	2014			2013			2012
Cash provided by operating activities	$	892.5		$	795.4		$	138.4
Cash required by investing activities	(285.1		)	(311.6		)	(1,019.9		)
Cash provided (required) by financing activities	(355.4		)	(422.3		)	881.4
Effect of exchange rate changes on cash and cash equivalents	(12.3		)	(4.5		)	(1.8		)
Increase (decrease) in cash and cash equivalents	$	239.7		$	57.0		$	(1.9	)

Operating Cash Flows

During 2014, we generated $892.5 million in cash flows from operating activities, which represented a $97.1 million increase compared to the prior year. Our cash flows from operating activities in 2013 were $657.0 million higher than 2012. The year-over-year increase in 2014 was due to higher income during the year, partially offset by a negative change in our working capital position driven by our portfolio of projects resulting from significant advance payments received in the prior year. 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 2012. 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 2014 were $285.1 million, primarily reflecting cash required by our capital expenditure program of $404.4 million during 2014 related to continued investments in capacity expansion and service asset investments primarily in our Subsea Technologies segment, partially offset by $105.6 million of proceeds related to the sale of our Material Handling Products business in the second quarter of 2014.

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 $355.4 million in 2014. The decrease in cash required from financing activities from the prior year was driven by higher payments to reduce our commercial paper position in 2013, payment of our outstanding balance under our revolving credit facility in 2013, partially offset by increased purchases of treasury stock during 2014.

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.

Debt and Liquidity

Total borrowings at December 31, 2014 and 2013, comprised the following:



	December 31,
(In millions)	2014		2013
Revolving credit facility	$	—	$	—
Commercial paper	469.1		501.4
2.00% Notes due 2017	299.6		299.5
3.45% Notes due 2022	499.7		499.6
Term loan	22.9		25.9
Foreign uncommitted credit facilities	7.9		31.9
Property financing	9.7		13.9
Total borrowings	$	1,308.9	$	1,372.2

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 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 revolving credit facility at December 31, 2014:



(In millions) Description	Amount		Debt Outstanding		Commercial Paper Outstanding (a)		Letters of Credit		Unused Capacity		Maturity
Five-year revolving credit facility	$	1,500.0	$	—	$	469.1	$	—	$	1,030.9	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 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 $469.1 million of commercial paper issued under our facility at December 31, 2014. 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, 2014.

Among other restrictions, the terms of the credit agreement include negative covenants related to liens and a financial covenant related to our debt-to-earnings ratio. As of December 31, 2014, 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 10 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Outlook for 2015

Historically, we have generated our liquidity and capital resources primarily through operations and, when needed, through our credit facility. We have $1,030.9 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. 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. Although we will continue to reach payment milestones on many of our projects, we expect our consolidated operating cash flow position in 2015 to slightly decrease as a result of the negative impact the decline in commodity prices will have on our overall business.

We expect to make contributions of approximately $15.9 million to our international pension plans during 2015. 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. Additionally, we expect to make contributions of approximately $4.0 million to our U.S. Non-Qualified Defined Benefit Pension Plan during 2015.

We project spending approximately $300 million in 2015 for capital expenditures, largely towards our growth of our subsea service offerings. During the second quarter of 2015, we expect to remit most of the $10 million withheld purchase price related to the acquisition of our automation and control business. Additional information 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. 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; however, we expect to repurchase approximately $100 million of common stock during 2015.

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, 2014:



	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)	$	1,301.0	$	3.8	$	797.4	$	0.1	$	499.7
Short-term debt	7.9		7.9		—		—		—
Interest on long-term debt ^(a)	156.0		23.3		46.5		34.5		51.7
Operating leases ^(b)	647.7		108.8		155.6		100.9		282.4
Purchase obligations ^(c)	1,344.5		1,216.0		128.5		—		—
Pension and other post-retirement benefits ^(d)	15.9		15.9		—		—		—
Unrecognized tax benefits ^(e)	41.0		41.0		—		—		—
Total contractual obligations	$	3,514.0	$	1,416.7	$	1,128.0	$	135.5	$	833.8

______________________________

^(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 our 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 2014, we paid $31.6 million for interest charges, net of interest capitalized.

^(b)

During 2014 we entered into construction and operating lease agreements to finance the construction of manufacturing and office facilities on land purchased in 2012 and located in Houston, TX. Upon expiration of the lease term in September 2021, we have the option to renew the lease, purchase the facilities or re-market the facilities on behalf of the lessor, including certain guarantees of residual value under the re-marketing option.

^(c)

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.


^(d)	We expect to contribute approximately $15.9 million to our international pension plans, representing primarily the U.K. and Norway qualified pension plans, in 2015. Required contributions for future years depend on factors that cannot be determined at this time. Additionally, we expect to contribute $4.0 million to our U.S. Non-Qualified Defined Benefit Pension Plan in 2015.


^(e)	It is reasonably possible that $41.0 million of liabilities for unrecognized tax benefits will be settled during 2015, and this amount is reflected in income taxes payable in our consolidated balance sheet as of December 31, 2014. 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, 2014:



	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 ^(a)	$	812.3	$	358.6	$	260.4	$	134.4	$	58.9
Surety bonds ^(a)	1.6		1.6		—		—		—
Third party guarantees ^(b)	20.0		—		20.0		—		—
Total other off-balance sheet arrangements	$	833.9	$	360.2	$	280.4	$	134.4	$	58.9

______________________________

^(a)

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.

^(b)

In August 2014 FMC Technologies entered into an arrangement to jointly guarantee the debt obligations under a revolving credit facility of FMC Technologies Offshore, LLC (“FTO Services”), our joint venture with Edison Chouest Offshore LLC. Information regarding our guarantee is incorporated herein by reference from Note 18 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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 about future events that affect the reported amounts of assets and liabilities at the date of the financial statements, the reported amounts of revenue and expenses during the periods presented and the related disclosures in the accompanying notes to the financial statements. 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 of accounting whereby 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 arising from these specific risks 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 of accounting was approximately 52%, 55% and 51% of total revenue recognized for the years ended December 31, 2014, 2013 and 2012, respectively. A significant portion of our total revenue recognized under the percentage of completion method of accounting 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. Profits are recognized based on the estimated project profit multiplied by the percentage complete. Adjustments to estimates of contract revenue, total contract cost, or extent of progress toward completion are often required as work progresses under the contract and as experience is gained, even though the scope of work required under the contract may not change. The nature of accounting for contracts under the percentage of completion method of accounting is such that refinements of the estimating process for changing conditions and new developments are continuous and characteristic of the process. Consequently, the amount of revenue recognized using the percentage of completion method of accounting is sensitive to changes in our estimates of total contract costs. For each contract in progress at December 31, 2014, 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 $33.1 million for the year ended December 31, 2014.

The total estimated contract cost in the percentage of completion method of 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 material 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 contracts using the percentage of completion method of accounting.

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 6 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. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future productivity of the asset, operating costs and capital decisions and all available information at the date of review.

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. We estimate the fair value of our reporting units using a discounted future cash flow model. The majority of the estimates and assumptions used in a discounted future cash flow model involve unobservable inputs reflecting management’s own assumptions about the assumptions market participants would use in estimating the fair value of a business. These estimates and assumptions include revenue growth rates and operating margins used to calculate projected future cash flows, discount rates 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, specifically our completion services and automation and control reporting units, could result in goodwill impairments. Factors that could trigger a lower fair value estimate include sustained price declines of the reporting unit’s products and services, cost increases, regulatory or political environment changes, changes in customer demand, and other changes in market conditions, which may affect certain market participant assumptions used in the discounted future cash flow model. We did not recognize any goodwill impairment for the years ended December 31, 2014 or 2013, 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 2014 or 2013 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, requires management to make assumptions about our future income over the lives of the deferred tax assets, and finally, 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, 2014, 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, 2014, 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 Pension and Other Post-Retirement Benefit Plans

Our pension and other post-retirement (health care and life insurance) obligations are described in Note 12 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

The determination of the projected benefit obligations of our pension and other post-retirement benefit plans are important to the recorded amounts of such obligations on our consolidated balance sheet and to the amount of pension expense in our consolidated statements of income. In order to measure the obligations and expense 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 and difficulty in estimating these measures. Different estimates used by management could result in our recognition of 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 long-term rate of return on plan assets are primarily based on investment yields available and the historical performance of our plan assets, respectively. These measures are critical accounting estimates because they are subject to management’s judgment and can materially affect net income.

The discount rate affects the interest cost component of net periodic pension cost and the calculation of the projected benefit obligation. 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 expected long-term rate of return on plan assets is a component of net periodic pension cost. Our estimate of the expected long-term 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. 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.

Holding other assumptions constant, the following table illustrates the sensitivity of changes in the discount rate and expected long-term return on plan assets on pension expense and the projected benefit obligation:



(In millions, except basis points)	Increase (Decrease) in 2014 Pension Expense Before Income Taxes			Increase (Decrease) in Projected Benefit Obligation at December 31, 2014
50 basis point decrease in discount rate	$	9.7		$	95.7
50 basis point increase in discount rate	$	(9.9	)	$	(86.2	)
50 basis point decrease in expected long-term rate of return on plan assets	$	4.6
50 basis point increase in expected long-term rate of return on plan assets	$	(4.6	)

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

Other Matters

During the second quarter of 2014, the Company received an inquiry and a subpoena from the SEC seeking information about accruals within the automation and control business unit for paid time off (“PTO”). The inquiry addressed the reversal of an accrual for PTO which understated the liability for PTO in the business unit for the quarter ended March 31, 2013. During the fourth quarter of 2014, the Company informed the SEC about an additional matter the Company identified within the automation and control business unit. The Company received a second subpoena in the fourth quarter of 2014. The Company has cooperated and fully responded to all requests for information. The Company has assessed the matters individually and collectively and concluded the impact is immaterial to the Company’s consolidated financial statements as of and for the year ended December 31, 2014. The Company discussed these matters with its independent registered public accounting firm and the Company’s Audit Committee.

Recently Issued Accounting Standards

In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This update requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will supersede most existing GAAP related to revenue recognition and will supersede some cost guidance in existing GAAP related to construction-type and production-type contract accounting. Additionally, the ASU will significantly increase disclosures related to revenue recognition. The amendments in the ASU are effective for the Company on January 1, 2017. Early application is not permitted. Entities are permitted to apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. The Company has not determined the method to be utilized upon adoption. The impacts that adoption of the ASU is expected to have on the Company’s consolidated financial statements and related disclosures are being evaluated. Additionally, the Company has not determined the effect of the ASU on its internal control over financial reporting or other changes in business practices and processes.

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, 2014 and 2013, substantially all of 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, 2014, would have changed our revenue and income before income taxes attributable to FMC Technologies, Inc. by approximately 4% and 3%, 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 $107.4 million in the net fair value of cash flow hedges reflected in our consolidated balance sheet at December 31, 2014. 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, 2014, we had unhedged variable rate debt of $469.1 million with a weighted average interest rate of 0.52%. Using sensitivity analysis to measure the impact of a 10% adverse movement in the interest rate, or five 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 $0.4 million in earnings in the period of change. Based on our portfolio as of December 31, 2014, 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 defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. 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 consolidated financial statements in accordance with U.S. 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, 2014.

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, 2014, and has issued an audit report on the Company’s internal control over financial reporting as of December 31, 2014, which is included herein.



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

February 20, 2015

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, 2014, 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, 2014, 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, 2014 and 2013, 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, 2014, and our report dated February 20, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 20, 2015

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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, 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, 2014, 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 20, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 20, 2015

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



	Year Ended December 31,
(In millions, except per share data)	2014			2013			2012
Revenue:
Product revenue	$	6,335.7		$	5,724.7		$	5,198.2
Service revenue	1,276.5			1,066.0			656.6
Lease and other revenue	330.4			335.5			296.6
Total revenue	7,942.6			7,126.2			6,151.4
Costs and expenses:
Cost of product revenue	4,860.0			4,562.4			4,155.7
Cost of service revenue	925.0			792.7			486.8
Cost of lease and other revenue	214.8			216.3			190.4
Selling, general and administrative expense	750.6			694.8			596.9
Research and development expense	123.7			112.4			116.8
Total costs and expenses	6,874.1			6,378.6			5,546.6
Gain on sale of Material Handling Products (Note 5)	84.3			—			—
Other income (expense), net	(54.0		)	5.3			23.0
Income before interest income, interest expense and income taxes	1,098.8			752.9			627.8
Interest income	1.1			0.7			(0.4		)
Interest expense	(33.6		)	(34.4		)	(26.2		)
Income before income taxes	1,066.3			719.2			601.2
Provision for income taxes	361.0			212.6			166.4
Net income	705.3			506.6			434.8
Net income attributable to noncontrolling interests	(5.4		)	(5.2		)	(4.8		)
Net income attributable to FMC Technologies, Inc.	$	699.9		$	501.4		$	430.0
Earnings per share attributable to FMC Technologies, Inc. (Note 3):
Basic	$	2.96		$	2.10		$	1.79
Diluted	$	2.95		$	2.10		$	1.78
Weighted average shares outstanding (Note 3):
Basic	236.3			238.3			239.7
Diluted	236.9			239.1			240.9

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

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31,
(In millions)	2014			2013			2012
Net income	$	705.3		$	506.6		$	434.8
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments ⁽¹⁾	(107.6		)	(99.7		)	(1.8		)
Net gains (losses) on hedging instruments:
Net gains (losses) arising during the period	(108.4		)	27.1			29.0
Reclassification adjustment for net gains included in net income	(0.8		)	(5.2		)	(2.3		)
Net gains (losses) on hedging instruments ⁽²⁾	(109.2		)	21.9			26.7
Pension and other post-retirement benefits:
Net actuarial gain (loss) arising during the period	(152.7		)	112.5			(5.1		)
Prior service cost arising during the period	(1.7		)	(0.4		)	—
Reclassification adjustment for settlement losses included in net income	15.7			3.2			9.6
Reclassification adjustment for amortization of prior service cost (credit) included in net income	0.3			(0.3		)	(0.7		)
Reclassification adjustment for amortization of net actuarial loss included in net income	12.3			18.2			19.3
Reclassification adjustment for amortization of transition asset included in net income	(0.1		)	(0.1		)	(0.2		)
Net pension and other post-retirement benefits ⁽³⁾	(126.2		)	133.1			22.9
Other comprehensive income (loss), net of tax	(343.0		)	55.3			47.8
Comprehensive income	362.3			561.9			482.6
Comprehensive income attributable to noncontrolling interest	(5.4		)	(5.2		)	(4.8		)
Comprehensive income attributable to FMC Technologies, Inc.	$	356.9		$	556.7		$	477.8

______________________


⁽¹⁾	Net of income tax (expense) benefit of $7.2, $(1.6) and $(2.2) for the years ended December 31, 2014, 2013 and 2012, respectively.


⁽²⁾	Net of income tax (expense) benefit of $25.7, $1.0 and $(12.3) for the years ended December 31, 2014, 2013 and 2012, respectively.


⁽³⁾	Net of income tax (expense) benefit of $56.9, $(81.8) and $(6.5) for the years ended December 31, 2014, 2013 and 2012, 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)	2014			2013
Assets
Cash and cash equivalents	$	638.8		$	399.1
Trade receivables, net of allowances of $9.4 in 2014 and $7.4 in 2013 (Note 21)	2,127.0			2,067.2
Inventories, net (Note 6)	1,021.2			980.4
Derivative financial instruments (Note 15)	197.6			165.9
Prepaid expenses	48.5			41.5
Deferred income taxes (Note 11)	70.8			59.1
Other current assets	332.5			309.8
Total current assets	4,436.4			4,023.0
Investments	35.9			44.3
Property, plant and equipment, net (Note 7)	1,458.4			1,349.1
Goodwill (Note 8)	552.1			580.7
Intangible assets, net (Note 8)	282.9			315.3
Deferred income taxes (Note 11)	106.5			36.9
Derivative financial instruments (Note 15)	134.9			68.5
Other assets	168.5			187.8
Total assets	$	7,175.6		$	6,605.6
Liabilities and equity
Short-term debt and current portion of long-term debt (Note 10)	$	11.7		$	42.5
Accounts payable, trade	723.5			750.7
Advance payments and progress billings	965.2			803.2
Accrued payroll	256.8			222.0
Derivative financial instruments (Note 15)	230.2			171.3
Income taxes payable	152.9			138.1
Deferred income taxes (Note 11)	54.2			66.4
Other current liabilities	389.1			420.5
Total current liabilities	2,783.6			2,614.7
Long-term debt, less current portion (Note 10)	1,297.2			1,329.8
Accrued pension and other post-retirement benefits, less current portion (Note 12)	236.7			84.0
Derivative financial instruments (Note 15)	220.2			47.1
Deferred income taxes (Note 11)	54.3			90.3
Other liabilities	105.9			103.4
Commitments and contingent liabilities (Note 18)
Stockholders’ equity (Note 14):
Preferred stock, $0.01 par value, 12.0 shares authorized; no shares issued in 2014 or 2013	—			—
Common stock, $0.01 par value, 600.0 shares authorized in 2014 and 2013; 286.3 shares issued in 2014 and 2013; and 231.5 and 235.8 shares outstanding in 2014 and 2013, respectively	2.9			2.9
Common stock held in employee benefit trust, at cost; 0.2 shares in 2014 and 2013	(8.0		)	(7.7		)
Treasury stock, at cost, 54.6 and 50.3 shares in 2014 and 2013, respectively	(1,431.1		)	(1,196.6		)
Capital in excess of par value of common stock	731.9			713.2
Retained earnings	3,844.3			3,146.1
Accumulated other comprehensive loss	(683.7		)	(340.7		)
Total FMC Technologies, Inc. stockholders’ equity	2,456.3			2,317.2
Noncontrolling interests	21.4			19.1
Total equity	2,477.7			2,336.3
Total liabilities and equity	$	7,175.6		$	6,605.6

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)	2014			2013			2012
Cash provided (required) by operating activities:
Net income	$	705.3		$	506.6		$	434.8
Adjustments to reconcile net income to cash provided (required) by operating activities:
Depreciation	170.8			156.0			113.1
Amortization	61.7			53.8			33.1
Employee benefit plan and stock-based compensation costs	89.3			93.5			110.4
Deferred income tax benefit	(18.1		)	(20.4		)	(9.8		)
Unrealized loss (gain) on derivative instruments	54.4			(5.7		)	13.5
Gain on sale of Material Handling Products	(84.3		)	—			—
Multi Phase Meters contingent earn-out consideration obligation	3.7			28.8			42.0
Other	7.1			1.6			(6.2		)
Changes in operating assets and liabilities, net of effects of acquisitions:
Trade receivables, net	(243.0		)	(391.0		)	(337.3		)
Inventories, net	(99.4		)	(28.9		)	(206.6		)
Accounts payable, trade	33.8			103.8			83.0
Advance payments and progress billings	225.0			329.0			25.9
Income taxes	4.4			77.6			(71.4		)
Payment of Multi Phase Meters earn-out consideration	(43.6		)	(32.2		)	—
Accrued pension and other post-retirement benefits, net	(32.0		)	(60.1		)	(63.1		)
Other assets and liabilities, net	57.4			(17.0		)	(23.0		)
Cash provided by operating activities	892.5			795.4			138.4
Cash provided (required) by investing activities:
Capital expenditures	(404.4		)	(314.1		)	(405.6		)
Acquisitions, net of cash and cash equivalents acquired	—			—			(615.5		)
Proceeds from sale of Material Handling Products, net of cash divested	105.6			—			—
Proceeds from disposal of assets	16.2			7.4			3.2
Other	(2.5		)	(4.9		)	(2.0		)
Cash required by investing activities	(285.1		)	(311.6		)	(1,019.9		)
Cash provided (required) by financing activities:
Net increase (decrease) in short-term debt	(25.8		)	8.5			13.4
Net increase (decrease) in commercial paper	(32.3		)	(168.4		)	189.7
Proceeds from issuance of long-term debt	—			26.2			1,068.9
Repayments of long-term debt	(1.6		)	(136.0		)	(288.8		)
Purchase of treasury stock	(247.6		)	(116.3		)	(91.1		)
Payment of Multi Phase Meters earn-out consideration	(31.0		)	(25.1		)	—
Payments related to taxes withheld on stock-based compensation	(13.0		)	(17.5		)	(34.8		)
Excess tax benefits	2.3			8.0			27.1
Other	(6.4		)	(1.7		)	(3.0		)
Cash provided (required) by financing activities	(355.4		)	(422.3		)	881.4
Effect of exchange rate changes on cash and cash equivalents	(12.3		)	(4.5		)	(1.8		)
Increase (decrease) in cash and cash equivalents	239.7			57.0			(1.9		)
Cash and cash equivalents, beginning of year	399.1			342.1			344.0
Cash and cash equivalents, end of year	$	638.8		$	399.1		$	342.1

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, 2011	$	2.9	$	(1,047.7	)	$	698.5		$	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 14)	—		(91.1		)	—			—		—			—			(91.1		)
Reissuances of treasury stock (Note 14)	—		30.4			(30.4		)	—		—			—			—
Net purchases of common stock for employee benefit trust	—		(2.0		)	0.6			—		—			—			(1.4		)
Stock-based compensation (Note 13)	—		—			34.0			—		—			—			34.0
Other	—		—			—			—		—			(1.6		)	(1.6		)
Balance at December 31, 2012	$	2.9	$	(1,110.4	)	$	695.7		$	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 14)	—		(116.3		)	—			—		—			—			(116.3		)
Reissuances of treasury stock (Note 14)	—		22.3			(22.3		)	—		—			—			—
Net purchases of common stock for employee benefit trust	—		0.1			1.0			—		—			—			1.1
Stock-based compensation (Note 13)	—		—			47.7			—		—			—			47.7
Other	—		—			—			—		—			(2.4		)	(2.4		)
Balance at December 31, 2013	$	2.9	$	(1,204.3	)	$	713.2		$	3,146.1	$	(340.7	)	$	19.1		$	2,336.3



(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, 2013	$	2.9	$	(1,204.3	)	$	713.2		$	3,146.1		$	(340.7	)	$	19.1		$	2,336.3
Net income	—		—			—			699.9			—			5.4			705.3
Other comprehensive loss	—		—			—			—			(343.0		)	—			(343.0		)
Issuance of common stock	—		—			0.2			—			—			—			0.2
Excess tax benefits on stock-based payment arrangements	—		—			2.3			—			—			—			2.3
Taxes withheld on issuance of stock-based awards	—		—			(13.0		)	—			—			—			(13.0		)
Purchases of treasury stock (Note 14)	—		(247.6		)	—			—			—			—			(247.6		)
Reissuances of treasury stock (Note 14)	—		13.1			(13.1		)	—			—			—			—
Net purchases of common stock for employee benefit trust	—		(0.3		)	0.5			—			—			—			0.2
Stock-based compensation (Note 13)	—		—			44.9			—			—			—			44.9
Purchase of noncontrolling interest	—		—			(3.1		)	—			—			0.1			(3.0		)
Other	—		—			—			(1.7		)	—			(3.2		)	(4.9		)
Balance at December 31, 2014	$	2.9	$	(1,439.1	)	$	731.9		$	3,844.3		$	(683.7	)	$	21.4		$	2,477.7

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; however, upon issuance of the common stock pursuant to the stock split, an amount equal to the aggregate par value of the additional shares of common stock issued was not reclassified from capital in excess of par value to common stock during the first quarter of 2011. This adjustment was made during the first quarter of 2014. All prior-year amounts have been revised to conform to the current year presentation. This adjustment had no overall effect on total equity and did not impact our overall financial position or results of operations for any period presented.

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 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 in our 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 in our consolidated balance sheets. Revenue generated from the installation portion of construction-type contracts is included in product revenue in our consolidated statements of income.

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, 2014 or 2013.

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 primarily comprised 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.

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.

Tax benefits related to uncertain tax positions are recognized when it is more likely than not, based on the technical merits, that the position will be sustained upon examination.

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, 2014, we adopted Accounting Standards Update (“ASU”) 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” issued by the Financial Accounting Standards Board (“FASB”). 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 are 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 is applied prospectively, effective January 1, 2014. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements.

Effective January 1, 2014, we adopted ASU No. 2014-08, “Reporting Discontinued Operations and Disclosures of

Disposals of Components of an Entity” issued by the FASB. This update changes the requirements of reporting discontinued operations. Under the amended guidance, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update are effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years, with early adoption permitted. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements.

Effective December 31, 2014, we adopted ASU No. 2014-15, “Presentation of Financial Statements - Going Concern.” This update provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and on determining when and how entities must disclose going concern uncertainties in the financial statements. The update requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date of issuance of the entity’s financial statements. The amendments in this ASU are effective for the Company for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. 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)	2014		2013		2012
Net income attributable to FMC Technologies, Inc.	$	699.9	$	501.4	$	430.0
Weighted average number of shares outstanding	236.3		238.3		239.7
Dilutive effect of restricted stock units and stock options	0.6		0.8		1.2
Total shares and dilutive securities	236.9		239.1		240.9

Basic earnings per share attributable to FMC Technologies, Inc.	$	2.96	$	2.10	$	1.79
Diluted earnings per share attributable to FMC Technologies, Inc.	$	2.95	$	2.10	$	1.78

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, for $282.8 million in cash, and closed the transaction on April 25, 2012. Prior to April 25, 2012, we owned 45% of Schilling Robotics. 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.

Schilling Robotics 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.

Control Systems International, Inc.—On April 30, 2012, we acquired 100% of Control Systems International, Inc. (“CSI”) for $59.0 million in consideration transferred, comprised of $49.0 million in cash and $10.0 million withheld ("holdback") 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. We may deduct from the holdback any eligible amounts and pay CSI the net amount three years after the closing date.

CSI 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”) for $287.0 million in cash, 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 flowback services and wireline services. The acquisition of Pure Energy is complementing the existing products and services of our Surface Technologies segment and is expected to create client value by providing an integrated well site solution.

Goodwill recognized for Schilling Robotics, CSI and Pure Energy as of the acquisition dates were $215.7 million, $30.7 million, and $85.5 million, respectively. The goodwill recognized is primarily attributable to expected synergies and assembled workforce acquired. 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.

NOTE 5. SALE OF MATERIAL HANDLING PRODUCTS

On April 30, 2014, we completed the sale of our equity interests of Technisys, Inc., a Utah corporation, and FMC Technologies Energy Holdings Ltd., a private limited liability company organized under the laws of Hong Kong, and assets primarily representing a product line of our material handling business (“Material Handling Products”) to Syntron Material Handling, LLC, an affiliate of Levine Leichtman Capital Partners Private Capital Solutions II, L.P. Material Handling Products was historically reported in our Energy Infrastructure segment. Net of working capital adjustments, we recognized a pretax gain of $84.3 million on the sale during the year ended December 31, 2014.

NOTE 6. INVENTORIES

Inventories consisted of the following:



	December 31,
(In millions)	2014			2013
Raw materials	$	196.6		$	186.3
Work in process	166.1			141.4
Finished goods	849.9			830.3
	1,212.6			1,158.0
LIFO and valuation adjustments	(191.4		)	(177.6		)
Inventory, net	$	1,021.2		$	980.4

Net inventories accounted for under the LIFO method totaled $370.8 million and $336.4 million at December 31, 2014 and 2013, respectively. The current replacement costs of LIFO inventories exceeded their recorded values by $94.6 million and $91.5 million at December 31, 2014 and 2013, respectively. There were no reductions to the base LIFO inventory in 2014 or 2012. 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.

NOTE 7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	December 31,
(In millions)	2014			2013
Land and land improvements	$	83.8		$	83.0
Buildings	410.6			379.4
Machinery and equipment	1,530.5			1,438.6
Construction in process	266.9			218.3
	2,291.8			2,119.3
Accumulated depreciation	(833.4		)	(770.2		)
Property, plant and equipment, net	$	1,458.4		$	1,349.1

Depreciation expense was $170.8, million, $156.0 million and $113.1 million in 2014, 2013 and 2012, respectively. The amount of interest cost capitalized was $0.9 million, $0.7 million and $1.4 million in 2014, 2013 and 2012, respectively.

NOTE 8. GOODWILL AND INTANGIBLE ASSETS

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



(In millions)	Subsea Technologies			Surface Technologies			Energy Infrastructure			Total
December 31, 2013	$	396.9		$	92.4		$	91.4		$	580.7
Material Handling Products divestiture ⁽¹⁾	—			—			(6.0		)	(6.0		)
Translation	(18.1		)	(4.5		)	—			(22.6		)
December 31, 2014	$	378.8		$	87.9		$	85.4		$	552.1

______________________________


⁽¹⁾	See Note 5 for additional disclosure.

We have not recognized any impairment for the years ended December 31, 2014 or 2013, 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 2014 or 2013 requiring us to perform additional impairment reviews.

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



	December 31,
	2014				2013
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	142.4	$	33.5	$	148.6	$	27.7
Patents and acquired technology	217.9		70.8		221.8		56.5
Trademarks	35.9		9.4		36.2		7.6
Other	5.9		5.5		6.0		5.5
Total intangible assets	$	402.1	$	119.2	$	412.6	$	97.3

We did not have any material additions to our intangible assets during 2014 or 2013. All of our acquired identifiable intangible assets are subject to amortization and, where applicable, foreign currency translation adjustments. We recorded $25.9 million, $26.9 million and $20.8 million in amortization expense related to intangible assets during the years ended December 31, 2014, 2013 and 2012, respectively. During the years 2015 through 2019, annual amortization expense is expected to be as follows: $24.9 million in 2015, $24.3 million in 2016, $23.5 million in 2017, $23.3 million in 2018, $23.2 million in 2019 and $163.7 million thereafter.

NOTE 9. 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 the 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. Annual rent of $4.2 million escalates 2.0% per year, and beginning in April 2017, annual rent will be re-established at $4.5 million and escalate 2.0% per year. The lease was recorded as an operating lease.

NOTE 10. DEBT

Credit facility—On March 26, 2012, we entered into a $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, 2014, had a weighted average interest rate of 0.52%.

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 subleased this property to a third party under a lease agreement that was accounted for as an operating lease. We accounted for the transaction as a financing transaction and were amortizing the related obligation using an effective annual interest rate of 5.37%. In September 2014, the sale and leaseback expired and resulted in an immaterial noncash gain. 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)	2014		2013
Property financing	$	3.8	$	10.5
Foreign uncommitted credit facilities	7.9		31.9
Other	—		0.1
Total short-term debt and current portion of long-term debt	$	11.7	$	42.5

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



	December 31,
(In millions)	2014			2013
Revolving credit facility	$	—		$	—
Commercial paper ⁽¹⁾	469.1			501.4
2.00% Notes due 2017	299.6			299.5
3.45% Notes due 2022	499.7			499.6
Term loan	22.9			25.9
Property financing	9.7			13.9
Total long-term debt	1,301.0			1,340.3
Less: current portion	(3.8		)	(10.5		)
Long-term debt, less current portion	$	1,297.2		$	1,329.8

_______________________

⁽¹⁾

At December 31, 2014 and 2013, 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, 2014 and 2013.

Maturities of total long-term debt as of December 31, 2014, are payable as follows: $3.8 million in 2015, $25.7 million in 2016, $771.7 million in 2017, $0.1 million in 2018, and $499.7 million in 2022.

NOTE 11. INCOME TAXES

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



	Year Ended December 31,
(In millions)	2014		2013		2012
Domestic	$	353.2	$	150.7	$	125.5
Foreign	707.7		563.3		470.9
Income before income taxes attributable to FMC Technologies, Inc.	$	1,060.9	$	714.0	$	596.4

The provision for income taxes consisted of:



	Year Ended December 31,
(In millions)	2014			2013			2012
Current:
Federal	$	139.6		$	77.8		$	41.5
State	11.7			5.6			2.9
Foreign	227.8			149.6			131.8
Total current	379.1			233.0			176.2
Deferred:
Increase in the valuation allowance for deferred tax assets	34.1			0.5			0.5
Decrease of deferred tax liability for change in tax rates	(2.3		)	(4.3		)	(1.3		)
Other deferred tax (benefit) expense	(49.9		)	(16.6		)	(9.0		)
Total deferred	(18.1		)	(20.4		)	(9.8		)
Provision for income taxes	$	361.0		$	212.6		$	166.4

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



	December 31,
(In millions)	2014			2013
Deferred tax assets attributable to:
Accrued expenses	$	58.0		$	56.6
Non deductible interest	29.2			—
Foreign tax credit carryforwards	29.3			14.0
Accrued pension and other post-retirement benefits	91.8			26.5
Stock-based compensation	28.9			25.3
Net operating loss carryforwards	48.7			47.8
Inventories	31.7			25.9
Norwegian correction tax	50.4			61.9
Foreign exchange	40.2			3.7
Deferred tax assets	408.2			261.7
Valuation allowance	(38.9		)	(4.7		)
Deferred tax assets, net of valuation allowance	369.3			257.0
Deferred tax liabilities attributable to:
Revenue in excess of billings on contracts accounted for under the percentage of completion method	105.2			137.0
U.S. tax on foreign subsidiaries’ undistributed earnings not indefinitely reinvested	52.5			43.5
Property, plant and equipment, goodwill and other assets	142.8			137.2
Deferred tax liabilities	300.5			317.7
Net deferred tax assets (liabilities)	$	68.8		$	(60.7	)

At December 31, 2014 and 2013, 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, 2014 were U.S. foreign tax credit carryforwards of $29.3 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 $186.6 million, $196.2 million and $118.3 million, in 2014, 2013 and 2012, 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 2017. 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.

Deferred tax assets also include tax benefits of $29.2 million related to certain intercompany interest costs which are not currently deductible, but which may be deductible in future periods. If not deducted, these costs will become permanently nondeductible beginning in 2025. Management believes that it is more likely than not that we will not be able to deduct these costs before expiration of the carry forward period; 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, 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
Additions for tax positions related to prior years	0.6			0.4			1.0
Reductions for tax positions due to settlements	(1.4		)	(0.3		)	(1.7		)
Balance at December 31, 2014	$	36.3		$	7.2		$	43.5

At December 31, 2014, 2013 and 2012, there were $43.1 million, $41.7 million and $36.4 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 $41.0 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. 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, 2014.

The following tax years and thereafter remain subject to examination: 2004 for Norway, 2009 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,
	2014		2013		2012
Statutory U.S. federal income tax rate	35	%	35	%	35	%
Net difference resulting from:
Foreign earnings subject to different tax rates	(8	)	(13	)	(12	)
Foreign earnings subject to U.S. tax	2		2		4
Non deductible Multi Phase Meters earn-out adjustments	—		1		2
Settlement of foreign audits	—		1		—
Foreign withholding taxes	2		3		—
Change in valuation allowance	3		—		—
Other	—		1		(1	)
Effective income tax rate	34	%	30	%	28	%

We have provided U.S. income taxes on $1,571.6 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 $1,619.2 million at December 31, 2014. The amount of applicable U.S. income taxes that would be incurred if these earnings were repatriated is approximately $491.5 million.

We benefit from income tax holidays in Singapore and Malaysia which will expire after 2018 for Singapore and 2015 and 2018 for Malaysia. For the years ended December 31, 2014 and 2013, these tax holidays reduced our provision for income taxes by $1.3 million, or $0.01 per share on a diluted basis, and $12.7 million, or $0.05 per share on a diluted basis, respectively.

NOTE 12. 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 (“frozen participants”). 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.

In 2014 the Company amended the U.S. Qualified Pension Plan, and effective June 1, 2014, the assets and liabilities attributable to participants who are (i) either frozen participants or participants that had terminated service and subsequently became re-employed on or after January 1, 2010, and (ii) active employees of FMC Technologies as of June 1, 2014 were transferred from the U.S. Qualified Pension Plan to the FMC Technologies, Inc. Frozen Retirement Plan (“Frozen Plan”). Under the Frozen Plan, participants had the option to accept cash or an annuity upon the Frozen Plan’s termination. In December 2014, settlement payments were made based on frozen participants’ elections and settlement costs were recorded during 2014.

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, 2014 and 2013, were as follows:



	Pensions												Other Post-retirement Benefits
	2014						2013						2014			2013
(In millions)	U.S.			Int’l			U.S.			Int’l
Accumulated benefit obligation	$	552.4		$	406.3		$	513.3		$	360.1
Projected benefit obligation at January 1	$	585.0		$	438.8		$	692.9		$	372.3		$	6.7		$	8.7
Service cost	13.8			16.7			16.5			14.7			0.1			0.1
Interest cost	29.1			18.5			25.8			16.1			0.3			0.2
Actuarial (gain) loss	101.8			71.6			(119.8		)	45.6			4.0			(1.7		)
Amendments	2.4			0.3			—			0.6			(0.1		)	—
Settlements	(63.8		)	—			(11.1		)	—			—			—
Foreign currency exchange rate changes	—			(53.6		)	—			(2.5		)	—			—
Plan participants’ contributions	—			2.4			—			2.2			—			—
Benefits paid	(27.7		)	(12.2		)	(19.3		)	(10.2		)	(0.6		)	(0.6		)
Projected benefit obligation at December 31	640.6			482.5			585.0			438.8			10.4			6.7
Fair value of plan assets at January 1	576.8			400.8			462.5			327.9			—			—
Actual return on plan assets	8.5			13.5			115.2			52.2			—			—
Company contributions	11.0			22.6			29.5			30.1			0.6			0.6
Foreign currency exchange rate changes	—			(40.4		)	—			(1.4		)	—			—
Settlements	(63.8		)	—			(11.1		)	—			—			—
Plan participants’ contributions	—			2.4			—			2.2			—			—
Benefits paid	(27.7		)	(12.2		)	(19.3		)	(10.2		)	(0.6		)	(0.6		)
Fair value of plan assets at December 31	504.8			386.7			576.8			400.8			—			—
Funded status of the plans (liability) at December 31	$	(135.8	)	$	(95.8	)	$	(8.2	)	$	(38.0	)	$	(10.4	)	$	(6.7	)



	Pensions												Other Post-retirement Benefits
	2014						2013						2014			2013
(In millions)	U.S.			Int’l			U.S.			Int’l
Other assets	$	—		$	—		$	38.3		$	3.8		$	—		$	—
Current portion of accrued pension and other post-retirement benefits	(4.1		)	(0.4		)	(9.1		)	(1.3		)	(0.8		)	(0.6		)
Accrued pension and other post-retirement benefits, net of current portion	(131.7		)	(95.4		)	(37.4		)	(40.5		)	(9.6		)	(6.1		)
Funded status recognized in the consolidated balance sheets at December 31	$	(135.8	)	$	(95.8	)	$	(8.2	)	$	(38.0	)	$	(10.4	)	$	(6.7	)

The following table summarizes the pre-tax amounts in accumulated other comprehensive (income) loss at December 31, 2014 and 2013 that have not been recognized as components of net periodic benefit cost:



	Pensions										Other Post-retirement Benefits
	2014					2013					2014			2013
(In millions)	U.S.		Int’l			U.S.		Int’l
Pre-tax amounts recognized in accumulated other comprehensive (income) loss:
Unrecognized actuarial (gain) loss	$	234.9	$	187.8		$	130.1	$	113.6		$	1.1		$	(3.2	)
Unrecognized prior service (credit) cost	0.2		1.3			0.1		1.5			(0.1		)	—
Unrecognized transition asset	—		(0.2		)	—		(0.4		)	—			—
Accumulated other comprehensive (income) loss at December 31	$	235.1	$	188.9		$	130.2	$	114.7		$	1.0		$	(3.2	)

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, 2014 and 2013:



	Pensions								Other Post-retirement Benefits
	2014				2013				2014		2013
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded projected benefit obligation:
Aggregate projected benefit obligation	$	640.6	$	482.5	$	46.4	$	151.8	$	10.4	$	6.7
Aggregate fair value of plan assets	$	504.8	$	386.7	$	—	$	110.1	$	—	$	—



	Pensions								Other Post-retirement Benefits
	2014				2013				2014	2013
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded accumulated benefit obligation:
Aggregate accumulated benefit obligation	$	552.4	$	145.0	$	36.2	$	28.9
Aggregate fair value of plan assets	$	504.8	$	103.1	$	—	$	9.0

The following table summarizes the components of net periodic benefit cost (income) for the years ended December 31, 2014, 2013 and 2012:



	Pensions																		Other Post-retirement Benefits
	2014						2013						2012						2014			2013			2012
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l
Components of net periodic benefit cost (income):
Service cost	$	13.8		$	16.7		$	16.5		$	14.7		$	14.6		$	37.2		$	0.1		$	0.1		$	0.1
Interest cost	29.1			18.5			25.8			16.1			26.9			21.4			0.3			0.2			0.4
Expected return on plan assets	(46.3		)	(30.0		)	(41.6		)	(23.7		)	(39.9		)	(26.4		)	—			—			—
Settlement cost	22.5			—			5.1			—			5.6			8.5			—			—			—
Curtailment cost	2.4			—			—			—			—			—			—			—			—
Amortization of transition asset	—			(0.1		)	—			(0.1		)	—			(0.2		)	—			—			—
Amortization of prior service cost (credit)	(0.1		)	0.4			(0.1		)	0.1			(0.1		)	0.1			—			(0.5		)	(1.1		)
Amortization of net actuarial loss (gain)	12.2			6.7			26.6			5.3			23.9			8.1			(0.3		)	(0.2		)	(0.2		)
Net periodic benefit cost (income)	$	33.6		$	12.2		$	32.3		$	12.4		$	31.0		$	48.7		$	0.1		$	(0.4	)	$	(0.8	)

The following table summarizes changes in plan assets and benefit obligations recognized in other comprehensive income (loss) for the years ended December 31, 2014, 2013 and 2012:



	Pensions																		Other Post-retirement Benefits
	2014						2013						2012						2014			2013			2012
(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	$	(139.6	)	$	(80.9	)	$	193.3		$	(15.6	)	$	(68.9	)	$	53.8		$	(4.0	)	$	1.7		$	—
Prior service (cost) credit arising during period	(2.3		)	(0.3		)	—			(0.6		)	—			—			0.1			—			—
Settlements and curtailments	24.9			—			5.1			—			5.6			8.5			—			—			—
Amortization of net actuarial loss (gain)	12.2			6.7			26.6			5.3			23.9			8.0			(0.3		)	(0.2		)	(0.2		)
Amortization of prior service cost (credit)	(0.1		)	0.4			(0.1		)	0.1			(0.1		)	0.1			—			(0.5		)	(1.1		)
Amortization of transition asset	—			(0.1		)	—			(0.1		)	—			(0.2		)	—			—			—
Total recognized in other comprehensive income (loss)	$	(104.9	)	$	(74.2	)	$	224.9		$	(10.9	)	$	(39.5	)	$	70.2		$	(4.2	)	$	1.0		$	(1.3	)

Included in accumulated other comprehensive income (loss) at December 31, 2014, are noncash, pre-tax charges which have not yet been recognized in net periodic benefit cost (income). The estimated amounts expected to 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)	$	19.5	$	13.0		$	—
Prior service cost (credit)	$	—	$	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
	2014				2013				2014		2013
	U.S.		Int’l		U.S.		Int’l
Discount rate	4.20	%	3.21	%	5.10	%	4.30	%	4.20	%	5.10	%
Rate of compensation increase	4.00	%	3.84	%	4.00	%	4.29	%	—		—

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



	Pensions												Other Post-retirement Benefits
	2014				2013				2012				2014		2013		2012
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Discount rate	5.10	%	4.30	%	3.90	%	4.46	%	4.60	%	4.54	%	5.10	%	3.90	%	4.60	%
Rate of compensation increase	4.00	%	4.29	%	4.00	%	3.98	%	4.00	%	4.05	%	—		—		—
Expected rate of return on plan assets	9.00	%	7.61	%	9.00	%	7.44	%	9.00	%	7.62	%	—		—		—

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, 2014 and 2013.


•	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, 2014 and 2013. Refer to “Fair value measurements” in Note 1 to these consolidated financial statements for a description of the levels.



	U.S.								International
December 31, 2014 (In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Cash	$	121.2	$	121.2	$	—	$	—	$	0.3	$	0.3	$	—	$	—
Equity securities:
U.S. companies:
Large cap	54.7		54.7		—		—		44.0		44.0		—		—
Mid cap	13.1		13.1		—		—		0.1		0.1		—		—
Small cap	102.1		102.1		—		—		—		—		—		—
International companies	83.3		83.3		—		—		241.9		241.9		—		—
Hedge funds	65.3		—		—		65.3		—		—		—		—
Limited partnerships	60.3		—		—		60.3		—		—		—		—
Insurance contracts	—		—		—		—		100.4		—		100.4		—
Emerging market bonds	4.8		4.8		—		—		—		—		—		—
Total assets	$	504.8	$	379.2	$	—	$	125.6	$	386.7	$	286.3	$	100.4	$	—
December 31, 2013 (In millions)
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	$	—

The summary of changes in the fair value of the pension plan Level 3 assets for the years ended December 31, 2014 and 2013 is as follows:



(In millions)	Level 3 Assets
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
Unrealized gains relating to instruments still held at the reporting date	1.6
Purchases, sales, and settlements, net	7.0
Balance at December 31, 2014	$	125.6

Contributions—We expect to contribute approximately $15.9 million to our international pension plans, representing primarily the U.K. and Norway qualified pension plans, and approximately $4.0 million to our U.S. Non-Qualified Defined Benefit Pension Plan in 2015. All of the contributions are expected to be in the form of cash. In 2014 we contributed $33.6 million to the pension plans. In 2013 we contributed $59.6 million to the pension plans, which included $18.0 million 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 2024. Actual benefit payments may differ from expected benefit payments.



	Pensions				Other Post-retirement Benefits
(In millions)	U.S.		International
2015	$	24.7	$	10.8	$	0.7
2016	$	26.0	$	11.3	$	0.8
2017	$	39.9	$	12.1	$	0.8
2018	$	26.6	$	13.6	$	0.8
2019	$	28.2	$	14.7	$	0.8
2020-2024	$	162.7	$	92.9	$	3.6

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 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. Nonelective contributions under the Amended Plans vest with three years of 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 both December 31, 2014 and 2013, our liability for the Non-Qualified Plan was $38.5 million 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, 2014 and 2013, we had investments for the Non-Qualified Plan totaling $30.7 million and $29.1 million, respectively, at fair market value and FMC Technologies stock held in trust of $8.0 million and $7.7 million, respectively, at its cost basis. Refer to Note 16 to these consolidated financial statements for fair value disclosure of the Non-Qualified Plan investments.

We recognized expense of $28.4 million, $23.5 million and $18.4 million, for matching contributions to these plans in 2014, 2013 and 2012, respectively. Additionally, we recognized expense of $18.9 million, $16.2 million and $11.8 million for nonelective contributions in 2014, 2013 and 2012, respectively.

NOTE 13. 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)	2014		2013		2012
Stock-based compensation expense	$	44.9	$	47.7	$	34.0
Income tax benefits related to stock-based compensation expense	$	14.5	$	16.2	$	11.5

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, 2014, 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 $43.6 million for restricted stock units. These costs are expected to be recognized over a weighted average period of 1.2 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, 2014, 3.3 million shares were reserved to satisfy existing awards and 20.3 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 settled when a director ceases services to the Board of Directors. However, a director may elect to settle restricted stock units either (i) in a calendar year no later than a year for which such restricted stock units are payable or (ii) in annual installments over a period of time with such installments commencing no later than a year for which such restricted stock units are payable. At December 31, 2014, outstanding awards to active and retired non-employee directors included 861 thousand stock units.

Restricted stock units—A summary of the nonvested restricted stock units to employees as of December 31, 2014, and changes during the year is presented below:



(Shares in thousands)	Shares		Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2013	2,464		$	48.04
Granted	953		$	51.20
Vested	(749	)	$	40.15
Cancelled/forfeited	(114	)	$	49.66
Nonvested at December 31, 2014	2,554		$	51.46

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, 2014. Based on results for the performance period, the payout will be 342 thousand shares at the vesting date in January 2017. Compensation cost was measured for 2014 based on the actual outcome of the performance conditions.

For current-year market-based awards, actual payouts may vary from zero to 172 thousand shares, contingent upon our performance relative to the same peer group of companies with respect to total shareholder return (“TSR”) for a three year period ending December 31, 2016. In 2012, the Committee changed 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 the TSR is limited to the target previously established by the Committee. In 2014, the Committee changed the performance evaluation period from one year to three years. 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,
	2014		2013		2012
Weighted average grant date fair value of restricted stock units granted	$	51.20	$	53.01	$	49.84
Vest date fair value of restricted stock units vested (in millions)	$	39.1	$	51.5	$	100.8

On January 2, 2015, restricted stock units vested and approximately 0.5 million shares were issued to employees.

NOTE 14. STOCKHOLDERS’ EQUITY

Capital stock—The following is a summary of our capital stock activity for the years ended December 31, 2014, 2013 and 2012:



(Number of shares in thousands)	Common Stock Issued	Common Stock Held in Employee Benefit Trust		Treasury Stock
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
Stock awards	—	—		(547	)
Treasury stock purchases	—	—		4,855
Net stock purchased for (sold from) employee benefit trust	—	(13	)	—
December 31, 2014	286,318	167		54,626

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 December 31, 2014, the Board of Directors had authorized 75 million shares for repurchase. We repurchased $247.6 million, $116.3 million and $91.1 million of common stock during 2014, 2013 and 2012, respectively, under the authorized repurchase program. As of December 31, 2014, approximately 8.0 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.

No cash dividends were declared on our common stock in 2014, 2013 or 2012.

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, 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		)
Other comprehensive income (loss) before reclassifications, net of tax	(107.6		)	(108.4		)	(154.4		)	(370.4		)
Reclassification adjustment for net (gains) losses included in net income, net of tax	—			(0.8		)	28.2			27.4
Other comprehensive income (loss), net of tax	(107.6		)	(109.2		)	(126.2		)	(343.0		)
December 31, 2014	$	(311.9	)	$	(77.3	)	$	(294.5	)	$	(683.7	)

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



	Year Ended
(In millions)	December 31, 2014			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:	$	(36.2	)	$	(11.7	)	Revenue
	34.2			14.8			Costs of sales
	(0.2		)	—			Selling, general and administrative expense
	(2.2		)	3.1			Income before income taxes
	3.0			2.1			Income tax (expense) benefit
	$	0.8		$	5.2		Net income
Defined pension and other post-retirement benefits
Settlements	$	(24.9	)	$	(5.1	)	^(a)
Amortization of actuarial loss	(18.6		)	(31.7		)	^(a)
Amortization of prior service credit	(0.3		)	0.5			^(a)
Amortization of transition asset	0.1			0.1			^(a)
	(43.7		)	(36.2		)	Income before income taxes
	15.5			15.2			Income tax (expense) benefit
	$	(28.2	)	$	(21.0	)	Net income

_______________________


^(a)	These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).

NOTE 15. 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, 2014, we held the following material positions:



	Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Australian dollar	31.9		26.1
British pound	73.3		114.1
Canadian dollar	(150.0	)	(129.1	)
Euro	151.4		183.2
Kuwaiti dinar	(5.9	)	(20.1	)
Malaysian ringgit	107.8		30.8
Norwegian krone	2,859.0		383.6
Singapore dollar	222.3		167.7
U.S. dollar	(929.1	)	(929.1	)

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, 2014, our portfolio of these instruments included the following material positions:



	Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Brazilian real	(105.6	)	(39.7	)
Norwegian krone	(77.6	)	(10.4	)
U.S. dollar	34.6		34.6

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. 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 16 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, 2014				December 31, 2013
(In millions)	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	$	172.1	$	207.1	$	149.3	$	152.5
Long-term – Derivative financial instruments	129.4		214.6		65.4		44.1
Total derivatives designated as hedging instruments	301.5		421.7		214.7		196.6
Derivatives not designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	25.5		23.1		16.6		18.8
Long-term – Derivative financial instruments	5.5		5.6		3.1		3.0
Total derivatives not designated as hedging instruments	31.0		28.7		19.7		21.8
Total derivatives	$	332.5	$	450.4	$	234.4	$	218.4

We recognized gains of $0.9 million, $0.1 million and $4.4 million on cash flow hedges for the years ended December 31, 2014, 2013 and 2012, 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 loss of $77.3 million and gain of $31.9 million at December 31, 2014 and 2013, respectively. We expect to transfer an approximate $17.3 million loss 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)	2014			2013		2012
Interest rate contracts	$	—		$	—	$	1.6
Foreign exchange contracts	(137.1		)	24.1		41.9
Total	$	(137.1	)	$	24.1	$	43.5



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)	2014			2013			2012
Foreign exchange contracts:
Revenue	$	(36.2	)	$	(11.7	)	$	6.6
Cost of sales	34.2			14.8			(1.9		)
Selling, general and administrative expense	(0.2		)	—			(0.2		)
Total	$	(2.2	)	$	3.1		$	4.5



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)	2014			2013			2012
Foreign exchange contracts:
Revenue	$	24.7		$	2.7		$	13.7
Cost of sales	(24.9		)	(11.0		)	(17.6		)
Total	$	(0.2	)	$	(8.3	)	$	(3.9	)

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)	2014			2013			2012
Foreign exchange contracts:
Revenue	$	(4.0	)	$	0.6		$	4.9
Cost of sales	0.7			(0.2		)	(0.2		)
Other income (expense), net	35.4			(15.0		)	6.4
Total	$	32.1		$	(14.6	)	$	11.1

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, 2014 and 2013, we had no collateralized derivative contracts. The following tables present both gross information and net information of recognized derivative instruments:



	December 31, 2014							December 31, 2013
(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	$	332.5	$	(321.5	)	$	11.0	$	234.4	$	(198.5	)	$	35.9



	December 31, 2014							December 31, 2013
(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	$	450.4	$	(321.5	)	$	128.9	$	218.4	$	(198.5	)	$	19.9

NOTE 16. FAIR VALUE MEASUREMENTS

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



	December 31, 2014								December 31, 2013
(In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Assets
Investments:
Equity securities	$	22.5	$	22.5	$	—	$	—	$	21.2	$	21.2	$	—	$	—
Fixed income	7.1		7.1		—		—		13.2		13.2		—		—
Money market fund	3.4		—		3.4		—		3.8		—		3.8		—
Stable value fund	0.7		—		0.7		—		1.0		—		1.0		—
Other	2.1		2.1		—		—		2.4		2.4		—		—
Derivative financial instruments:
Foreign exchange contracts	332.5		—		332.5		—		234.4		—		234.4		—
Total assets	$	368.3	$	31.7	$	336.6	$	—	$	276.0	$	36.8	$	239.2	$	—
Liabilities
Derivative financial instruments:
Foreign exchange contracts	450.4		—		450.4		—		218.4		—		218.4		—
Contingent earn-out consideration	—		—		—		—		70.1		—		—		70.1
Total liabilities	$	450.4	$	—	$	450.4	$	—	$	288.5	$	—	$	218.4	$	70.1

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. See Note 12 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 15 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 were 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 was based upon significant inputs not observable in the market. Changes in the value of the contingent earn-out consideration were recorded as cost of service 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)	2014			2013
Balance at beginning of year	$	70.1		$	105.3
Remeasurement adjustment	3.6			28.7
Payment	(74.6		)	(57.3		)
Foreign currency translation adjustment	0.9			(6.6		)
Balance at end of year	$	—		$	70.1

Fair value of debt—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 $779.5 million and $767.6 million as of December 31, 2014 and 2013, respectively, as compared to the $800.0 million face value of the debt, net of issue discounts, recorded in the consolidated balance sheets.

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 17. WARRANTY OBLIGATIONS

Warranty cost and accrual information is as follows:



	December 31,
(In millions)	2014			2013
Balance at beginning of year	$	18.0		$	15.4
Expenses for new warranties	30.5			27.0
Adjustments to existing accruals	0.7			1.5
Claims paid	(26.2		)	(25.9		)
Balance at end of year	$	23.0		$	18.0

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 $136.8 million, $149.7 million and $133.9 million in 2014, 2013 and 2012, respectively.

In March 2014 we entered into construction and operating lease agreements to finance the construction of manufacturing and office facilities located in Houston, TX. Upon expiration of the lease term in September 2021, we have the option to renew the lease, purchase the facilities or re-market the facilities on behalf of the lessor, including certain guarantees of residual value under the re-marketing option.

At December 31, 2014, future minimum rental payments under noncancellable operating leases were:



	(In millions)
2015	$	108.8
2016	87.7
2017	67.9
2018	55.3
2019	45.6
Thereafter	282.4
Total	647.7
Less income from subleases	1.2
Net minimum operating lease payments	$	646.5

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, 2014, represented $755.4 million for guarantees of our future performance and $78.4 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.

In August 2014 FMC Technologies entered into an arrangement to guarantee the debt obligations under a revolving credit facility of FMC Technologies Offshore, LLC (“FTO Services”), our joint venture with Edison Chouest Offshore LLC. Under the terms of the guarantee, FMC Technologies and Edison Chouest Offshore LLC jointly and severally guaranteed amounts under the revolving credit facility with a maximum potential amount of future payments of $40.0 million that would become payable if FTO Services defaults in payment under the terms of the revolving credit facility. The approximate term of the guarantee is two years. The liability recognized at inception for the fair value of our obligation as a guarantor was not material, and we expect our future performance under the guarantee to be remote.

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.

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, 2014 and 2013, 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 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)	2014			2013			2012
Segment revenue
Subsea Technologies ⁽¹⁾	$	5,266.4		$	4,726.9		$	4,006.8
Surface Technologies	2,130.7			1,806.8			1,598.1
Energy Infrastructure	557.4			617.2			574.1
Other revenue ⁽²⁾and intercompany eliminations	(11.9		)	(24.7		)	(27.6		)
Total revenue	$	7,942.6		$	7,126.2		$	6,151.4
Income before income taxes:
Segment operating profit:
Subsea Technologies	$	748.2		$	548.2		$	432.2
Surface Technologies	393.0			257.2			284.3
Energy Infrastructure	52.5			74.3			68.2
Intercompany eliminations	(0.3		)	(0.1		)	—
Total segment operating profit	1,193.4			879.6			784.7
Corporate items:
Corporate expense ⁽³⁾	(66.3		)	(46.3		)	(41.8		)
Other revenue ⁽²⁾ and other expense, net ⁽⁴⁾	(33.7		)	(85.6		)	(119.9		)
Net interest expense	(32.5		)	(33.7		)	(26.6		)
Total corporate items	(132.5		)	(165.6		)	(188.3		)
Income before income taxes attributable to FMC Technologies, Inc. ⁽⁵⁾	$	1,060.9		$	714.0		$	596.4

______________________________


⁽¹⁾	We had one customer in our Subsea Technologies segment that comprised approximately $875.9 million and $625.9 million of our consolidated revenue for the year ended December 31, 2013 and 2012, respectively.


⁽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.


⁽⁵⁾	Excludes amounts attributable to noncontrolling interests.

Segment operating capital employed and segment assets



	December 31,
(In millions)	2014			2013
Segment operating capital employed ⁽¹⁾:
Subsea Technologies	$	2,175.2		$	2,126.3
Surface Technologies	1,183.6			1,139.1
Energy Infrastructure	313.9			345.4
Total segment operating capital employed	3,672.7			3,610.8
Segment liabilities included in total segment operating capital employed ⁽²⁾	2,402.3			2,272.8
Corporate ⁽³⁾	1,100.6			722.0
Total assets	$	7,175.6		$	6,605.6
Segment assets:
Subsea Technologies	$	4,066.1		$	3,923.6
Surface Technologies	1,587.8			1,484.0
Energy Infrastructure	442.3			496.4
Intercompany eliminations	(21.2		)	(20.4		)
Total segment assets	6,075.0			5,883.6
Corporate ⁽³⁾	1,100.6			722.0
Total assets	$	7,175.6		$	6,605.6

______________________________


⁽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)	2014		2013		2012
Revenue:
United States	$	2,245.3	$	1,940.4	$	1,541.6
Norway	1,023.3		1,217.7		1,231.1
Brazil	831.6		689.0		561.2
Nigeria	627.0		335.0		192.7
Angola	406.7		516.0		598.0
All other countries	2,808.7		2,428.1		2,026.8
Total revenue	$	7,942.6	$	7,126.2	$	6,151.4



	December 31,
(In millions)	2014		2013
Long-lived assets:
United States	$	490.5	$	443.4
Norway	250.8		223.3
Brazil	169.1		166.3
United Kingdom	147.0		137.2
Malaysia	112.6		100.8
All other countries	288.4		278.1
Total long-lived assets	$	1,458.4	$	1,349.1

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)	2014		2013		2012		2014		2013		2012		2014			2013			2012
Subsea Technologies	$	268.7	$	235.0	$	257.9	$	138.0	$	119.5	$	89.3	$	92.2		$	87.1		$	93.9
Surface Technologies	124.6		70.1		110.1		72.0		68.0		38.8		21.6			15.6			12.2
Energy Infrastructure	10.5		8.3		10.3		16.6		16.5		14.0		11.3			12.2			10.7
Corporate	0.6		0.7		27.3		5.9		5.8		4.1		—			—			—
Intercompany eliminations	—		—		—		—		—		—		(1.4		)	(2.5		)	—
Total	$	404.4	$	314.1	$	405.6	$	232.5	$	209.8	$	146.2	$	123.7		$	112.4		$	116.8

NOTE 20. QUARTERLY INFORMATION (UNAUDITED)



	2014								2013
(In millions, except per share data)	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Revenue	$	2,156.2	$	1,976.7	$	1,985.3	$	1,824.4	$	2,047.8	$	1,724.5	$	1,707.9	$	1,646.0
Cost of sales	1,608.9		1,479.6		1,507.8		1,403.5		1,560.3		1,353.8		1,350.1		1,307.2
Net income	170.6		170.5		227.7		136.5		179.1		117.4		106.5		103.6
Net income attributable to FMC Technologies, Inc.	$	168.6	$	169.8	$	226.3	$	135.2	$	177.8	$	116.0	$	105.2	$	102.4
Basic earnings per share ⁽¹⁾	$	0.72	$	0.72	$	0.96	$	0.57	$	0.75	$	0.49	$	0.44	$	0.43
Diluted earnings per share ⁽¹⁾	$	0.72	$	0.72	$	0.95	$	0.57	$	0.74	$	0.49	$	0.44	$	0.43

______________________________


⁽¹⁾	Basic and diluted EPS are independently computed 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)	2014		2013		2012
Supplemental disclosures of cash flow information:
Cash paid for interest (net of interest capitalized)	$	31.6	$	27.1	$	18.5
Cash paid for income taxes (net of refunds received)	$	370.0	$	137.3	$	225.4



	December 31,
(In millions)	2014		2013
Other reportable information:
Unbilled receivables included in trade receivables	$	804.3	$	777.0
Trading securities included in investments	$	35.8	$	41.6
Net capitalized software costs included in other assets	$	57.3	$	56.9

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, 2014, 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, our principal executive officer and principal financial officer have concluded as of December 31, 2014, 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, 2014, 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 “Election of Directors (Item 1 on the Proxy Card)” of our Proxy Statement for the 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 (Item 2 on the Proxy Card)” of our Proxy Statement for the 2015 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, 2014, 2013 and 2012

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013, and 2012

Consolidated Balance Sheets as of December 31, 2014 and 2013

Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012

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 Adjustments ^(b)		Balance at End of Period
Year ended December 31, 2012:
Allowance for doubtful accounts	$	7,799	$	1,753	$	71		$	3,477	$	6,146
Inventory valuation reserve	$	63,773	$	30,660	$	1,352		$	25,929	$	69,856
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
Inventory valuation reserve	$	69,856	$	37,629	$	(314	)	$	21,135	$	86,036
Valuation allowance for deferred tax assets	$	4,265	$	1,779	$	(15	)	$	1,302	$	4,727
Year ended December 31, 2014:
Allowance for doubtful accounts	$	7,441	$	3,574	$	(555	)	$	1,039	$	9,421
Inventory valuation reserve	$	86,036	$	47,578	$	(8,686	)	$	28,118	$	96,810
Valuation allowance for deferred tax assets	$	4,727	$	39,932	$	—		$	5,762	$	38,897

______________________________


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


^(b)	“Deductions and adjustments” 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 Executive Vice President and Chief Financial Officer

Date: February 20, 2015

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 20, 2015		/S/ JOHN T. GREMP
		John T. Gremp Chairman, President and Chief Executive Officer (Principal Executive Officer)

February 20, 2015		/S/ MARYANN T. SEAMAN
		Maryann T. Seaman Executive Vice President and Chief Financial Officer (Principal Financial Officer)

February 20, 2015		/S/ JAY A. NUTT
		Jay A. Nutt Vice President and Controller (Principal Accounting Officer)

February 20, 2015		/S/ ELEAZAR DE CARVALHO FILHO
		Eleazar De Carvalho Filho, Director

February 20, 2015		/S/ CLARENCE P. CAZALOT, JR.
		Clarence P. Cazalot, Jr., Director

February 20, 2015		/S/ C. MAURY DEVINE
		C. Maury Devine, Director

February 20, 2015		/S/ CLAIRE S. FARLEY
		Claire S. Farley, Director

February 20, 2015		/S/ THOMAS M. HAMILTON
		Thomas M. Hamilton, Director

February 20, 2015		/S/ PETER MELLBYE
		Peter Mellbye, Director

February 20, 2015		/S/ EDWARD J. MOONEY
		Edward J. Mooney, Director

February 20, 2015		/S/ JOSEPH H. NETHERLAND
		Joseph H. Netherland, Director

February 20, 2015		/S/ PETER OOSTERVEER
		Peter Oosterveer, Director

February 20, 2015		/S/ JAMES M. RINGLER
		James M. Ringler, Director

INDEX OF EXHIBITS



Exhibit No.		Exhibit Description
2.1		Arrangement Agreement between FMC Technologies, Inc. and Pure Energy Services Ltd. dated August 17, 2012 (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 between FMC Technologies, Inc. and U.S. Bank National Association, as trustee, dated September 21, 2012 (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 between FMC Technologies, Inc. and U.S. Bank National Association, as trustee, dated September 21, 2012 (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 between FMC Technologies, Inc. and U.S. Bank National Association, as trustee, dated September 21, 2012 (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*		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).
10.1.a*		First Amendment of the Amended and Restated FMC Technologies, Inc. Incentive Compensation and Stock Plan, dated October 3, 2013 (incorporated by reference from Exhibit 10.4.a to the Annual Report on Form 10-K filed on February 21, 2014) (File No. 001-16489).
10.2*		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 10.1 to the Current Report on Form 8-K filed on March 14, 2014) (File No. 001-16489).
10.3*		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).
10.4*		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).
10.5*		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).
10.6*		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).
10.7*		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).
10.8*		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).
10.9*		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 10.4k to the Quarterly Report on Form 10-Q filed on May 9, 2006) (File No. 001-16489).
10.10*		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).
10.11*		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).
10.12*		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).
10.13*		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).
10.13.a*		First Amendment of Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part I Salaried and Nonunion Hourly Employees’ Retirement Plan, dated April 30, 2014.
10.13.b*		Second Amendment of Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part I Salaried and Nonunion Hourly Employees’ Retirement Plan, dated June 30, 2014 (incorporated by reference from Exhibit 10.2 to the Quarterly Report on Form 10-Q filed on June 25, 2014) (File No. 001-16489).
10.13.c*		Third Amendment of Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part I Salaried and Nonunion Hourly Employees’ Retirement Plan, dated November 14, 2014.
10.14*		Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part II Union Hourly Employees’ Retirement Plan, dated January 28, 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).
10.14.a*		First Amendment of Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part II Union Hourly Employees’ Retirement Plan, dated November 14, 2014.
10.15*		FMC Technologies, Inc. Salaried Employees’ Equivalent Retirement Plan, dated July 31, 2008 (incorporated by reference from Exhibit 10.7 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.15.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).
10.15.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).
10.16*		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).
10.17*		Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated January 28, 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).
10.17.a*		First Amendment to the Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated October 3, 2013 (incorporated by reference from Exhibit 10.20.a to the Annual Report on Form 10-K filed on February 21, 2014) (File No. 001-16489).
10.17.b*		Second Amendment to the Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated February 7, 2014 (incorporated by reference from Exhibit 10.20.b to the Annual Report on Form 10-K filed on February 21, 2014) (File No. 001-16489).
10.18*		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).
10.19*		Amended and Restated FMC Technologies, Inc. Non-Qualified Savings and Investment Plan, dated July 31, 2008 (incorporated by reference from Exhibit 10.9 to the Annual Report on Form 10-K filed on March 1, 2010) (File No. 001-16489).
10.19.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).
10.20*		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).
10.21*		FMC Technologies, Inc. Frozen Retirement Plan, dated June 30, 2014 (incorporated by reference from Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on July 25, 2014) (File No. 001-16489).
10.21.a*		First Amendment of FMC Technologies, Inc. Frozen Retirement Plan, dated September 29, 2014 (incorporated by reference from Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on October 24, 2014) (File No. 001-16489).
10.22		Commercial Paper Dealer Agreement 4(2) Program between Banc of America Securities LLC and FMC Technologies Inc., dated 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).
10.23		Commercial Paper Dealer Agreement 4(2) Program between Wells Fargo Brokerage Services, LLC and FMC Technologies, Inc., dated 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).
10.24		Commercial Paper Dealer Agreement 4(2) Program between J.P. Morgan Securities Inc. and FMC Technologies, Inc., dated 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).
10.25		Commercial Paper Dealer Agreement 4(2) Program between Citigroup Global Markets Inc. and FMC Technologies, Inc., dated 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).
10.26		Commercial Paper Dealer Agreement 4(2) Program between RBS Securities Inc. and FMC Technologies, Inc., dated 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).
10.27		Issuing and Paying Agency Agreement by and between Wells Fargo Bank, National Association and FMC Technologies, Inc., dated 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).
10.28		$1,500,000,000 Credit Agreement 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, dated March 26, 2012 (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on March 27, 2012) (File No. 001-16489).
10.29		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).
10.29.a		Securities Purchase Agreement by and among FMC Technologies, Inc., Schilling Robotics, Inc. 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).
10.30		Purchase Agreement 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, dated September 9, 2009 (incorporated by reference from Exhibit 10.10 to the Quarterly Report on Form 10-Q filed on November 3, 2009) (File No. 001-16489).
10.31		Form of Voting and Support Agreement between FMC Technologies, Inc. and the directors and officers of Pure Energy Services Ltd., dated August 17, 2012 (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