Edgar Filing: FMC TECHNOLOGIES INC

10-K

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, 2015



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

For the transition period from to

Commission file number 001-16489

FMC TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)



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

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

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

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



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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES ý NO ¨

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

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

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

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

The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant, determined by multiplying the outstanding shares on June 30, 2015, by the closing price on such day of $41.49 as reported on the New York Stock Exchange, was $5,416,567,545.*

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of February 22, 2016 was 226,906,343.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement relating to its 2016 annual meeting of stockholder are incorporated by reference into Part III of this Annual Report of Form 10-K where indicated. The 2016 Proxy Statement will be filed with the U.S. Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.



*	Excludes 99,371,968 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, 2015. 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	13
Item 1A. Risk Factors	14
Item 1B. Unresolved Staff Comments	19
Item 2. Properties	20
Item 3. Legal Proceedings	20
Item 4. Mine Safety Disclosures	20

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6. Selected Financial Data	23
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	44
Item 8. Financial Statements and Supplementary Data	46
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	94
Item 9A. Controls and Procedures	94
Item 9B. Other Information	94

PART III

Item 10. Directors, Executive Officers and Corporate Governance	95
Item 11. Executive Compensation	95
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	95
Item 13. Certain Relationships and Related Transactions, and Director Independence	96
Item 14. Principal Accounting Fees and Services	96

PART IV

Item 15. Exhibits, Financial Statement Schedules	97
Signatures	99

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 20 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. The acquisition of the remaining 55% has enabled us to grow in the subsea market environment, where demand for ROVs and the need for maintenance activities of subsea equipment exists. Additionally, we acquired Pure Energy, a provider of flowback services and wireline services. The acquisition of Pure Energy complements the existing products and services of our Surface Technologies segment and creates 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 enhances our automation and controls technologies and benefits technologies to support our long-term strategy to expand our subsea production and processing systems.

Also in 2012, we formed FMC Technologies Offshore, LLC (“FTO Services”), a 50/50 joint venture with Edison Chouest Offshore LLC. Utilizing the subsea technologies, tooling and expertise of FMC Technologies, and the vessel, port logistics and ROV operations of Edison Chouest Offshore, the joint venture was formed to provide integrated vessel-based subsea services for offshore oil and gas fields around the world. The objective of the joint venture is to provide cost-effective solutions to enhance our customers’ ability to initiate, maintain and increase production from subsea field developments. Additional information regarding this joint venture is incorporated herein by reference from Note 7 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.

During 2015, we signed an agreement with Technip S.A. (“Technip”) to form Forsys Subsea Limited (“Forsys Subsea”), a 50/50 joint venture. Forsys Subsea brings the proprietary technologies of FMC Technologies and Technip together to offer front-end engineering and design services aimed to identify opportunities through new technologies, services, and standardization of equipment to significantly reduce the cost of subsea field development and provide the technology to maximize well performance over the life of the field. In conjunction with the formation of Forsys Subsea, the agreement also formed an alliance with Technip that enables us to create the framework to deliver and install seabed and/or topside subsea infrastructure resulting from designs produced by Forsys Subsea. Additional financial information is incorporated herein by reference from Note 7 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Also in 2015, we largely completed integration efforts in our Surface Technologies segment. These integration efforts, primarily in North America, bring together the services acquired from Pure Energy and our surface wellhead business to create an integrated shale offering. The integration efforts have the strategic aim (i) to improve our customers’ returns by offering integrated solutions involving multiple surface products and services, (ii) to enable execution excellence through specialization and focus, (iii) to improve scalability and (iv) to increase market share in the North American shale market. Our integration efforts of our Surface Technologies products and services resulted in Surface Technologies now being organized and operated under the three businesses of surface integrated services, surface wellhead international, and fluid control.

Website Access to Reports and Proxy Statement. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statements and Forms 3, 4 and 5 filed on behalf of directors and executive officers, and amendments to each of 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 such material is electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”). Alternatively, our reports may be accessed through the website maintained by the SEC at www.sec.gov. Unless expressly noted, the information on our website or any other website is not incorporated by reference in this Annual Report on Form 10-K and should not be considered part of this Annual Report on Form 10-K or any other filing we make with the SEC.

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 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 management 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 an array of subsea services aimed to improve uptime, lower lifecycle costs and increase recovery over the life of the field. These services include (i) installation services to plan and direct the technical onshore and offshore activities, resources and operations required in an installation, (ii) asset management services such as tool management, equipment refurbishment, condition and performance monitoring, processing equipment-related maintenance and rental tools, (iii) product optimization using a suite of services including flow assurance services, real-time surveillance, predictive analytics and flow modeling software, (iv) inspection, maintenance and repair of control and instrumentation modules, chokes, flow modules, and processing equipment, and (v) well access and intervention services including exploration wellheads, production and completion related services, rig-based intervention, riserless light well intervention through our FTO Services joint venture, tree commissioning, through tubing rotary drilling and plug and abandonment. Additionally, Forsys Subsea, our joint venture with Technip, offers front-end engineering and design to identify opportunities through new technologies, services, and standardization of equipment to significantly reduce the cost of subsea field development and provide the technology to maximize well performance over the life of the field.

Subsea systems represented approximately 69%, 63% and 63% of our consolidated revenue in 2015, 2014 and 2013, 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, and technical assistance.

Multi Phase Meters. We design and manufacture multiphase and wetgas meters to measure production rates of oil, water and gas for both topside and subsea applications. These meters have diverse applications that include production testing of well fluid rates, reservoir monitoring, measurement of fluid rates for production and revenue sharing between partners, and artificial lift optimization. The Multi Phase Meters product line augments our portfolio of technologies for increasing oil and gas recovery, early water detection, accurate fiscal allocation 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 payments and progress billings 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 actively pursue 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 meet 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 would 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. Given the current recessionary economy in Brazil and the low crude oil price environment, our operational performance may be negatively affected by any significant changes in Petrobras’ operations, such as further decreases in their capital spending plans. As part of enhancing our customer relationship, we are working with Petrobras to delay certain deliveries of product which may affect the timing of our results of operations or cash flows.

The loss of one or more of our significant customers could have a material adverse effect on our Subsea Technologies segment. No single Subsea Technologies customer accounted for 10% or more of our 2015 consolidated revenue.

Competition

Subsea Technologies competes with companies that supply subsea systems and with other smaller companies that are focused on a specific application, technology or geographical niche in which we operate. Companies including OneSubsea (a Cameron and Schlumberger company), GE Oil & Gas (a division of General Electric Company), Aker Solutions ASA and Dril-Quip, Inc. compete with us in the marketplace across our various Subsea Technologies product and services.

Competitive factors in our industry include price, the quality of both product technology and service, and on-time delivery. Our competitive strengths include our intellectual capital, the reliability of our products, the 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 and our worldwide presence and reputation in each of the major producing basins around the world. Our strong customer relationships, experience and technology help us maintain a leadership position in the subsea systems market.

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 each 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 wellhead systems and high pressure valves and pumps 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 Integrated Services and Surface Wellhead International. 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.

As part of our surface integrated services business, we provide an integrated shale offering which includes manifolds and trees and flowback equipment for timely and cost-effective well completion. Acquired in October 2012 and formerly known as Pure Energy Services Ltd., we also provide flowback services for the recovery of solids, fluids, and hydrocarbons from oil and natural gas wells after the stimulation of the well, cased hole electric wireline and slickline services, specialty logging services, and well optimization services for exploration companies in the oil and gas industry.

Fluid Control. We design and manufacture flowline products, under the Weco^®/Chiksan^® trademarks, articulating frac arm manifold trailers, well service pumps, compact valves and reciprocating pumps used in well completion and stimulation activities by major oilfield service companies, such as Schlumberger Limited, Baker Hughes Incorporated, Halliburton Company and Weatherford International 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.

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 2015 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 (a division of The Weir Group PLC), GE Oil & Gas (a division of General Electric Company) 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 during the spring months, which reduces activity levels. There is greater demand for oilfield services, specifically completion services, provided by our Canadian surface integrated 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 service 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 gas and liquid 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. As part of our liquid measurement system offering, 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.

We also provide automation and control technology for the oil and gas, chemical and other industries. Acquired in April 2012 and formerly known as Control Systems International, Inc., our automation and control technology supplies innovative control and automation system solutions. One of the primary products, 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.

Loading Systems. We provide land- and marine-based 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 can be applied to both greenfield development as well as retrofit solutions for fields currently in production. Also, these systems provide solutions for both subsea and topside applications. For subsea applications, these systems can be designed with primary separation at the seabed which enables more effective production, increased field recovery and the reduced need for topside processing capacity for our customers.

Dependence on Key Customers

No single Energy Infrastructure customer accounted for 10% or more of our 2015 consolidated revenue.

OTHER BUSINESS INFORMATION RELEVANT TO OUR BUSINESS SEGMENTS

Product Development

We invest in product development to advance technologies necessary to support the current and future technical challenges of our customers. We seek to develop products and services aimed to assist our customers to lower capital and operating expenditures, increase oil recovery and deliver improved performance of their assets. 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, our investments in product development are focused on (i) progressing capabilities to bring products to market faster and more efficiently, (ii) developing the next generation of cost-effective production and processing equipment, (iii) advancing core enabling technologies and materials and (iv) expanding product families to address broader market applications.

To accelerate the commercialization of technologies in all of our businesses, we made several investments to enhance our research and development capabilities. First, we expanded our network of rapid prototyping centers, increasing the resources available for our engineers to design and build new products. Second, we upgraded and expanded our capabilities to conduct qualification testing. These investments included the addition of test cells, flow loops, bending fixtures and test pits along with advanced instrumentation to better facilitate monitoring of test programs. Our investments added capacity and provided new functionality to accommodate a broader range of test parameters including high pressure, high temperature (“HPHT”) conditions.

Subsea Technologies. We continue to expand our subsea technologies portfolio of solutions in order to deliver a complete production system for 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. In 2015, we added another major operator to this joint agreement. We believe standardization of our products is an important element in improving execution, optimizing resources, lowering lifecycle costs and providing superior long-term value. This joint development agreement is expected to result in standardized design, materials, processes and interfaces to deliver improved reliability and operability over the life of the field. During 2015, we completed major qualification testing meeting the latest industry guidelines.

The downturn in the energy market has shifted the needs of our customers. As a result, we have also invested in subsea product development focused on developing lower cost solutions. Technology development progressed on the next generation of subsea equipment utilizing designs that will be significantly smaller and lighter than current designs. In addition to the investments to develop lower cost production solutions, we continued efforts on our portfolio of product technology and services aimed to help operators maximize recovery from existing subsea fields. Along with our development partner Sulzer Pumps Ltd., we expanded the product family of pumps and motors to include more sizes and pressure ratings. Additionally, development of our well access management system was completed in 2015, and the system was successfully employed in the North Sea. This combined subsea product and service solution provided real-time data to the operator to enable the assessment of actual loading on a subsea completion riser during operations, leading to reduced operational and maintenance costs and increased oil recovery.

Surface Technologies. Development work focused on enhancing several core enabling technologies including seals, valves and instrumentation. During 2015, we completed development on a steam valve for high temperature service. The valve was successfully qualified and installed on an onshore field in North America. Additionally, we completed development on the next generation of sealing technology featuring a dual metal packoff. Developed in collaboration with one of our key customers, the new design of the sealing technology eliminates elastomers and improves seal performance. Other investments in our surface technologies portfolio included the development and testing of sensing and instrumentation technologies and of technologies for the treatment of well fluids.

Energy Infrastructure. Our measurement solutions business completed development of AccuLoad IV, the newest generation electronic preset system. This new generation includes important upgrades and enhancements such as improved diagnostics that will ensure AccuLoad^® remains a widely used preset in oil custody transfer. Our loading systems business completed extended fatigue and operating simulation testing on ATOL, our tandem offshore loading solution.

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 products to meet our customer needs. Financial information about R&D activities is incorporated herein by reference from Note 20 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 1,530 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 155 registrations and pending applications in the United States and abroad.

We protect and promote our intellectual property portfolio and take 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, 2015, we had approximately 17,400 full-time employees, consisting of approximately 5,700 in the United States and 11,700 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, 2015.

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 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 20 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.

EXECUTIVE OFFICERS OF THE REGISTRANT

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 24, 2016, 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	64	Chairman and Chief Executive Officer (2015) Chairman, President and Chief Executive Officer (2013) Chairman and Chief Executive Officer (2012) Chairman, President and Chief Executive Officer (2011)
Maryann T. Mannen	53	Executive Vice President and Chief Financial Officer (2014) Senior Vice President and Chief Financial Officer (2011)
Richard G. Alabaster	55	Vice President—Surface Technologies (2015) General Manager—Surface Integrated Services (2013) General Manager—Fluid Control (2010)
Bradley D. Beitler	62	Vice President—Technology (2009)
Sanjay Bhatia	46	Vice President—Corporate Development (2012) Director of Business Development (2007)
Barry Glickman	47	Vice President—Subsea Services (2015) General Manager—Subsea Systems Western Region (2012) Vice President—Energy Infrastructure (2011) Integration Leader for GE Oil & Gas/Wood Group (2011)
Tore Halvorsen	61	Senior Vice President—Subsea Technologies (2011)
Jay A. Nutt	52	Vice President—Controller and Treasurer (2015) Vice President and Controller (2009)
Douglas J. Pferdehirt	52	President and Chief Operating Officer (2015) Executive Vice President and Chief Operating Officer (2012) Executive Vice President—Corporate Development & Communication for Schlumberger Limited (2011)
Dianne B. Ralston	49	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	62	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 products 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 products 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. The current downturn in the oil and gas industry has resulted in a reduction in demand for oilfield services and could further 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 products that could adversely affect our financial condition.

We are subject to potential liabilities arising from equipment malfunctions and failures, particularly due to high temperature and pressure environments, 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 results of operations.

Environmental laws and regulations in the United States and 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 products 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 require the installation of new GHG emission control technologies. The EPA has also promulgated rules requiring 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 August 2015, the EPA announced proposed rules that would establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, as part of an overall effort to reduce methane emissions by up to 45 percent by 2025. 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 products and services. In addition, any new laws or regulations establishing cap-and-trade or 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 products 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 on underground water supplies. Although we do not perform hydraulic fracturing, we do 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 EPA has issued final regulations under the U.S. Clean Air Act governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing and proposed in April 2015 the prohibition of the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Also, the U.S. Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule, and a final decision has not yet been issued. These 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 products 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 and liabilities 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 sizable operations, do not actively trade in the global foreign exchange markets and may subject us to increased foreign currency exposures. Refer to “Quantitative and Qualitative Disclosures about Market Risk” in Part II, Item 7A of this Annual Report on Form 10-K for additional discussion of foreign currency rate risk. 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 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 clauses related to liquidated damages or financial incentives regarding on-time delivery, and a failure by us to deliver in accordance with customer expectations could subject us to liquidated damages or loss of financial incentives, 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 and execution, 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.

In accordance with Section 1502 of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC’s rules 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 became effective in 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. 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. Additionally, we rely on third parties to support the operation of our IT hardware and software infrastructure, and in certain instances, utilize web-based applications. Although no such material incidents have occurred to date, the failure of our IT systems or those of our vendors 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 and proprietary information, reputational harm, 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. 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, 2015, recorded goodwill of $63.7 million was associated with our U.S. surface integrated services reporting unit. The decline in crude oil prices that began in 2014 and continued throughout 2015 has introduced uncertainty associated with certain key assumptions used in estimating fair value of the reporting unit. Depressed crude oil and natural gas prices for a prolonged period of time may adversely affect the economics of our customers’ projects, particularly shale-related projects in North America, which may lead to the reduction in demand for our products and services, negatively impacting the financial results of the reporting unit. Our estimate of fair value for the U.S. surface integrated services reporting unit relies on third party forecasts of the number of hydraulic fracturing stages expected to be completed as well as the expected recovery of the overall North American oil and gas market. Management is monitoring the overall market, specifically crude oil and natural gas prices, and its effect on the estimates and assumptions used in our goodwill impairment test for U.S. surface integrated services, which may require re-evaluation and could result in an impairment of goodwill for this reporting unit.

At December 31, 2015, recorded goodwill of $54.7 million was associated with our separation systems reporting unit. The decline in crude oil prices and its related effect on customer capital spending has led to negative margins for separation systems in 2015. Our estimate of fair value for the separation systems reporting unit relies on assumptions of lower oil and gas activity over the next few years with expected market recovery in 2019 for this business. To mitigate the impact of lower commodity prices, management is expanding the reporting unit’s existing product offering in both greenfield and brownfield applications by introducing differentiating technology and expanding the system and solutions business as a growth platform. Management is monitoring the overall market, specifically crude oil prices and changes in customer capital spending, and its effect on the estimates and assumptions used in our goodwill impairment test for separation systems, which may require re-evaluation and could result in an impairment of goodwill for this reporting unit.

Refer to “Critical Accounting Estimates” in Part II, Item 7 of this Annual Report on Form 10-K for additional discussion regarding estimates and assumptions surrounding goodwill.

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

The terms of our financing are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. Factors that may impact our credit ratings include debt levels, capital structure, planned asset purchases or sales, near- and long-term production growth opportunities, market position, liquidity, asset quality, cost structure, product mix, customer and geographic diversification and commodity price levels. A downgrade in our credit ratings, particularly to non-investment grade levels, could limit our ability to access the debt capital markets, refinance our existing debt or cause us to refinance or issue debt with less favorable terms and conditions. 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.

Our industry is undergoing consolidation that may impact our results of operations.

Our industry, including our customers and competitors, is undergoing consolidation which may affect demand for our products and services as a result of price concessions or decreased customer capital spending. This consolidation activity could have a significant negative impact on our results of operations, financial condition or cash flows. We are unable to predict what effect consolidations in the industry may have on prices, capital spending by our customers, our selling strategies, our competitive position, our ability to retain customers or our ability to negotiate favorable agreements with our customers.

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

We depend on key personnel. The loss of any key personnel could adversely impact our business if we are unable to implement key strategies or transactions in their absence. The loss of qualified employees or an inability to retain and motivate additional highly-skilled employees required for the operation and expansion of our business could hinder our ability to successfully conduct research activities and develop marketable products and services.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We lease our corporate headquarters in Houston, Texas, and own or lease numerous properties throughout the world. We operate 29 major production facilities and service bases in 18 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 principal properties by reporting segment at December 31, 2015:



Subsea Technologies	Surface Technologies	Energy Infrastructure
United States:
Davis, California	Brighton, Colorado	Corpus Christi, Texas
* Houston, Texas	Oklahoma City, Oklahoma	Erie, Pennsylvania
	San Antonio, Texas
	Stephenville, Texas

International:
Bergen, Norway	Abu Dhabi, U.A.E.	Arnhem, The Netherlands
* Dunfermline, Scotland	Collecchio, Italy
Kongsberg, Norway	Dammam, Saudi Arabia
Labuan, Malaysia	Edmonton, Canada
Luanda, Angola	Jakarta, Indonesia
Macaé, Brazil	Neuquén, Argentina
* Nusajaya, Malaysia	+ Sens, France
Perth, Australia
Port Harcourt, Nigeria
* Rio de Janeiro, Brazil
* Singapore
* Stavanger, Norway
Takoradi, Ghana

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

+This facility is a principal 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 “FTI” symbol.



	2015								2014
	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Common stock closing price:
High	$	35.48	$	39.79	$	44.10	$	46.52	$	57.00	$	63.52	$	61.89	$	53.27
Low	$	28.35	$	28.73	$	36.96	$	36.14	$	42.75	$	54.21	$	52.16	$	48.37



Closing stock price at December 31, 2015	$	29.01
Closing stock price at February 22, 2016	$	25.32
Number of common stockholders of record at February 22, 2016	2,876

We have not declared or paid cash dividends in 2015 or 2014, and we do not currently have a plan to pay cash dividends in the future.

As of December 31, 2015, 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	—	$	—	23,042,721	(1)
Equity compensation plans not approved by security holders	—	—		—
Total	—	$	—	23,042,721	(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 4,068,156 shares available for issuance for nonvested stock awards that vest after December 31, 2015.

We had no unregistered sales of equity securities during the year ended December 31, 2015.

The following table summarizes repurchases of our common stock during the three months ended December 31, 2015.

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, 2015 – October 31, 2015	286,710	$	33.15	286,000	18,812,222
November 1, 2015 – November 30, 2015	260,470	$	33.97	260,000	18,552,222
December 1, 2015 – December 31, 2015	773,874	$	29.60	772,444	17,779,778
Total	1,321,054			1,318,444	17,779,778

______________________________

^(a)

Represents 1,318,444 shares of common stock repurchased and held in treasury and 2,610 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 2,300 shares of registered common stock held in this trust, as directed by the beneficiaries, during the three months ended December 31, 2015.

^(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. The Board of Directors authorized additional extensions of this program, adding 15 million shares in both December 2011 and February 2015 for a total of 90 million shares of common stock authorized for repurchase.

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, 2015. 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	2015		2014		2013		2012		2011
Statement of income data:
Total revenue	$	6,362.7	$	7,942.6	$	7,126.2	$	6,151.4	$	5,099.0
Total costs and expenses	$	5,770.6	$	6,874.1	$	6,378.6	$	5,546.6	$	4,536.6
Net income	$	394.8	$	705.3	$	506.6	$	434.8	$	403.5
Net income attributable to FMC Technologies, Inc.	$	393.1	$	699.9	$	501.4	$	430.0	$	399.8

Earnings per share from continuing operations attributable to FMC Technologies, Inc.: ⁽¹⁾
Basic earnings per share	$	1.70	$	2.96	$	2.10	$	1.79	$	1.66
Diluted earnings per share	$	1.70	$	2.95	$	2.10	$	1.78	$	1.64

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



(In millions) As of December 31	2015			2014			2013			2012			2011
Balance sheet data:
Total assets	$	6,437.9		$	7,172.1		$	6,605.6		$	5,902.9		$	4,271.0
Net (debt) cash ⁽²⁾	$	(239.8	)	$	(666.6	)	$	(973.2	)	$	(1,298.7	)	$	(279.6	)
Long-term debt, less current portion	$	1,134.1		$	1,293.7		$	1,329.8		$	1,580.4		$	36.0
Total FMC Technologies, Inc. stockholders’ equity	$	2,511.8		$	2,456.3		$	2,317.2		$	1,836.9		$	1,424.6



(In millions) Years Ended December 31	2015		2014		2013		2012		2011
Other financial information:
Capital expenditures	$	250.8	$	404.4	$	314.1	$	405.6	$	274.0
Cash flows provided by operating activities	$	932.4	$	892.5	$	795.4	$	138.4	$	164.8
Segment operating capital employed ⁽³⁾	$	3,219.1	$	3,672.7	$	3,610.8	$	3,572.6	$	2,204.2
Order backlog ⁽⁴⁾	$	4,355.6	$	6,619.4	$	6,998.2	$	5,377.8	$	4,876.4

______________________________


⁽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 20 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 our 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 allocations to each 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 20 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 of operations and the results of operations of each of our segments for the years ended December 31, 2015, 2014 and 2013 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 results of our segments 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. 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.

Our Subsea Technologies segment is primarily affected by trends in deepwater oil and natural gas production. Our Surface Technologies segment is primarily affected by trends in land-based and shallow water oil and natural gas production, including trends in shale production. We have developed close working relationships with our customers. Our Subsea Technologies segment 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. 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 2015, approximately 73% of our total sales were recognized outside of the United States. We evaluate international markets and pursue opportunities that fit our technological capabilities and strategies. 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—Along with volatility in global equity prices and exchange rates, crude oil price volatility which began in late 2014 continued throughout 2015, and as such, uncertainty regarding the short-term market fundamentals remains. This uncertainty is driven by multiple factors, including continued strength in U.S. oil production and international crude oil supply, especially from OPEC’s and other major non-OPEC countries’ decisions to maintain oil production levels to retain or increase their market share. The increases in global crude oil inventories in 2015 marked the second consecutive year of inventory builds and have put significant downward pressure on commodity prices. As a result of the weak crude oil price environment, many crude oil development prospects have been deferred and near-term capital spending plans of our customers have been reduced, leading to a downturn in demand for our products and services and an overall weaker demand for oilfield services. The timing of any recovery of crude oil prices is dependent on many variables, including the expected impact on supply of the relief of international sanctions on Iran’s oil sector. The market corrections necessary to address the oversupply of crude oil are expected to occur over the next couple of years. Although oil companies have reduced their near-term capital investments, most of their capital spending reductions have been in capital exploration budgets that largely affect production levels beyond 2018. However, 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.

Subsea Technologies—In reaction to the decline in crude oil prices, many of our customers reduced their capital spending plans in 2015 or deferred new deepwater projects. These actions had an adverse effect on our 2015 subsea inbound orders when compared to the prior year. During 2015, we reduced our workforce to maintain operating margin improvements and to align our operations with anticipated decreases in future year activity due to delayed subsea project inbound.

Given the lower industry expectations for 2016, we have strategically aligned our focus on certain objectives to ensure our continued success during these difficult times in our industry. These objectives include (i) the continuing improvement of our execution, (ii) the strengthening of our relationships with our customers, (iii) the timely identification of further restructuring efforts to effectively reduce costs, (iv) the employment of critical supply chain management to reduce product costs, (v) the capitalization of our subsea service offerings as a continued growth platform, and (vi) the integration of our overall product and service offerings to increase the value stream to our customers. We remain focused on ways to reduce customer costs by offering cost-effective approaches to our customers’ project developments, including customer acceptance of new technologies and alternative business models to help achieve their cost-reduction goals and accelerate achievement of first oil. Many customers, including our alliance customers, are actively exploring ways to utilize our standardized subsea production equipment as operators understand the cost and scheduling benefits that standardization brings to their projects.

Additionally, Forsys Subsea, our joint venture with Technip, was designed to bring the proprietary technologies of FMC Technologies and Technip together to offer front-end engineering and design services aimed to identify opportunities through new technologies, services, and standardization of equipment to significantly reduce the cost of subsea field development. Forsys Subsea received two integrated FEED studies during 2015, and we expect expanded interest and market acceptance in 2016.

In the long-term, we continue to believe deepwater development will remain a significant part of our customers’ portfolio. 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’ fields and further expand our capabilities focused on increasing reservoir production over the life of the field. We believe the long-term commitment to deepwater was further exemplified during 2015 with Chevron joining our high-pressure, high-temperature joint industry program which is aimed to solve the technical and economic deepwater challenges operators currently face.

Surface Technologies—With the decline in crude oil prices, we expected a decline in rig counts and decreased North American land activity in 2015 to negatively affect all of our Surface Technologies businesses in North America. However, customer spending reductions, coupled with increased pricing pressure, had a greater impact in our Surface Technologies businesses than in past downturns. This market environment led us to take significant actions to reduce headcount in our North American businesses in 2015. During 2015, we largely completed the reorganization within our Surface Technologies segment. This reorganization was directly aligned with our integration efforts over the last year to bring our North American surface wellhead and completion services businesses together to create our surface integrated services businesses to strengthen our market presence and bring increased value to our customers by providing an integrated offering. Although we do not expect the North American market to recover in 2016, we expect our actions to improve our position in the North American market and reduce costs in 2016. Our international surface wellhead business delivered solid operational results in 2015 due to its strong backlog, however, pricing pressure also extended to the international markets in the latter half of 2015. This pricing pressure had a slight negative effect on our 2015 international surface wellhead inbound; however we believe international activity levels to remain resilient in 2016. Given the uncertainties regarding crude oil prices and its effect on customer spending, we believe the need for further business restructuring is likely in 2016.

CONSOLIDATED RESULTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013



	Year Ended December 31,									Change
(In millions, except percentages)	2015			2014			2013			2015 vs. 2014				2014 vs. 2013
Revenue	$	6,362.7		$	7,942.6		$	7,126.2		$	(1,579.9	)	(20)%	$	816.4		11%
Costs and expenses:
Cost of sales	4,894.8			5,994.9			5,571.4			(1,100.1		)	(18)	423.5			8
Selling, general and administrative expense	628.3			750.6			694.8			(122.3		)	(16)	55.8			8
Research and development expense	135.3			123.7			112.4			11.6			9	11.3			10
Restructuring and impairment expense	112.2			4.9			—			107.3			2,190	4.9			*
Total costs and expenses	5,770.6			6,874.1			6,378.6			(1,103.5		)	(16)	495.5			8
Gain on sale of Material Handling Products	—			84.3			—			(84.3		)	*	84.3			*
Other income (expense), net	(57.2		)	(54.0		)	5.3			(3.2		)	*	(59.3		)	*
Net interest expense	(32.3		)	(32.5		)	(33.7		)	0.2			1	1.2			4
Income before income taxes	502.6			1,066.3			719.2			(563.7		)	(53)	347.1			48
Provision for income taxes	107.8			361.0			212.6			(253.2		)	(70)	148.4			70
Net income	394.8			705.3			506.6			(310.5		)	(44)	198.7			39
Less: net income attributable to noncontrolling interests	(1.7		)	(5.4		)	(5.2		)	3.7			69	(0.2		)	(4)
Net income attributable to FMC Technologies, Inc.	$	393.1		$	699.9		$	501.4		$	(306.8	)	(44)%	$	198.5		40%

_______________________

*Not meaningful

2015 Compared With 2014

Revenue decreased by $1,579.9 million in 2015 compared to the prior year. Revenue in 2015 included a $652.5 million unfavorable impact of foreign currency translation. Excluding the impact of foreign currency translation, total revenue decreased by $927.4 million year-over-year. In Subsea Technologies, we entered 2015 with a strong backlog; however, during the latter part of 2014 and throughout 2015, crude oil prices experienced a precipitous decline. The decline in crude oil prices had an unfavorable effect on the subsea market which led to decreased order activity for subsea systems and services. Additionally, the decrease in revenue was attributable to lower sales volumes in our Schilling Robotics and Multi Phase Meters businesses as a result of lower market activity. Surface Technologies posted lower revenue in 2015 driven by lower market activity in North America which decreased demand for our well service pumps and flowline products in our fluid control business and conventional wellheads and frac-tree rental, flowback and wireline services in our surface integrated services business.

Gross profit (revenue less cost of sales) decreased as a percentage of sales to 23.1% in 2015 from 24.5% in the prior year. The decrease in gross profit as a percentage of sales was primarily due to lower market activity in North America which decreased sales volumes in our surface integrated service business and decreased sales volumes for our well service pumps and flowline products in our fluid control business. Additionally, the market downturn in North America led us to take excess and obsolescence inventory charges in our surface integrated services, fluid control and measurement solutions businesses in 2015. The decrease in gross profit as a percentage of sales was partially offset by higher margin project backlog conversion in our Western Region and Asia Pacific subsea business.

Selling, general and administrative (“SG&A”) expense decreased by $122.3 million year-over-year, driven by foreign currency translation, decreased sales commissions, and costs associated with terminating a representative agreement in our international surface wellhead business in the prior year.

Information regarding impairment and restructuring expenses recognized during 2015 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 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 foreign currency losses in 2015 primarily related to the devaluation of the Angolan kwanza. In 2014, other income (expense), net reflected foreign currency losses primarily related to 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. Further discussion of our derivative instruments is incorporated herein by reference from Note 17 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 21.5% and 34.0% in 2015 and 2014, respectively. The decrease in our effective tax rate in 2015 from 2014 was primarily due to a favorable change in mix of earnings, partially offset by an increase in the valuation allowance for certain intercompany interest costs and a settlement of an IRS audit. 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 in Singapore and 2017 and 2020 in Malaysia. 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.

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 integrated services and international surface wellhead businesses 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 our international surface wellhead business, primarily in the Middle East and Europe, and due to increased demand for our well service pumps and flowline products in our fluid control business.

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.

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 17 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 to 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.

OPERATING RESULTS OF BUSINESS SEGMENTS

YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013

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 and a reconciliation of segment operating results to consolidated income before income taxes, is incorporated herein by reference from Note 20 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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. In order to provide worldwide consolidated results, the earnings of subsidiaries functioning in their local currencies are translated into U.S. dollars based upon the average exchange rate during the period. 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



	Year Ended December 31,									Favorable/(Unfavorable)
(In millions, except %)	2015			2014			2013			2015 vs. 2014				2014 vs. 2013
Revenue	$	4,509.0		$	5,266.4		$	4,726.9		$	(757.4	)	(14)%	$	539.5	11%
Operating profit	$	630.2		$	748.2		$	548.2		$	(118.0	)	(16)%	$	200.0	36%

Operating profit as a percent of revenue	14.0		%	14.2		%	11.6		%				(0.2) pts.			2.6 pts.

2015 Compared With 2014

Subsea Technologies’ revenue decreased $757.4 million in 2015 compared to the prior year. Revenue for 2015 included a $540.6 million unfavorable impact of foreign currency translation, primarily as a result of the Brazilian real and Norwegian krone. Excluding the impact of foreign currency translation, Subsea Technologies’ revenue decreased by $216.8 million during 2015 compared to the prior year. We entered 2015 with a strong backlog; however, during the latter part of 2014 and throughout 2015, crude oil prices experienced a precipitous decline. The decline in crude oil price had an unfavorable effect on the subsea market which led to decreased order activity for subsea systems and services. Additionally, the decrease in revenue was attributable to lower sales volumes in our Schilling Robotics and Multi Phase Meters businesses as a result of lower market activity.

Subsea Technologies’ operating profit totaled $630.2 million, or 14.0% of revenue, in 2015, compared to the prior-year’s operating profit as a percentage of revenue of 14.2%. The margin decline was primarily driven by the following:


•	Subsea Systems - 0.5 percentage point increase due to higher margin project backlog conversion in our Western Region and Asia Pacific subsea business, partially offset by restructuring and severance charges in 2015; and


•	Schilling Robotics and Multi Phase Meters - 0.8 percentage point decrease due to the decline in crude oil price and its related effect on market activity in 2015.

Subsea Technologies’ operating profit in 2015 included a $77.5 million unfavorable impact of foreign currency translation and $49.7 million in impairment, restructuring and other severance charges.

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 2014 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 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.

Subsea Technologies’ operating profit in 2014 included a $24.9 million unfavorable impact of foreign currency translation.

Surface Technologies



	Year Ended December 31,									Favorable/(Unfavorable)
(In millions, except %)	2015			2014			2013			2015 vs. 2014				2014 vs. 2013
Revenue	$	1,487.6		$	2,130.7		$	1,806.8		$	(643.1	)	(30)%	$	323.9	18%
Operating profit	$	60.6		$	393.0		$	257.2		$	(332.4	)	(85)%	$	135.8	53%

Operating profit as a percent of revenue	4.1		%	18.4		%	14.2		%				(14.3) pts.			4.2 pts.

2015 Compared With 2014

Surface Technologies’ revenue decreased $643.1 million in 2015 compared to the prior year. The decrease in revenue was primarily driven by lower market activity in North America which decreased demand for our well service pumps and flowline products in our fluid control business and conventional wellheads in our surface integrated services business. Foreign currency translation unfavorably impacted revenue by $74.3 million in 2015.

Surface Technologies’ operating profit totaled $60.6 million, or 4.1% of revenue, in 2015, compared to the prior-year’s operating profit as a percentage of revenue of 18.4%. The margin decline was primarily driven by the following:


•	Surface Integrated Services - 10.2 percentage point decrease due to $59.0 million in asset impairment charges primarily in Canada, excess and obsolescence inventory charges, and lower market activity in North America; and


•	Fluid Control - 5.6 percentage point decrease due to decreased sales volumes for our well service pumps and flowline products resulting from lower activity in the North American shale markets and related excess and obsolescence inventory charges and restructuring expense.

Surface Technologies’ operating profit in 2015 included a $7.6 million favorable impact of foreign currency translation, $73.7 million in impairment, restructuring and other severance charges, and $41.1 million in excess and obsolescence inventory charges.

2014 Compared With 2013

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

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 International - 1.9 percentage point increase due to higher volumes and higher margin projects in the Middle East and Europe regions; and


•	Fluid Control - 1.8 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.

Energy Infrastructure



	Year Ended December 31,									Favorable/(Unfavorable)
(In millions, except %)	2015			2014			2013			2015 vs. 2014				2014 vs. 2013
Revenue	$	395.4		$	557.4		$	617.2		$	(162.0	)	(29)%	$	(59.8	)	(10)%
Operating profit	$	3.2		$	52.5		$	74.3		$	(49.3	)	(94)%	$	(21.8	)	(29)%

Operating profit as a percent of revenue	0.8		%	9.4		%	12.0		%				(8.6) pts.				(2.6) pts.

2015 Compared With 2014

Energy Infrastructure’s revenue decreased $162.0 million in 2015 compared to the prior year. The decrease in revenue was due to lower sales volumes primarily in our measurement solutions business driven by the market downturn in 2015. Foreign currency translation unfavorably impacted revenue by $38.7 million in 2015.

Energy Infrastructure’s operating profit totaled $3.2 million, or 0.8% of revenue, in 2015, compared to the prior-year’s operating profit as a percentage of revenue of 9.4%. The margin decline was primarily driven by a 6.5 percentage point decrease in our measurement solutions business as a result of lower sales volumes due to the market downturn in 2015 and restructuring expense, severance charges and excess and obsolescence inventory charges recorded in 2015. Energy Infrastructure’s operating profit in 2015 included $8.5 million in restructuring and other severance charges and $7.4 million in excess and obsolescence inventory charges.

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.

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:


•	Measurement Solutions - 1.5 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.

Corporate Items



	Year Ended December 31,									Favorable/(Unfavorable)
(In millions, except %)	2015			2014			2013			2015 vs. 2014				2014 vs. 2013
Corporate expense	$	(60.2	)	$	(66.3	)	$	(46.3	)	$	6.1		9%	$	(20.0	)	(43)%
Other revenue and other (expense), net	(100.8		)	(33.7		)	(85.6		)	(67.1		)	(199)%	51.9			61%
Net interest expense	(32.3		)	(32.5		)	(33.7		)	0.2			1%	1.2			4%
Total corporate items	$	(193.3	)	$	(132.5	)	$	(165.6	)	$	(60.8	)	(46)%	$	33.1		20%

2015 Compared With 2014

Our corporate items reduced earnings by $193.3 million in 2015, compared to $132.5 million in 2014. The year-over-year increase primarily reflected the following:


•	unfavorable variance of $84.3 million related to the gain on sale of our Material Handling Products business in 2014;


•	favorable variance of $8.0 million related to inventory LIFO and valuation adjustments; and a


•	favorable variance of $13.9 million associated with lower pension expense, primarily related to settlement charges in our U.S. defined benefit plan in 2014.

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 of $84.3 million related to the gain on sale of our Material Handling Products business in 2014;


•	favorable variance of $25.1 million related to the remeasurement of the Multi Phase Meters earn-out consideration in 2013;


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


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

Inbound Orders and Order Backlog

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



	Inbound Orders Year Ended December 31,
(In millions)	2015			2014
Subsea Technologies	$	3,102.7		$	5,547.1
Surface Technologies	1,289.8			2,070.4
Energy Infrastructure	379.3			473.3
Intercompany eliminations and other	(17.3		)	(6.2		)
Total inbound orders	$	4,754.5		$	8,084.6

Order backlog—Order backlog is calculated as the estimated sales value of unfilled, confirmed customer orders at the reporting date. Translation negatively affected backlog by $655.6 million and $520.8 million for the years ended December 31, 2015 and 2014, respectively.



	Order Backlog December 31,
(In millions)	2015			2014
Subsea Technologies	$	3,761.8		$	5,793.1
Surface Technologies	432.8			654.2
Energy Infrastructure	163.9			187.0
Intercompany eliminations	(2.9		)	(14.9		)
Total order backlog	$	4,355.6		$	6,619.4

Subsea Technologies. Order backlog at December 31, 2015, decreased by $2.0 billion compared to December 31, 2014, primarily due to lower inbound orders during 2015 and the negative impact of foreign currency translation. Subsea Technologies backlog of $3.8 billion at December 31, 2015, was composed of various subsea projects, including BP’s Mad Dog Phase 2 and Shah Deniz Stage 2; Chevron’s Agbami; Eni’s Block 15/06 East Hub and Jangkrik; Petrobras’ pre-salt tree and manifold award; Shell's Appomattox; Statoil’s Johan Sverdrup Phase 1; Total’s Egina; Tullow Ghana’s TEN; Wintershall’s Maria; and Woodside's Greater Western Flank Phase 2. The above listed projects represented 73% of our Subsea Technologies backlog as of December 31, 2015. We expect to convert approximately 55% to 60% of December 31, 2015 backlog into revenue during 2016.

Surface Technologies. Order backlog at December 31, 2015 decreased by $221.4 million compared to December 31, 2014. The decrease in backlog was due to lower inbound orders primarily in our fluid control and surface integrated services businesses during 2015. We expect to convert substantially all December 31, 2015 backlog into revenue into 2016.

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 financial measure reflecting cash and cash equivalents, net of debt. Management uses this non-GAAP financial measure to evaluate our capital structure and financial leverage. We believe net debt, or net cash, is a meaningful financial measure that may assist investors in understanding our financial condition and recognizing underlying trends in our capital structure. 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, 2015			December 31, 2014
Cash and cash equivalents	$	916.2		$	638.8
Short-term debt and current portion of long-term debt	(21.9		)	(11.7		)
Long-term debt, less current portion	(1,134.1		)	(1,293.7		)
Net debt	$	(239.8	)	$	(666.6	)

The change in our net debt position was primarily due to lower capital expenditures, positive changes in our working capital position, and decreased treasury stock repurchases, partially offset by lower cash generated from operating activities from lower income from operations and cash requirements to fund our joint ventures.

Cash Flows

Cash flows for each of the years in the three-year period ended December 31, 2015, were as follows:



	Year Ended December 31,
(In millions)	2015			2014			2013
Cash provided by operating activities	$	932.4		$	892.5		$	795.4
Cash required by investing activities	(275.2		)	(285.1		)	(311.6		)
Cash required by financing activities	(345.6		)	(355.4		)	(422.3		)
Effect of exchange rate changes on cash and cash equivalents	(34.2		)	(12.3		)	(4.5		)
Increase in cash and cash equivalents	$	277.4		$	239.7		$	57.0

Operating cash flows—During 2015, we generated $932.4 million in cash flows from operating activities, which represented a $39.9 million increase compared to the prior year. Our cash flows from operating activities in 2014 were $97.1 million higher than 2013. The year-over-year increase in 2015 was due to a positive change in our working capital position driven by our portfolio of projects resulting from collections of receivables, partially offset by lower income during the year. 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 2013. 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 2015 were $275.2 million, primarily reflecting cash required by our capital expenditure program of $250.8 million during 2015 related to continued investments in service asset primarily in our Subsea Technologies segment and $34.5 million in investments in our Forsys Subsea and FTO Services joint ventures.

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 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 related to continued investments in capacity expansion and service asset investments primarily in our Subsea Technologies segment.

Financing cash flows—Cash required by financing activities was $345.6 million in 2015. The decrease in cash required from financing activities from the prior year was driven by decreased purchases of treasury stock in 2015 and the payment of the Multi Phase Meters earn-out obligation in 2014, partially offset by higher payments to reduce our commercial paper position in 2015.

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.

Debt and Liquidity

Total borrowings at December 31, 2015 and 2014, comprised the following:



	December 31,
(In millions)	2015		2014
Revolving credit facility	$	—	$	—
Commercial paper	337.2		469.1
2.00% Notes due 2017	299.1		298.6
3.45% Notes due 2022	497.5		497.2
Term loan	15.6		22.9
Foreign uncommitted credit facilities	5.9		7.9
Property financing	0.7		9.7
Total borrowings	$	1,156.0	$	1,305.4

Credit Facility—On September 24, 2015, we entered into a new $2.0 billion revolving credit agreement (“credit agreement”) with Wells Fargo Bank, National Association, as Administrative Agent. The credit agreement is a five-year, revolving credit facility expiring in September 2020. Subject to certain conditions, at our request the aggregate commitments under the credit agreement may be increased by an additional $500 million.

Borrowings under the credit agreement bear interest at the highest of three base rates or the London interbank offered rate (“LIBOR”), at our option, plus an applicable margin. Depending on our senior unsecured credit rating, the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 1.00% to 1.75% and (ii) in the case of base rate loans, from 0.00% to 0.75%.

In connection with the new credit agreement, we terminated our previously existing $1.5 billion five-year, revolving credit agreement.

The following is a summary of our revolving credit facility at December 31, 2015:



(In millions) Description	Amount		Debt Outstanding		Commercial Paper Outstanding (a)		Letters of Credit		Unused Capacity		Maturity
Five-year revolving credit facility	$	2,000.0	$	—	$	337.2	$	—	$	1,662.8	September 2020

______________________________


^(a)	Under our commercial paper program, we have the ability to access up to $1.5 billion of financing through our commercial paper dealers. Our available capacity under our revolving credit facility is reduced by any outstanding commercial paper.

Committed credit available under our revolving credit facility provides the ability to issue our commercial paper obligations on a long-term basis. We had $337.2 million of commercial paper issued under our facility at December 31, 2015. 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, 2015.

Among other restrictions, the terms of the credit agreement include negative covenants related to liens and our total capitalization ratio. As of December 31, 2015, 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 2016

Liquidity and Capital Resources—Historically, we have generated our liquidity and capital resources primarily through operations and, when needed, through our credit facility. We have $1,662.8 million in capacity available under our revolving credit facility that we expect to utilize if working capital needs temporarily increase in response to changes in market demand. The volatility in credit, equity and commodity markets creates some uncertainty for our businesses. Although we will continue to reach payment milestones on many of our projects, we expect our consolidated operating cash flow position in 2016 to decrease as a result of the negative impact the decline in commodity prices will have on our overall business. The downturn in the oilfield services industry as a result of the decrease in commodity prices has led some of our customers to request price concessions or delays in backlog delivery. Consequently, any discounts or material product delivery delays that may ultimately be mutually agreed with our customers may adversely affect our results of operations and cash flows. 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.

The term loan supporting our Brazilian operations matures in 2016; however, we expect to re-finance this obligation during 2016.

We expect to make contributions of approximately $12.7 million to our international pension plans during 2016. 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 $3.7 million to our U.S. Non-Qualified Defined Benefit Pension Plan during 2016.

We project spending approximately $180 million in 2016 for capital expenditures, largely towards maintenance expenditures in our subsea service business. Further, we expect to continue our stock repurchases authorized by our Board of Directors, with the timing and amounts of these repurchases dependent upon market conditions and liquidity.

We 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.

Credit rating—Due to the deterioration in crude oil prices, Moody’s has placed many U.S. exploration and production and oilfield service companies, including FMC Technologies, on review for downgrade. Should a downgrade occur, we believe it is reasonably likely to affect our borrowing costs related to our commercial paper program; however, we are currently unable to estimate the incremental borrowing costs under our commercial paper program during 2016.

Contractual Obligations

The following is a summary of our contractual obligations at December 31, 2015:



	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)	$	1,150.1	$	16.0	$	636.6	$	—	$	497.5
Short-term debt	5.9		5.9		—		—		—
Interest on long-term debt ^(a)	132.8		23.3		40.5		34.5		34.5
Operating leases ^(b)	421.0		85.9		128.1		78.4		128.6
Purchase obligations ^(c)	602.6		506.5		94.9		1.2		—
Pension and other post-retirement benefits ^(d)	12.7		12.7		—		—		—
Unrecognized tax benefits ^(e)	9.7		9.7		—		—		—
Total contractual obligations	$	2,334.8	$	660.0	$	900.1	$	114.1	$	660.6

______________________________


^(a)	Our available long-term debt is dependent upon our compliance with covenants, including negative covenants related to liens and our total capitalization 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.

Due to our intent and ability to refinance commercial paper obligations on a long-term basis under our revolving credit facility and the variable interest rates associated with these debt instruments, only interest on our Senior Notes is included in the table. During 2015, we paid $31.0 million for interest charges, net of interest capitalized.

^(b)

In 2014 we entered into construction and operating lease agreements to finance the construction of manufacturing and office facilities located in Houston, TX. In January 2016, construction of the facilities was completed and the operating lease commenced. 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 $12.7 million to our international pension plans, representing primarily the U.K. and Norway qualified pension plans, in 2016. Required contributions for future years depend on factors that cannot be determined at this time. Additionally, we expect to contribute $3.7 million to our U.S. Non-Qualified Defined Benefit Pension Plan in 2016.


^(e)	It is reasonably possible that $9.7 million of liabilities for unrecognized tax benefits will be settled during 2016, and this amount is reflected in income taxes payable in our consolidated balance sheet as of December 31, 2015. 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, 2015:



	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)	$	677.8	$	266.5	$	188.0	$	115.4	$	107.9
Surety bonds ^(a)	5.7		1.1		4.0		—		0.6
Third party guarantees ^(b)	20.0		20.0		—		—		—
Total other off-balance sheet arrangements	$	703.5	$	287.6	$	192.0	$	115.4	$	108.5

______________________________

^(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. 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 reasonably likely there will be material claims against these commitments. However, should these financial instruments become unavailable to us, our operations and liquidity could be negatively impacted.


^(b)	In August 2014 FMC Technologies entered into an arrangement to jointly guarantee the debt obligations under a revolving credit facility of FTO Services, our joint venture with Edison Chouest Offshore LLC. Information regarding our guarantee is incorporated herein by reference from Note 12 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 60%, 52% and 55% of total revenue recognized for the years ended December 31, 2015, 2014 and 2013, 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, 2015, 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 $30.1 million for the year ended December 31, 2015.

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 market. We evaluate the components of inventory on a regular basis for excess and obsolescence. 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. Factors that could materially impact our estimate include changes in crude oil prices and its effect on the longevity of the current industry downturn, which would impact the demand for our products and services, as well as changes in the pattern of demand for the products that we offer. We believe our inventory valuation reserve is adequate to properly value potential excess and obsolete inventory as of December 31, 2015, however, any significant changes to the factors mentioned above could lead our estimate to change. Refer to 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 recorded during 2015.

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. During 2015, we identified various assets whose carrying values were impaired due to the downturn in the oilfield services industry, driven by the decline in crude oil prices. Refer to Note 4 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to asset impairment charges recorded during 2015. If future market conditions deteriorate beyond our current expectations and assumptions, additional impairments of long-lived assets may be identified if we conclude that the carrying amounts are no longer recoverable.

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.

At December 31, 2014, we determined the fair values of our heritage completion services and automation and control reporting units did not substantially exceed their carrying values. As a result, we conducted interim goodwill impairments tests for both these reporting units during the first and second quarter in 2015. As part of management’s strategy to integrate our products and services in our Surface Technologies segment, the services of our completion services reporting unit became part of our U.S. and Canadian surface integrated services reporting units during the third quarter of 2015. Refer to Part I, Item 1 “Business” for further information regarding these integration efforts. A goodwill impairment charge of $8.4 million related to our Canadian surface integrated services reporting unit was recorded in our Surface Technologies segment during the third quarter of 2015 as a result of the continued deterioration in crude oil prices and its related effect on demand for services of the reporting unit. Refer to Note 4 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to asset impairment charges recorded in 2015. We did not recognize any goodwill impairment during 2014, 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 requiring us to perform additional impairment reviews.

A lower fair value estimate in the future for any of our reporting units, specifically our U.S. surface integrated services and separation systems 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.

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, 2015, 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, 2015, 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 15 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 2015 Pension Expense Before Income Taxes			Increase (Decrease) in Projected Benefit Obligation at December 31, 2015
50 basis point decrease in discount rate	$	9.9		$	88.7
50 basis point increase in discount rate	$	(9.2	)	$	(79.8	)
50 basis point decrease in expected long-term rate of return on plan assets	$	4.3
50 basis point increase in expected long-term rate of return on plan assets	$	(4.3	)

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

As previously disclosed, during the second quarter of 2014, we received an inquiry and a subpoena from the SEC seeking information about paid-time-off accruals within the automation and control business unit. The inquiry continued into the second half of 2014 and covered revenue and expenses in certain business units. Pursuant to additional subpoenas received in 2015, we provided information regarding our tax department and our previously disclosed accounting treatment for uncertain foreign tax positions.

We have fully responded to all of the SEC’s requests for information and have cooperated and engaged in discussions with the SEC. On January 19, 2016, we received a notice indicating that the SEC had made a preliminary determination to recommend that the SEC Division of Enforcement file a civil enforcement action against the Company for alleged violations of the reporting, books-and-records and internal control provisions of U.S. securities laws. We believe that no enforcement action is warranted against us, and we intend to vigorously defend any claims that may be brought. We have discussed these matters with our independent registered public accounting firm and our Audit Committee.

Recently Issued Accounting Standards

Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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, 2015 and 2014, 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. Many 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, 2015, would have changed our revenue and income before income taxes attributable to FMC Technologies, Inc. by approximately 4% and 2%, respectively.

When transactions are denominated in currencies other than our subsidiaries’ respective functional currencies, we manage these exposures through the use of derivative instruments. We primarily 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 usually 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. Unless these cash flow contracts are deemed to be ineffective or are not designated as cash flow hedges at inception, 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. 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 containing terms and conditions that qualify as embedded derivative instruments and are subject to fluctuations in foreign exchange rates. In those situations, we enter into derivative foreign exchange contracts that hedge the price or cost fluctuations due to movements in the foreign exchange rates. These derivative instruments are not designated 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 $68.0 million in the net fair value of cash flow hedges reflected in our consolidated balance sheet at December 31, 2015.

Interest Rate Risk

At December 31, 2015, we had unhedged variable rate debt of $337.2 million with a weighted average interest rate of 0.89%. Using sensitivity analysis to measure the impact of a 10% adverse movement in the interest rate, or nine basis points, would result in an increase to interest expense of $0.3 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 in the unrealized valuation of our forward foreign currency contracts 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 unrealized earnings in the period of change. Based on our portfolio as of December 31, 2015, we have material positions with exposure to the interest rates in the United States, Canada, Australia, 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 and operated, 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 (2013) 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, 2015.

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, 2015, and has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2015, which is included herein.



/s/ JOHN T. GREMP		/s/ MARYANN T. MANNEN
John T. Gremp		Maryann T. Mannen
Chairman and Chief Executive Officer		Executive Vice President and Chief Financial Officer

February 24, 2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

FMC Technologies, Inc.:

We have audited FMC Technologies, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) 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 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, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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, 2015 and 2014, 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, 2015, and our report dated February 24, 2016 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 24, 2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

FMC Technologies, Inc.:

We have audited the accompanying consolidated balance sheets of FMC Technologies, Inc. and subsidiaries as of December 31, 2015 and 2014, 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, 2015. 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 FMC Technologies, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, 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, present 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), FMC Technologies, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 24, 2016

FMC TECHNOLOGIES, INC. AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



	Year Ended December 31,
(In millions, except per share data)	2015			2014			2013
Revenue:
Product revenue	$	5,084.5		$	6,335.7		$	5,724.7
Service revenue	1,024.8			1,276.5			1,066.0
Lease and other income	253.4			330.4			335.5
Total revenue	6,362.7			7,942.6			7,126.2
Costs and expenses:
Cost of product revenue	3,915.9			4,855.1			4,562.4
Cost of service revenue	772.1			925.0			792.7
Cost of lease and other revenue	206.8			214.8			216.3
Selling, general and administrative expense	628.3			750.6			694.8
Research and development expense	135.3			123.7			112.4
Restructuring and impairment expense (Note 4)	112.2			4.9			—
Total costs and expenses	5,770.6			6,874.1			6,378.6
Gain on sale of Material Handling Products (Note 5)	—			84.3			—
Other income (expense), net	(57.2		)	(54.0		)	5.3
Income before interest income, interest expense and income taxes	534.9			1,098.8			752.9
Interest income	0.8			1.1			0.7
Interest expense	(33.1		)	(33.6		)	(34.4		)
Income before income taxes	502.6			1,066.3			719.2
Provision for income taxes (Note 14)	107.8			361.0			212.6
Net income	394.8			705.3			506.6
Net income attributable to noncontrolling interests	(1.7		)	(5.4		)	(5.2		)
Net income attributable to FMC Technologies, Inc.	$	393.1		$	699.9		$	501.4
Earnings per share attributable to FMC Technologies, Inc. (Note 3):
Basic	$	1.70		$	2.96		$	2.10
Diluted	$	1.70		$	2.95		$	2.10
Weighted average shares outstanding (Note 3):
Basic	230.9			236.3			238.3
Diluted	231.7			236.9			239.1

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)	2015			2014			2013
Net income	$	394.8		$	705.3		$	506.6
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments ⁽¹⁾	(182.3		)	(107.6		)	(99.7		)
Net gains (losses) on hedging instruments:
Net gains (losses) arising during the period	(64.9		)	(108.4		)	27.1
Reclassification adjustment for net losses (gains) included in net income	55.1			(0.8		)	(5.2		)
Net gains (losses) on hedging instruments ⁽²⁾	(9.8		)	(109.2		)	21.9
Pension and other post-retirement benefits:
Net actuarial gain (loss) arising during the period	(21.0		)	(152.7		)	112.5
Prior service cost arising during the period	—			(1.7		)	(0.4		)
Reclassification adjustment for settlement losses included in net income	1.2			15.7			3.2
Reclassification adjustment for amortization of prior service cost (credit) included in net income	0.1			0.3			(0.3		)
Reclassification adjustment for amortization of net actuarial loss included in net income	22.9			12.3			18.2
Reclassification adjustment for amortization of transition asset included in net income	(0.1		)	(0.1		)	(0.1		)
Net pension and other post-retirement benefits ⁽³⁾	3.1			(126.2		)	133.1
Other comprehensive income (loss), net of tax	(189.0		)	(343.0		)	55.3
Comprehensive income	205.8			362.3			561.9
Comprehensive income attributable to noncontrolling interest	(1.7		)	(5.4		)	(5.2		)
Comprehensive income attributable to FMC Technologies, Inc.	$	204.1		$	356.9		$	556.7

______________________


⁽¹⁾	Net of income tax (expense) benefit of $7.9, $7.2 and $(1.6) for the years ended December 31, 2015, 2014 and 2013, respectively.


⁽²⁾	Net of income tax benefit of $3.3, $25.7 and $1.0 for the years ended December 31, 2015, 2014 and 2013, respectively.


⁽³⁾	Net of income tax (expense) benefit of $(4.1), $56.9 and $(81.8) for the years ended December 31, 2015, 2014 and 2013, 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)	2015			2014
Assets
Cash and cash equivalents	$	916.2		$	638.8
Receivables, net of allowances of $19.2 in 2015 and $9.4 in 2014 (Note 22)	1,522.4			2,127.0
Inventories, net (Note 6)	744.6			1,021.2
Derivative financial instruments (Note 17)	371.9			197.6
Prepaid expenses	48.9			48.5
Income taxes receivable	68.7			23.4
Other current assets	276.0			379.9
Total current assets	3,948.7			4,436.4
Investments	29.6			35.9
Property, plant and equipment, net (Note 8)	1,371.5			1,458.4
Goodwill (Note 9)	514.7			552.1
Intangible assets, net (Note 9)	246.3			314.5
Deferred income taxes (Note 14)	183.3			106.5
Derivative financial instruments (Note 17)	0.1			134.9
Other assets	143.7			133.4
Total assets	$	6,437.9		$	7,172.1
Liabilities and equity
Short-term debt and current portion of long-term debt (Note 10)	$	21.9		$	11.7
Accounts payable, trade	519.3			723.5
Advance payments and progress billings	664.6			965.2
Accrued payroll	185.8			256.8
Derivative financial instruments (Note 17)	554.9			230.2
Income taxes payable	57.2			152.9
Other current liabilities	339.6			443.3
Total current liabilities	2,343.3			2,783.6
Long-term debt, less current portion (Note 10)	1,134.1			1,293.7
Accrued pension and other post-retirement benefits, less current portion (Note 15)	230.4			236.7
Derivative financial instruments (Note 17)	0.5			220.2
Deferred income taxes (Note 14)	98.2			54.3
Other liabilities	100.5			105.9
Commitments and contingent liabilities (Note 12)
Stockholders’ equity (Note 13):
Preferred stock, $0.01 par value, 12.0 shares authorized; no shares issued in 2015 or 2014	—			—
Common stock, $0.01 par value, 600.0 shares authorized in 2015 and 2014; 286.3 shares issued in 2015 and 2014; and 226.8 and 231.5 shares outstanding in 2015 and 2014, respectively	2.9			2.9
Common stock held in employee benefit trust, at cost; 0.2 shares in 2015 and 2014	(7.0		)	(8.0		)
Treasury stock, at cost, 59.4 and 54.6 shares in 2015 and 2014, respectively	(1,607.8		)	(1,431.1		)
Capital in excess of par value of common stock	759.0			731.9
Retained earnings	4,237.4			3,844.3
Accumulated other comprehensive loss	(872.7		)	(683.7		)
Total FMC Technologies, Inc. stockholders’ equity	2,511.8			2,456.3
Noncontrolling interests	19.1			21.4
Total equity	2,530.9			2,477.7
Total liabilities and equity	$	6,437.9		$	7,172.1

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)	2015			2014			2013
Cash provided (required) by operating activities:
Net income	$	394.8		$	705.3		$	506.6
Adjustments to reconcile net income to cash provided (required) by operating activities:
Depreciation	179.5			170.8			156.0
Amortization	72.1			61.7			53.8
Employee benefit plan and stock-based compensation costs	81.8			89.3			93.5
Deferred income tax provision (benefit), net	12.1			(18.1		)	(20.4		)
Unrealized loss (gain) on derivative instruments	59.5			54.4			(5.7		)
Impairments	66.5			—			—
Gain on sale of Material Handling Products	—			(84.3		)	—
Other	44.9			10.8			30.4
Changes in operating assets and liabilities, net of effects of acquisitions:
Receivables, net	395.0			(243.0		)	(391.0		)
Inventories, net	238.0			(99.4		)	(28.9		)
Accounts payable, trade	(154.5		)	33.8			103.8
Advance payments and progress billings	(234.7		)	225.0			329.0
Income taxes payable, net	(129.7		)	16.2			77.3
Payment of Multi Phase Meters earn-out consideration	—			(43.6		)	(32.2		)
Accrued pension and other post-retirement benefits, net	(24.8		)	(32.0		)	(60.1		)
Other assets and liabilities, net	(68.1		)	45.6			(16.7		)
Cash provided by operating activities	932.4			892.5			795.4
Cash provided (required) by investing activities:
Capital expenditures	(250.8		)	(404.4		)	(314.1		)
Investments in joint ventures	(34.5		)	(3.0		)	(2.0		)
Proceeds from sale of Material Handling Products, net of cash divested	—			105.6			—
Other	10.1			16.7			4.5
Cash required by investing activities	(275.2		)	(285.1		)	(311.6		)
Cash provided (required) by financing activities:
Net increase (decrease) in short-term debt	(0.7		)	(25.8		)	8.5
Net decrease in commercial paper	(131.9		)	(32.3		)	(168.4		)
Proceeds from issuance of long-term debt	—			—			26.2
Repayments of long-term debt	(1.2		)	(1.6		)	(136.0		)
Purchase of treasury stock	(186.2		)	(247.6		)	(116.3		)
Payment of Multi Phase Meters earn-out consideration	—			(31.0		)	(25.1		)
Acquisitions, payment of withheld purchase price	(9.6		)	—			—
Payments related to taxes withheld on stock-based compensation	(8.8		)	(13.0		)	(17.5		)
Other	(7.2		)	(4.1		)	6.3
Cash required by financing activities	(345.6		)	(355.4		)	(422.3		)
Effect of exchange rate changes on cash and cash equivalents	(34.2		)	(12.3		)	(4.5		)
Increase in cash and cash equivalents	277.4			239.7			57.0
Cash and cash equivalents, beginning of year	638.8			399.1			342.1
Cash and cash equivalents, end of year	$	916.2		$	638.8		$	399.1

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, 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 13)	—		(116.3		)	—			—			—			—			(116.3		)
Reissuances of treasury stock (Note 13)	—		22.3			(22.3		)	—			—			—			—
Net sales of common stock for employee benefit trust	—		0.1			1.0			—			—			—			1.1
Stock-based compensation (Note 16)	—		—			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
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 13)	—		(247.6		)	—			—			—			—			(247.6		)
Reissuances of treasury stock (Note 13)	—		13.1			(13.1		)	—			—			—			—
Net purchases of common stock for employee benefit trust	—		(0.3		)	0.5			—			—			—			0.2
Stock-based compensation (Note 16)	—		—			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



(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, 2014	$	2.9	$	(1,439.1	)	$	731.9		$	3,844.3	$	(683.7	)	$	21.4		$	2,477.7
Net income	—		—			—			393.1		—			1.7			394.8
Other comprehensive loss	—		—			—			—		(189.0		)	—			(189.0		)
Excess tax benefits on stock-based payment arrangements	—		—			0.2			—		—			—			0.2
Taxes withheld on issuance of stock-based awards	—		—			(8.8		)	—		—			—			(8.8		)
Purchases of treasury stock (Note 13)	—		(186.2		)	(4.2		)	—		—			—			(190.4		)
Reissuances of treasury stock (Note 13)	—		9.5			(9.5		)	—		—			—			—
Net sales of common stock for employee benefit trust	—		1.0			—			—		—			—			1.0
Stock-based compensation (Note 16)	—		—			49.4			—		—			—			49.4
Other	—		—			—			—		—			(4.0		)	(4.0		)
Balance at December 31, 2015	$	2.9	$	(1,614.8	)	$	759.0		$	4,237.4	$	(872.7	)	$	19.1		$	2,530.9

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,” “us” or “our”) 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 were 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—These 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 equity method of accounting is used to account for investments in unconsolidated affiliates where we have the ability to exert significant influence over the affiliate’s operating and financial policies. The cost method of accounting is used where significant influence over the affiliate is not present.

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. These reclassifications include (i) income tax presentation in the cash provided by operating activities section on the consolidated statements of cash flows and (ii) intangible asset reclassification from other assets to intangible assets on the consolidated balance sheets.

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 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.

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

Inventories—Inventories are stated at the lower of cost or market. 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 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”). We did not have any available-for-sale securities at December 31, 2015 or 2014.

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 classified as held for sale are reported at the lower of carrying value or fair value less cost to sell.

Capitalized software costs—Capitalized software costs are recorded at cost. Capitalized software costs include 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 and are presented, net of accumulated amortization, in other assets on the consolidated balance sheets. 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, with the exception of certain assets and liabilities measured using the net asset value practical expedient, which are not required to be leveled. 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. We use the treasury stock method to compute diluted EPS which gives effect to the potential dilution of earnings that could have occurred if additional shares were issued for awards granted under our incentive compensation and stock plan. The treasury stock method assumes proceeds that would be obtained upon exercise of awards granted under our incentive compensation and stock plan are used to purchase 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 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 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. NEW ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

Effective January 1, 2015, we adopted Accounting Standards Update (“ASU”) No. 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items” which eliminates from GAAP the concept of extraordinary items. However, the presentation and disclosure guidance for items that are unusual in nature or infrequent in occurrence was retained. We adopted the updated guidance prospectively. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements.

Effective July 1, 2015, we adopted ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” This update requires debt issuance costs to be presented in the balance sheet as a deduction from the carrying amount of the corresponding debt liability, consistent with debt discounts or premiums. We adopted the updated guidance retrospectively. Effective September 30, 2015, we adopted ASU No. 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” This update incorporates the SEC staff’s announcement that it would not object to an entity presenting the costs of securing a revolving line of credit as an asset, regardless of whether a balance is outstanding. We adopted the updated guidance retrospectively. The adoption of these updates concerns presentation and disclosure only as it relates to our consolidated financial statements.

Effective December 31, 2015, we adopted ASU No. 2015-07, “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent).” This update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure requirements. We adopted the updated guidance retrospectively. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements.

Effective December 31, 2015, we adopted ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes.” This update requires entities to present deferred tax assets and deferred tax liabilities as noncurrent in a classified balance sheet. The standard simplifies the previous guidance, which required entities to separately present deferred tax assets and deferred tax liabilities as current and noncurrent in a classified balance sheet. We adopted the updated guidance prospectively. Prior periods have not been retrospectively adjusted for the adoption of this standard. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements.

Recently Issued Accounting Standards

In May 2014, the FASB issued 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. In August 2015, the FASB issued ASU No. 2015-14 which deferred the effective date of ASU No. 2014-09 by one year, and as a result, is now effective for us on January 1, 2018. Early adoption is permitted to the original effective date of January 1, 2017. 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. We have not determined the method to be utilized upon adoption. The impacts that adoption of the ASU is expected to have on our consolidated financial statements and related disclosures are being evaluated. Additionally, we have not determined the effect of the ASU on our internal control over financial reporting or other changes in business practices and processes.

In February 2015, the FASB issued ASU No. 2015-02, “Amendments to the Consolidation Analysis.” Among other amendments, this update removes three of the six criteria a fee must meet for a decision maker or service provider to conclude a fee does not represent a variable interest, alters how variable interests held by related parties affect consolidation, and clarifies the two-step process to determine whether the at-risk equity holders of a corporation have the power to direct the corporation’s significant activities. The amendments in this ASU are effective for us on January 1, 2016. Early application is permitted. We chose to adopt the guidance using a modified retrospective approach, and the effect of this adoption was deemed to be not material.

In April 2015, the FASB issued ASU No. 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This update provides guidance on the recognition of fees paid by a customer for cloud computing arrangements as either the acquisition of a software license or a service contract. The amendments in this ASU are effective for us on January 1, 2016. Early application is permitted. Entities may apply the new guidance either prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. We chose to adopt the guidance prospectively, and the effect of this adoption was deemed to be not material.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This update requires in scope inventory to be measured at the lower of cost and net realizable value rather than at the lower of cost or market under existing guidance. The amendments in this ASU are effective for us on January 1, 2017 and are required to be adopted prospectively. Early application is permitted. We are currently evaluating the impact of this ASU 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)	2015		2014		2013
Net income attributable to FMC Technologies, Inc.	$	393.1	$	699.9	$	501.4
Weighted average number of shares outstanding	230.9		236.3		238.3
Dilutive effect of restricted stock units and stock options	0.8		0.6		0.8
Total shares and dilutive securities	231.7		236.9		239.1

Basic earnings per share attributable to FMC Technologies, Inc.	$	1.70	$	2.96	$	2.10
Diluted earnings per share attributable to FMC Technologies, Inc.	$	1.70	$	2.95	$	2.10

NOTE 4. RESTRUCTURING AND IMPAIRMENT EXPENSE

Restructuring and impairment expense were as follows:



	Year Ended December 31,
(In millions)	2015		2014
Restructuring expense:
Subsea Technologies	$	28.0	$	4.9
Surface Technologies	12.0		—
Energy Infrastructure	5.7		—
Total restructuring expense	45.7		4.9
Impairment expense:
Subsea Technologies	5.1		—
Surface Technologies	61.4		—
Energy Infrastructure	—		—
Total impairment expense	66.5		—
Total restructuring and impairment expense	$	112.2	$	4.9

Restructuring—As a result of the decline in crude oil prices and its effect on the demand for products and services in the oilfield services industry worldwide, beginning in 2015, we initiated a company-wide reduction in workforce intended to reduce costs and better align our workforce with current and anticipated activity levels, which resulted in the recognition of severance costs relating to termination benefits and other restructuring charges. We did not record any restructuring expenses during the year ended December 31, 2013.

Asset impairments—We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate the carrying value may not be recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition over the assets remaining useful life. Our review of recoverability of the carrying value of our assets considers several assumptions including the intended use and service potential of the asset.

The prolonged downturn in the energy market and its corresponding impact on our business outlook led us to conclude the carrying amount of certain of our assets, primarily in our surface integrated services business in Canada, exceeded their fair values. The low commodity price environment’s impact on our outlook for revenue growth and profitability of our surface integrated services business in Canada led us to record impairment charges of $54.7 million in our Surface Technologies segment during the year ended December 31, 2015. These charges include the complete impairment of customer relationships intangible asset and goodwill in our Canadian surface integrated services reporting unit of $33.3 million and $8.4 million, respectively, as well as a charge of $13.0 million to record wireline and flowback long-lived assets at their fair value of $39.4 million as of September 30, 2015. Refer to Note 18 to these consolidated financial statements for a discussion of the method used to determine the fair value of these assets. We did not record any impairment expenses during the years ended December 31, 2014 and 2013.

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)	2015			2014
Raw materials	$	149.9		$	196.6
Work in process	114.8			166.1
Finished goods	723.4			849.9
	988.1			1,212.6
LIFO and valuation adjustments	(243.5		)	(191.4		)
Inventory, net	$	744.6		$	1,021.2

Historically, we have held quantities of inventory in our Surface Technologies segment necessary to react to fast-paced changes in customer demand, particularly in the North American market. As a result of the decline in crude oil prices and its effect on demand for products and services in the oilfield services industry as well as changes in the pattern of demand for certain types of inventory, we recorded $41.1 million of inventory valuation reserves in our Surface Technologies segment during the year ended December 31, 2015.

Net inventories accounted for under the LIFO method totaled $253.6 million and $370.8 million at December 31, 2015 and 2014, respectively. The current replacement costs of LIFO inventories exceeded their recorded values by $90.2 million and $94.6 million at December 31, 2015 and 2014, respectively. In 2015 and 2013 there were reductions 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 $2.3 million and $0.1 million for 2015 and 2013, respectively. There was no reduction to the base LIFO inventory in 2014.

NOTE 7. EQUITY METHOD INVESTMENTS

FTO Services—FMC Technologies Offshore, LLC (“FTO Services”) is an affiliated company in the form of a joint venture between FMC Technologies and Edison Chouest Offshore LLC. FTO Services provides integrated vessel-based subsea services for offshore oil and gas fields globally, and its results are reported in our Subsea Technologies segment. FTO Services, as lessee, rents riserless light well intervention assets from FMC Technologies. Our cumulative equity investment in FTO Services totaled $12.0 million as of December 31, 2015. We have accounted for our 50% investment using the equity method of accounting. Additionally, debt obligations under a revolving credit facility of FTO Services are jointly and severally guaranteed by FMC Technologies and Edison Chouest Offshore LLC. Refer to Note 12 for additional information regarding the guarantee.

FTO Services has experienced net losses since formation due to expenses related to startup of operations and as a result of the downturn in the oilfield services industry. We recognized $44.5 million of losses from equity earnings in FTO Services for the year ended December 31, 2015, which are included in lease and other income in the accompanying consolidated statements of income. All prior year results were not material. The carrying value of our equity method investment in FTO Services was $(22.0) million as of December 31, 2015, and is included as a component of other liabilities in the accompanying consolidated balance sheets. As a result of our joint guarantee of FTO Services’ debt obligations under its revolving credit facility and additional financial support provided and committed, we recognized losses up to our joint share of such obligations and re-suspended the recognition of equity method losses as of December 31, 2015.

Forsys Subsea—Forsys Subsea Limited (“Forsys Subsea”) is an affiliated company in the form of a joint venture between FMC Technologies and Technip S.A. Forsys Subsea provides front-end engineering and life-of-field decision support services for subsea fields globally, and its results are reported in our Subsea Technologies segment. During 2015, we provided financial support to Forsys Subsea. We have accounted for our 50% investment using the equity method of accounting. Forsys Subsea has experienced net losses since formation due to expenses related to startup of operations and as a result of the downturn in the oilfield services industry. We recognized $9.3 million of losses from equity earnings in Forsys Subsea for the year ended December 31, 2015, which are included in lease and other income in the accompanying consolidated statements of income.

Summarized financial information—Summarized financial information for 100% of FTO Services and Forsys Subsea are presented below.



(In millions)	2015			2014⁽¹⁾			2013⁽¹⁾
As of December 31
Current assets	$	49.6		$	13.5
Noncurrent assets	4.2			0.1
Current liabilities	125.0			10.4
Noncurrent liabilities	40.2			7.0
Year ended December 31
Revenues	23.6			11.0			$	2.1
Gross profit (loss)	(17.0		)	(3.1		)	(0.4		)
Net income (loss)	(107.8		)	(10.9		)	(2.8		)

______________________________


⁽¹⁾	Due to its formation in the second quarter of 2015, financial information for Forsys Subsea is not applicable for 2014 and 2013.

NOTE 8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	December 31,
(In millions)	2015			2014
Land and land improvements	$	78.4		$	83.8
Buildings	385.6			410.6
Machinery and equipment	1,620.8			1,530.5
Construction in process	178.8			266.9
	2,263.6			2,291.8
Accumulated depreciation	(892.1		)	(833.4		)
Property, plant and equipment, net	$	1,371.5		$	1,458.4

Depreciation expense was $179.5, million, $170.8 million and $156.0 million in 2015, 2014 and 2013, respectively. The amount of interest cost capitalized was $1.6 million, $0.9 million and $0.7 million in 2015, 2014 and 2013, respectively.

NOTE 9. 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, 2014	$	378.8		$	87.9		$	85.4	$	552.1
Impairment	—			(8.4		)	—		(8.4		)
Translation	(21.4		)	(7.6		)	—		(29.0		)
December 31, 2015	$	357.4		$	71.9		$	85.4	$	514.7

Refer to Note 4 to these consolidated financial statements for additional disclosure related to impairment of goodwill during the year ended December 31, 2015. We did not recognize any impairment for the years ended December 31, 2014 and 2013, as the fair values of our reporting units with goodwill balances exceeded their carrying amounts.

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



	December 31,
	2015				2014
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships	$	96.8	$	33.6	$	142.4	$	33.5
Patents and acquired technology	248.5		90.0		256.0		77.3
Trademarks	35.7		11.2		35.9		9.4
Other	5.2		5.1		5.9		5.5
Total intangible assets	$	386.2	$	139.9	$	440.2	$	125.7

An impairment charge of $33.3 million related to customer relationships intangible asset was recorded in our Surface Technologies segment during the year ended December 31, 2015. Refer to Note 4 to these consolidated financial statements for additional disclosure related to asset impairment charges. We did not have any material additions to our intangible assets during 2015 or 2014.

All of our acquired identifiable intangible assets are subject to amortization and, where applicable, foreign currency translation adjustments. We recorded $27.0 million, $25.9 million and $26.9 million in amortization expense related to intangible assets during the years ended December 31, 2015, 2014 and 2013, respectively. During the years 2016 through 2020, annual amortization expense is expected to be as follows: $25.0 million in 2016, $26.5 million in 2017, $24.1 million in 2018, $23.8 million in 2019, $23.7 million in 2020 and $123.2 million thereafter.

NOTE 10. DEBT

Credit facility—On September 24, 2015, we entered into a $2.0 billion revolving credit agreement (“credit agreement”) with Wells Fargo Bank, National Association, as Administrative Agent. The credit agreement is a five-year, revolving credit facility expiring in September 2020. Subject to certain conditions, at our request the aggregate commitments under the credit agreement may be increased by an additional $500.0 million.

In connection with the new credit agreement, we terminated our previously existing $1.5 billion five-year revolving credit agreement.

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 $1.5 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, 2015, had a weighted average interest rate of 0.89%.

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.

Foreign 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)	2015		2014
Term loan	$	15.6	$	—
Capital leases	0.4		3.8
Foreign uncommitted credit facilities	5.9		7.9
Total short-term debt and current portion of long-term debt	$	21.9	$	11.7

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



	December 31,
(In millions)	2015			2014
Revolving credit facility	$	—		$	—
Commercial paper ⁽¹⁾	337.2			469.1
2.00% Notes due 2017	299.1			298.6
3.45% Notes due 2022	497.5			497.2
Term loan	15.6			22.9
Capital leases	0.7			9.7
Total long-term debt	1,150.1			1,297.5
Less: current portion	(16.0		)	(3.8		)
Long-term debt, less current portion	$	1,134.1		$	1,293.7

_______________________

⁽¹⁾

At December 31, 2015 and 2014, 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, 2015 and 2014.

Maturities of total long-term debt as of December 31, 2015, are payable as follows:



	Payments Due by Period
(In millions)	Total payments		Less than 1 year		1-3 years		3-5 years		After 5 years
Long-term debt	$	1,150.1	$	16.0	$	636.6	$	—	$	497.5

NOTE 11. 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 12. 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 $131.2 million, $136.8 million and $149.7 million in 2015, 2014 and 2013, 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. In January 2016, construction of the facilities was completed and the operating lease commenced. Upon expiration of the operating lease 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, 2015, future minimum rental payments under noncancellable operating leases were:



(In millions)
2016	$	85.9
2017	69.6
2018	58.5
2019	43.9
2020	34.5
Thereafter	128.6
Total	421.0
Less income from subleases	5.9
Net minimum operating lease payments	$	415.1

Contingent liabilities associated with guarantees—In the ordinary course of business, we enter into standby letters of credit, performance bonds, surety bonds and other guarantees with financial institutions for the benefit of our customers, vendors and other parties. These financial instruments at December 31, 2015, represented $632.9 million of guarantees related to our future performance and $70.6 million of guarantees to secure a portion of our existing financial obligations. We expect to replace these financial instruments as they mature 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 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 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 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, 2015 and 2014, and that the ultimate resolution of such matters will not materially affect our consolidated financial position, results of operations, or cash flows.

NOTE 13. STOCKHOLDERS’ EQUITY

Capital stock—The following is a summary of our capital stock activity for the years ended December 31, 2015, 2014 and 2013:



(Number of shares in thousands)	Common Stock Issued	Common Stock Held in Employee Benefit Trust		Treasury Stock
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
Stock awards	—	—		(523	)
Treasury stock purchases	—	—		5,253
Net stock purchased for (sold from) employee benefit trust	—	(10	)	—
December 31, 2015	286,318	157		59,356

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.

In February 2015, the Board of Directors authorized an extension of our repurchase program by 15.0 million shares. As of December 31, 2015, the Board of Directors had authorized 90 million shares of common stock under our share repurchase program. We repurchased $190.4 million, $247.6 million and $116.3 million of common stock during 2015, 2014 and 2013, respectively, under the authorized repurchase program. As of December 31, 2015, approximately 17.8 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 2015, 2014 or 2013.

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, 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		)
Other comprehensive income (loss) before reclassifications, net of tax	(182.3		)	(64.9		)	(21.0		)	(268.2		)
Reclassification adjustment for net (gains) losses included in net income, net of tax	—			55.1			24.1			79.2
Other comprehensive income (loss), net of tax	(182.3		)	(9.8		)	3.1			(189.0		)
December 31, 2015	$	(494.2	)	$	(87.1	)	$	(291.4	)	$	(872.7	)

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



	Year Ended
(In millions)	December 31, 2015			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:	$	(122.8	)	$	(36.2	)	$	(11.7	)	Revenue
	53.9			34.2			14.8			Costs of sales
	(1.7		)	(0.2		)	—			Selling, general and administrative expense
	0.1			—			—			Research and development expense
	0.1			—			—			Interest expense
	(70.4		)	(2.2		)	3.1			Income before income taxes
	15.3			3.0			2.1			Provision for income taxes
	$	(55.1	)	$	0.8		$	5.2		Net income
Defined pension and other post-retirement benefits
Settlements	$	(1.9	)	$	(24.9	)	$	(5.1	)	^(a)
Amortization of actuarial loss	(31.2		)	(18.6		)	(31.7		)	^(a)
Amortization of prior service credit	(0.1		)	(0.3		)	0.5			^(a)
Amortization of transition asset	0.1			0.1			0.1			^(a)
	(33.1		)	(43.7		)	(36.2		)	Income before income taxes
	9.0			15.5			15.2			Provision for income taxes
	$	(24.1	)	$	(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 15 for additional details).

NOTE 14. INCOME TAXES

Components of income (loss) before income taxes—Domestic and foreign components of income (loss) before income taxes were as follows:



	Year Ended December 31,
(In millions)	2015			2014		2013
Domestic	$	(67.7	)	$	353.2	$	150.7
Foreign	568.6			707.7		563.3
Income before income taxes attributable to FMC Technologies, Inc.	$	500.9		$	1,060.9	$	714.0

Provision for income tax—The provision for income taxes consisted of:



	Year Ended December 31,
(In millions)	2015			2014			2013
Current:
Federal	$	15.9		$	139.6		$	77.8
State	(2.7		)	11.7			5.6
Foreign	82.5			227.8			149.6
Total current	95.7			379.1			233.0
Deferred:
Increase in the valuation allowance for deferred tax assets	27.7			34.1			0.5
Decrease of deferred tax liability for change in tax rates	(3.9		)	(2.3		)	(4.3		)
Other deferred tax (benefit) expense	(11.7		)	(49.9		)	(16.6		)
Total deferred	12.1			(18.1		)	(20.4		)
Provision for income taxes	$	107.8		$	361.0		$	212.6

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



	December 31,
(In millions)	2015			2014
Deferred tax assets attributable to:
Accrued expenses	$	55.0		$	58.0
Non-deductible interest	43.8			29.2
Foreign tax credit carryforwards	29.3			29.3
Accrued pension and other post-retirement benefits	88.8			91.8
Stock-based compensation	34.4			28.9
Net operating loss carryforwards	44.7			48.7
Inventories	43.0			31.7
Norwegian correction tax	—			50.4
Research and development credit	4.7			—
Foreign exchange	4.1			40.2
Deferred tax assets	347.8			408.2
Valuation allowance	(58.3		)	(38.9		)
Deferred tax assets, net of valuation allowance	289.5			369.3
Deferred tax liabilities attributable to:
Revenue in excess of billings on contracts accounted for under the percentage of completion method	87.8			105.2
U.S. tax on foreign subsidiaries’ undistributed earnings not indefinitely reinvested	0.2			52.5
Property, plant and equipment, goodwill and other assets	116.4			142.8
Deferred tax liabilities	204.4			300.5
Net deferred tax assets (liabilities)	$	85.1		$	68.8

At December 31, 2015 and 2014, the carrying amount of net deferred tax assets and the related valuation allowance included the impact of foreign currency translation adjustments.

Non-deductible interest. At December 31, 2015, deferred tax assets include tax benefits of $43.8 million related to certain intercompany interest costs which are not currently deductible, but which may be deductible in future periods. If not utilized, 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.

Foreign tax credit carryforwards. At December 31, 2015, deferred tax assets included U.S. foreign tax credit carryforwards of $29.3 million, which, if not utilized, will begin to expire in 2022. 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 $190.2 million, $186.6 million and $196.2 million, in 2015, 2014 and 2013, respectively.

Net operating loss carryforwards. At December 31, 2015, deferred tax assets included 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 2018. 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.

Unrecognized tax benefits—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, 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
Additions for tax positions related to prior years	7.3			1.3			8.6
Additions for tax positions related to current year	6.1			—			6.1
Reductions for tax positions due to settlements	(40.4		)	(7.8		)	(48.2		)
Balance at December 31, 2015	$	9.3		$	0.7		$	10.0

At December 31, 2015, 2014 and 2013, there were $9.3 million, $43.1 million and $41.7 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 $9.7 million, due to either the expiration of the statute of limitations in certain jurisdictions or the resolution of current income tax examinations, or both.

In 2015, IRS examinations of our U.S. federal income tax returns for our 2010 and 2011 tax years as well as protests filed with the IRS Appeals Office with respect to proposed adjustments related to our 2007 through 2009 tax years were resolved.

The following tax years and thereafter remain subject to examination: 2010 for Angola, 2006 for Norway, 2007 for Nigeria, 2010 for Brazil and 2012 for the United States.

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



	Year Ended December 31,
	2015		2014		2013
Statutory U.S. federal income tax rate	35	%	35	%	35	%
Net difference resulting from:
Foreign earnings subject to different tax rates:
Singapore	(8	)	(1	)	2
Malaysia	(4	)	(1	)	(3	)
Luxembourg	(4	)	(4	)	(6	)
Other	(7	)	(2	)	(6	)
Foreign earnings subject to U.S. tax	3		2		2
Non-deductible Multi Phase Meters earn-out adjustments	—		—		1
Settlement of foreign audits	—		—		1
Foreign withholding taxes	3		2		3
Change in valuation allowance	6		3		—
Other	(2	)	—		1
Effective income tax rate	22	%	34	%	30	%

Undistributed earnings of foreign subsidiaries. We have provided U.S. income taxes on $1,532.2 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 $1,948.5 million at December 31, 2015. The amount of applicable U.S. income taxes that would be incurred if these earnings were repatriated is approximately $717.2 million.

Income tax holidays. We benefit from income tax holidays in Singapore and Malaysia which will expire after 2018 for Singapore and 2017 and 2020 for Malaysia. For the years ended December 31, 2015 and 2014, these tax holidays reduced our provision for income taxes by $29.3 million, or $0.13 per share on a diluted basis, and $1.3 million, or $0.01 per share on a diluted basis, respectively.

NOTE 15. 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, substantially all settlement payments were made based on frozen participants’ elections and settlement costs were recorded during 2014.

Also on June 1, 2014, the U.S. Qualified Pension Plan was further amended to provide vested participants who had terminated employment prior to May 1, 2014 an option to commence their benefits immediately, either as an annuity or a single lump sum payment. In December 2014, lump sum payments were paid out of the Plan to these terminated vested participants.

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 balance sheets as of December 31, 2015 and 2014, were as follows:



	Pensions												Other Post-retirement Benefits
	2015						2014						2015			2014
(In millions)	U.S.			Int’l			U.S.			Int’l
Accumulated benefit obligation	$	539.3		$	364.5		$	552.4		$	406.3
Projected benefit obligation at January 1	$	640.6		$	482.5		$	585.0		$	438.8		$	10.4		$	6.7
Service cost	14.4			16.1			13.8			16.7			—			0.1
Interest cost	26.4			14.8			29.1			18.5			0.4			0.3
Actuarial (gain) loss	(35.6		)	(36.9		)	101.8			71.6			(1.2		)	4.0
Amendments	—			—			2.4			0.3			—			(0.1		)
Settlements	(4.9		)	(0.1		)	(63.8		)	—			—			—
Foreign currency exchange rate changes	—			(39.1		)	—			(53.6		)	—			—
Plan participants’ contributions	—			2.1			—			2.4			—			—
Benefits paid	(23.8		)	(11.5		)	(27.7		)	(12.2		)	(0.5		)	(0.6		)
Other	—			0.6			—			—			—			—
Projected benefit obligation at December 31	617.1			428.5			640.6			482.5			9.1			10.4
Fair value of plan assets at January 1	504.8			386.7			576.8			400.8			—			—
Actual return on plan assets	(20.3		)	(7.5		)	8.5			13.5			—			—
Company contributions	7.6			16.2			11.0			22.6			0.5			0.6
Foreign currency exchange rate changes	—			(30.0		)	—			(40.4		)	—			—
Settlements	(4.9		)	(0.1		)	(63.8		)	—			—			—
Plan participants’ contributions	—			2.1			—			2.4			—			—
Benefits paid	(23.8		)	(11.5		)	(27.7		)	(12.2		)	(0.5		)	(0.6		)
Fair value of plan assets at December 31	463.4			355.9			504.8			386.7			—			—
Funded status of the plans (liability) at December 31	$	(153.7	)	$	(72.6	)	$	(135.8	)	$	(95.8	)	$	(9.1	)	$	(10.4	)



	Pensions												Other Post-retirement Benefits
	2015						2014						2015			2014
(In millions)	U.S.			Int’l			U.S.			Int’l
Current portion of accrued pension and other post-retirement benefits	$	(3.8	)	$	(0.4	)	$	(4.1	)	$	(0.4	)	$	(0.7	)	$	(0.8	)
Accrued pension and other post-retirement benefits, net of current portion	(149.9		)	(72.2		)	(131.7		)	(95.4		)	(8.4		)	(9.6		)
Funded status recognized in the consolidated balance sheets at December 31	$	(153.7	)	$	(72.6	)	$	(135.8	)	$	(95.8	)	$	(9.1	)	$	(10.4	)

The following table summarizes the pre-tax amounts in accumulated other comprehensive (income) loss at December 31, 2015 and 2014 that have not been recognized as components of net periodic benefit cost:



	Pensions										Other Post-retirement Benefits
	2015					2014					2015			2014
(In millions)	U.S.		Int’l			U.S.		Int’l
Pre-tax amounts recognized in accumulated other comprehensive (income) loss:
Unrecognized actuarial (gain) loss	$	242.0	$	174.8		$	234.9	$	187.8		$	(0.2	)	$	1.1
Unrecognized prior service (credit) cost	0.1		1.2			0.2		1.3			—			(0.1		)
Unrecognized transition asset	—		(0.1		)	—		(0.2		)	—			—
Accumulated other comprehensive (income) loss at December 31	$	242.1	$	175.9		$	235.1	$	188.9		$	(0.2	)	$	1.0

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, 2015 and 2014:



	Pensions								Other Post-retirement Benefits
	2015				2014				2015		2014
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded projected benefit obligation:
Aggregate projected benefit obligation	$	617.1	$	428.5	$	640.6	$	482.5	$	9.1	$	10.4
Aggregate fair value of plan assets	$	463.4	$	355.9	$	504.8	$	386.7	$	—	$	—



	Pensions								Other Post-retirement Benefits
	2015				2014				2015	2014
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded accumulated benefit obligation:
Aggregate accumulated benefit obligation	$	539.3	$	117.7	$	552.4	$	145.0
Aggregate fair value of plan assets	$	463.4	$	90.4	$	504.8	$	103.1

The following table summarizes the components of net periodic benefit cost (income) for the years ended December 31, 2015, 2014 and 2013:



	Pensions																		Other Post-retirement Benefits
	2015						2014						2013						2015		2014			2013
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l
Components of net periodic benefit cost (income):
Service cost	$	14.4		$	16.1		$	13.8		$	16.7		$	16.5		$	14.7		$	—	$	0.1		$	0.1
Interest cost	26.4			14.8			29.1			18.5			25.8			16.1			0.4		0.3			0.2
Expected return on plan assets	(43.9		)	(27.9		)	(46.3		)	(30.0		)	(41.6		)	(23.7		)	—		—			—
Settlement cost	2.1			(0.1		)	22.5			—			5.1			—			—		—			—
Curtailment cost	—			—			2.4			—			—			—			—		—			—
Amortization of transition asset	—			(0.1		)	—			(0.1		)	—			(0.1		)	—		—			—
Amortization of prior service cost (credit)	—			0.1			(0.1		)	0.4			(0.1		)	0.1			—		—			(0.5		)
Amortization of net actuarial loss (gain)	19.4			11.7			12.2			6.7			26.6			5.3			0.1		(0.3		)	(0.2		)
Net periodic benefit cost (income)	$	18.4		$	14.6		$	33.6		$	12.2		$	32.3		$	12.4		$	0.5	$	0.1		$	(0.4	)

The following table summarizes changes in plan assets and benefit obligations recognized in other comprehensive income (loss) for the years ended December 31, 2015, 2014 and 2013:



	Pensions																		Other Post-retirement Benefits
	2015						2014						2013						2015		2014			2013
(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	$	(28.5	)	$	0.6		$	(139.6	)	$	(80.9	)	$	193.3		$	(15.6	)	$	1.2	$	(4.0	)	$	1.7
Prior service (cost) credit arising during period	—			—			(2.3		)	(0.3		)	—			(0.6		)	—		0.1			—
Settlements and curtailments	2.1			(0.1		)	24.9			—			5.1			—			—		—			—
Amortization of net actuarial loss (gain)	19.4			11.7			12.2			6.7			26.6			5.3			0.1		(0.3		)	(0.2		)
Amortization of prior service cost (credit)	—			0.1			(0.1		)	0.4			(0.1		)	0.1			—		—			(0.5		)
Amortization of transition asset	—			(0.1		)	—			(0.1		)	—			(0.1		)	—		—			—
Other	—			(0.6		)	—			—			—			—			—		—			—
Total recognized in other comprehensive income (loss)	$	(7.0	)	$	11.6		$	(104.9	)	$	(74.2	)	$	224.9		$	(10.9	)	$	1.3	$	(4.2	)	$	1.0

Included in accumulated other comprehensive income (loss) at December 31, 2015, 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)	$	15.5	$	10.2		$	(0.1	)
Prior service cost (credit)	$	0.1	$	0.1		$	—
Transition asset	$	—	$	(0.1	)	$	—

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



	Pensions								Other Post-retirement Benefits
	2015				2014				2015		2014
	U.S.		Int’l		U.S.		Int’l
Discount rate	4.70	%	3.39	%	4.20	%	3.21	%	4.70	%	4.20	%
Rate of compensation increase	4.00	%	3.71	%	4.00	%	3.84	%

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



	Pensions												Other Post-retirement Benefits
	2015				2014				2013				2015		2014		2013
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Discount rate	4.20	%	3.21	%	5.10	%	4.30	%	3.90	%	4.46	%	4.20	%	5.10	%	3.90	%
Rate of compensation increase	4.00	%	3.84	%	4.00	%	4.29	%	4.00	%	3.98	%
Expected rate of return on plan assets	9.00	%	7.48	%	9.00	%	7.61	%	9.00	%	7.44	%

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, 2015 and 2014.


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


•	Equity securities are comprised of common stock and preferred stock. The fair values of equity securities are valued at the closing price reported on the active market on which the securities are traded.


•	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. Registered investment companies primarily include investments in emerging market bonds. Common/collective trusts primarily includes money market instruments with short maturities.


•	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.


•	The fair values of hedge funds are valued using the NAV as determined by the administrator or custodian of the fund. The funds primarily invest in U.S. and international equities, debt securities and other hedge funds.


•	The fair values of limited partnerships are valued using the NAV as determined by the administrator or custodian of the fund. The partnerships primarily invest in U.S. and international equities and debt securities.


•	Real estate and other investments primarily consists of real estate investment trusts and other investments. These investments are measured at quoted market prices, which represent the NAV of the securities held in such funds at year end.

Our pension plan assets measured at fair value on a recurring basis are as follows at December 31, 2015 and 2014. Refer to “Fair value measurements” in Note 1 to these consolidated financial statements for a description of the levels.



	U.S.								International
December 31, 2015 (In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Cash and cash equivalents	$	29.7	$	29.7	$	—	$	—	$	1.2	$	1.2	$	—	$	—
Equity securities:
U.S. companies	150.0		150.0		—		—		44.5		44.5		—		—
International companies	30.8		30.8		—		—		221.8		221.8		—		—
Registered investment companies ⁽¹⁾	14.8								—
Common/collective trusts ⁽¹⁾	23.1								—
Insurance contracts	—		—		—		—		88.4		—		88.4		—
Hedge funds ⁽¹⁾	140.3								—
Limited partnerships ⁽¹⁾	68.3								—
Real estate and other investments	6.1		6.1		—		—		—		—		—		—
Total assets	$	463.1	$	216.6	$	—	$	—	$	355.9	$	267.5	$	88.4	$	—
December 31, 2014 (In millions)
Cash and cash equivalents	$	103.6	$	103.6	$	—	$	—	$	0.3	$	0.3	$	—	$	—
Equity securities:
U.S. companies	162.3		162.3		—		—		44.1		44.1		—		—
International companies	53.5		53.5		—		—		241.9		241.9		—		—
Registered investment companies ⁽¹⁾	4.8								—
Common/collective trusts ⁽¹⁾	49.3								—
Insurance contracts	—		—		—		—		100.4		—		100.4		—
Hedge funds ⁽¹⁾	65.3								—
Limited partnerships ⁽¹⁾	60.3								—
Real estate and other investments	6.5		6.5		—		—		—		—		—		—
Total assets	$	505.6	$	325.9	$	—	$	—	$	386.7	$	286.3	$	100.4	$	—

_______________________


⁽¹⁾	Certain investments that are measured at fair value using net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.

Contributions—We expect to contribute approximately $12.7 million to our international pension plans, representing primarily the U.K. and Norway qualified pension plans, and approximately $3.7 million to our U.S. Non-Qualified Defined Benefit Pension Plan in 2016. All of the contributions are expected to be in the form of cash. In 2015 and 2014, we contributed $24.3 million and $33.6 million to the pension plans, respectively.

Estimated future benefit payments—The following table summarizes expected benefit payments from our various pension and post-retirement benefit plans through 2025. Actual benefit payments may differ from expected benefit payments.



	Pensions				Other Post-retirement Benefits
(In millions)	U.S.		International
2016	$	26.9	$	11.1	$	0.7
2017	$	40.7	$	11.9	$	0.7
2018	$	27.4	$	13.3	$	0.7
2019	$	28.9	$	14.3	$	0.7
2020	$	30.5	$	15.4	$	0.7
2021-2025	$	180.0	$	94.8	$	3.4

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 December 31, 2015 and 2014, our liability for the Non-Qualified Plan was $29.0 million and $38.5 million, respectively, and was recorded in other non-current liabilities. We hedge the financial impact of changes in the participants’ hypothetical investments by purchasing the investments that the participants have chosen. With the exception of FMC Technologies stock, which is maintained at its cost basis, changes in the fair value of these investments are recognized as an offset to other income (expense), net. As of December 31, 2015 and 2014, we had investments for the Non-Qualified Plan totaling $24.4 million and $30.7 million, respectively, at fair market value and FMC Technologies stock held in trust of $7.0 million and $8.0 million, respectively, at its cost basis. Refer to Note 18 to these consolidated financial statements for fair value disclosure of the Non-Qualified Plan investments.

We recognized expense of $27.6 million, $28.4 million and $23.5 million, for matching contributions to these plans in 2015, 2014 and 2013, respectively. Additionally, we recognized expense of $17.7 million, $18.9 million and $16.2 million for nonelective contributions in 2015, 2014 and 2013, respectively.

NOTE 16. STOCK-BASED COMPENSATION

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, 2015, 4.0 million shares were reserved to satisfy existing awards and 19.0 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 is 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, 2015, outstanding awards to active and retired non-employee directors included 793 thousand stock units.

The compensation expense for awards under the plan is as follows:



	Year Ended December 31,
(In millions)	2015		2014		2013
Stock-based compensation expense	$	49.4	$	44.9	$	47.7
Income tax benefits related to stock-based compensation expense	$	16.8	$	14.5	$	16.2

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, 2015, the portion of stock-based compensation expense related to outstanding awards to be recognized in future periods is as follows:



	December 31, 2015
Stock-based compensation expense not yet recognized (in millions)	$	49.4
Weighted-average recognition period (in years)	1.7

Restricted stock units—A summary of the nonvested restricted stock units to employees as of December 31, 2015, and changes during the year is presented below:



(Shares in thousands)	Shares		Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2014	2,554		$	51.46
Granted	1,521		$	39.36
Vested	(574	)	$	50.94
Cancelled/forfeited	(226	)	$	47.07
Nonvested at December 31, 2015	3,275		$	46.11

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, 2015. Based on results for the performance period, the payout will be 338 thousand shares at the vesting date in January 2018. Compensation cost was measured for 2015 based on the actual outcome of the performance conditions.

For current-year market-based awards (“2015 Market-Based Awards”), actual payouts may vary from zero to 123 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, 2017. For prior year market-based awards (“2014 Market-Based Awards”), actual payouts may vary from zero to 86 thousand shares, contingent upon our performance relative to the same peer group of companies with respect to 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,
	2015		2014		2013
Weighted average grant date fair value of restricted stock units granted	$	39.36	$	51.20	$	53.01
Vest date fair value of restricted stock units vested (in millions)	$	25.5	$	39.1	$	51.5

On January 2, 2016, restricted stock units vested and approximately 0.7 million shares were issued to employees.

NOTE 17. DERIVATIVE FINANCIAL INSTRUMENTS

For purposes of mitigating the effect of changes in exchange rates, we hold derivative financial instruments to hedge the risks of certain identifiable and anticipated transactions and recorded assets and liabilities in our consolidated balance sheets. 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. Our policy is to hold derivatives only for the purpose of hedging risks associated with anticipated foreign currency purchases and sales created in the normal course of business 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. For derivative instruments not designated as hedging instruments, any change in the fair value of those instruments are reflected in earnings in the period such change occurs.

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 and recorded assets and liabilities in our consolidated balance sheets. At December 31, 2015, we held the following material net positions:



	Net Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Brazilian real	270.5		69.3
British pound	83.4		123.6
Canadian dollar	(195.8	)	(141.1	)
Euro	151.6		165.0
Malaysian ringgit	194.0		45.2
Norwegian krone	2,199.9		249.5
Singapore dollar	213.4		150.7
U.S. dollar	(889.7	)	(889.7	)

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 conduct business in internationally recognized and traded currencies. At December 31, 2015, our portfolio of these instruments included the following material net positions:



	Net Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Brazilian real	(84.3	)	(21.6	)
Euro	13.1		14.3
Norwegian krone	(131.5	)	(14.9	)
U.S. dollar	24.8		24.8

Fair value amounts for all outstanding derivative instruments have been determined using available market information and commonly accepted valuation methodologies. Refer to Note 18 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 are settled.

The following table presents the location and fair value amounts of derivative instruments reported in the consolidated balance sheets.



	December 31, 2015				December 31, 2014
(In millions)	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	$	345.6	$	526.2	$	172.1	$	207.1
Long-term – Derivative financial instruments	0.1		0.5		129.4		214.6
Total derivatives designated as hedging instruments	345.7		526.7		301.5		421.7
Derivatives not designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	26.3		28.7		25.5		23.1
Long-term – Derivative financial instruments	—		—		5.5		5.6
Total derivatives not designated as hedging instruments	26.3		28.7		31.0		28.7
Total derivatives	$	372.0	$	555.4	$	332.5	$	450.4

We recognized a loss of $11.9 million and gains of $0.9 million and $0.1 million on cash flow hedges for the years ended December 31, 2015, 2014 and 2013, 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 $87.1 million and $77.3 million at December 31, 2015 and 2014, respectively. We expect to transfer an approximate $66.9 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 second half of 2017.

The following tables present the location of gains (losses) on the consolidated statements of income related to derivative instruments designated as cash flow hedges.



	Gain (Loss) Recognized in OCI (Effective Portion)
	Year Ended December 31,
(In millions)	2015			2014			2013
Foreign exchange contracts	$	(83.5	)	$	(137.1	)	$	24.1



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)	2015			2014			2013
Foreign exchange contracts:
Revenue	$	(122.8	)	$	(36.2	)	$	(11.7	)
Cost of sales	53.9			34.2			14.8
Selling, general and administrative expense	(1.7		)	(0.2		)	—
Research and development expense	0.1			—			—
Interest expense	0.1			—			—
Total	$	(70.4	)	$	(2.2	)	$	3.1



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)	2015			2014			2013
Foreign exchange contracts:
Revenue	$	14.2		$	24.7		$	2.7
Cost of sales	(17.3		)	(24.9		)	(11.0		)
Total	$	(3.1	)	$	(0.2	)	$	(8.3	)

The following table presents the location of gains (losses) on the consolidated statements of income related to derivative instruments not designated as hedging instruments.



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)	2015			2014			2013
Foreign exchange contracts:
Revenue	$	(11.1	)	$	(4.0	)	$	0.6
Cost of sales	2.8			0.7			(0.2		)
Other income (expense), net ⁽¹⁾	43.4			35.4			(15.0		)
Total	$	35.1		$	32.1		$	(14.6	)

_______________________


⁽¹⁾	Other income (expense), net excludes asset and liability remeasurement gains and losses.

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, 2015 and 2014, we had no collateralized derivative contracts. The following tables present both gross information and net information of recognized derivative instruments:



	December 31, 2015							December 31, 2014
(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	$	372.0	$	(355.0	)	$	17.0	$	332.5	$	(321.5	)	$	11.0



	December 31, 2015							December 31, 2014
(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	$	555.4	$	(355.0	)	$	200.4	$	450.4	$	(321.5	)	$	128.9

NOTE 18. FAIR VALUE MEASUREMENTS

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



	December 31, 2015								December 31, 2014
(In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Assets
Investments:
Equity securities	$	18.4	$	18.4	$	—	$	—	$	22.5	$	22.5	$	—	$	—
Fixed income	4.9		4.9		—		—		7.1		7.1		—		—
Other investments	1.0		1.0		—		—		2.1		2.1		—		—
Money market fund	2.9		—		2.9		—		3.4		—		3.4		—
Stable value fund ⁽¹⁾	1.2								0.7
Derivative financial instruments:
Foreign exchange contracts	372.0		—		372.0		—		332.5		—		332.5		—
Total assets	$	400.4	$	24.3	$	374.9	$	—	$	368.3	$	31.7	$	335.9	$	—
Liabilities
Derivative financial instruments:
Foreign exchange contracts	555.4		—		555.4		—		450.4		—		450.4		—
Total liabilities	$	555.4	$	—	$	555.4	$	—	$	450.4	$	—	$	450.4	$	—

_______________________


⁽¹⁾	Certain investments that are measured at fair value using net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.

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. Refer to Note 15 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.

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 as of December 31, 2015 and 2014.

Refer to Note 17 to these consolidated financial statements for additional disclosure related to derivative financial instruments.

Assets measured at fair value on a non-recurring basis were as follows:

Fair value of long-lived, non-financial assets—Long-lived, non-financial assets are measured at fair value on a non-recurring basis for the purposes of calculating impairment. The fair value measurements of our long-lived, non-financial assets measured on a non-recurring basis are determined by estimating the amount and timing of net future cash flows, which are Level 3 unobservable inputs, and discounting them using a risk-adjusted rate of interest. Significant increases or decreases in actual cash flows may result in valuation changes. During the year ended December 31, 2015, we recorded asset impairment charges primarily related to our surface integrated services business in Canada. Refer to Note 4 for additional disclosure related to these asset impairments.

Other fair value disclosures:

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 $761.9 million and $779.5 million as of December 31, 2015 and 2014, 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, 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 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 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 19. WARRANTY OBLIGATIONS

Warranty cost and accrual information is as follows:



	December 31,
(In millions)	2015			2014
Balance at beginning of year	$	23.0		$	18.0
Expenses for new warranties	28.5			30.5
Adjustments to existing accruals	2.6			0.7
Claims paid	(27.1		)	(26.2		)
Balance at end of year	$	27.0		$	23.0

NOTE 20. 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. In addition to our strategic priorities, segment reporting is also based on differences in the products and services we provide.

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. FTO Services and Forsys Subsea are included in the results of operations and capital employed of the Subsea Technologies segment. Refer to Note 7 for additional information.

•

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 natural 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.

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.

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)	2015			2014			2013
Segment revenue
Subsea Technologies ⁽¹⁾	$	4,509.0		$	5,266.4		$	4,726.9
Surface Technologies	1,487.6			2,130.7			1,806.8
Energy Infrastructure	395.4			557.4			617.2
Other revenue ⁽²⁾and intercompany eliminations	(29.3		)	(11.9		)	(24.7		)
Total revenue	$	6,362.7		$	7,942.6		$	7,126.2
Income before income taxes:
Segment operating profit: ⁽⁶⁾
Subsea Technologies	$	630.2		$	748.2		$	548.2
Surface Technologies	60.6			393.0			257.2
Energy Infrastructure	3.2			52.5			74.3
Intercompany eliminations	0.2			(0.3		)	(0.1		)
Total segment operating profit	694.2			1,193.4			879.6
Corporate items:
Corporate expense ⁽³⁾	(60.2		)	(66.3		)	(46.3		)
Other revenue ⁽²⁾ and other expense, net ⁽⁴⁾	(100.8		)	(33.7		)	(85.6		)
Net interest expense	(32.3		)	(32.5		)	(33.7		)
Total corporate items	(193.3		)	(132.5		)	(165.6		)
Income before income taxes attributable to FMC Technologies, Inc. ⁽⁵⁾	$	500.9		$	1,060.9		$	714.0

______________________________


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


⁽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.


⁽⁶⁾	Includes restructuring and impairment expenses in 2015 and 2014. Refer to Note 4 for additional information.

Segment operating capital employed and segment assets



	December 31,
(In millions)	2015			2014
Segment operating capital employed ⁽¹⁾:
Subsea Technologies	$	2,025.7		$	2,175.2
Surface Technologies	911.9			1,183.6
Energy Infrastructure	281.5			313.9
Total segment operating capital employed	3,219.1			3,672.7
Segment liabilities included in total segment operating capital employed ⁽²⁾	1,806.1			2,402.3
Corporate ⁽³⁾	1,412.7			1,097.1
Total assets	$	6,437.9		$	7,172.1
Segment assets:
Subsea Technologies	$	3,512.3		$	4,066.1
Surface Technologies	1,131.9			1,587.8
Energy Infrastructure	396.7			442.3
Intercompany eliminations	(15.7		)	(21.2		)
Total segment assets	5,025.2			6,075.0
Corporate ⁽³⁾	1,412.7			1,097.1
Total assets	$	6,437.9		$	7,172.1

______________________________


⁽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)	2015		2014		2013
Revenue:
United States	$	1,721.5	$	2,245.3	$	1,940.4
Nigeria	622.1		627.0		335.0
Brazil	516.9		831.6		689.0
Norway	492.1		1,023.3		1,217.7
Angola	485.1		406.7		516.0
All other countries	2,525.0		2,808.7		2,428.1
Total revenue	$	6,362.7	$	7,942.6	$	7,126.2



	December 31,
(In millions)	2015		2014
Long-lived assets:
United States	$	501.6	$	490.5
Norway	242.4		250.8
Malaysia	118.5		112.6
Brazil	116.5		169.1
United Kingdom	93.9		147.0
All other countries	298.6		288.4
Total long-lived assets	$	1,371.5	$	1,458.4

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)	2015		2014		2013		2015		2014		2013		2015			2014			2013
Subsea Technologies	$	175.6	$	268.7	$	235.0	$	154.3	$	138.0	$	119.5	$	110.7		$	92.2		$	87.1
Surface Technologies	69.4		124.6		70.1		74.4		72.0		68.0		16.1			21.6			15.6
Energy Infrastructure	3.6		10.5		8.3		16.7		16.6		16.5		9.5			11.3			12.2
Corporate	2.2		0.6		0.7		6.2		5.9		5.8		—			—			—
Intercompany eliminations	—		—		—		—		—		—		(1.0		)	(1.4		)	(2.5		)
Total	$	250.8	$	404.4	$	314.1	$	251.6	$	232.5	$	209.8	$	135.3		$	123.7		$	112.4

NOTE 21. QUARTERLY INFORMATION (UNAUDITED)



	2015								2014
(In millions, except per share data)	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Revenue	$	1,427.3	$	1,545.0	$	1,695.2	$	1,695.2	$	2,156.2	$	1,976.7	$	1,985.3	$	1,824.4
Cost of sales	1,141.3		1,173.9		1,297.0		1,293.0		1,608.9		1,479.6		1,507.8		1,403.5
Net income⁽¹⁾	56.2		82.5		108.0		148.1		170.6		170.5		227.7		136.5
Net income attributable to FMC Technologies, Inc.⁽¹⁾	$	55.6	$	82.0	$	107.9	$	147.6	$	168.6	$	169.8	$	226.3	$	135.2
Basic earnings per share	$	0.24	$	0.36	$	0.46	$	0.63	$	0.72	$	0.72	$	0.96	$	0.57
Diluted earnings per share	$	0.24	$	0.35	$	0.46	$	0.63	$	0.72	$	0.72	$	0.95	$	0.57

______________________________


⁽¹⁾	In the second quarter of 2014, we completed the sale of Material Handling Products and recognized a gain on the sale. Refer to Note 5 for additional information.

NOTE 22. OTHER INFORMATION



	Year Ended December 31,
(In millions)	2015		2014		2013
Supplemental disclosures of cash flow information:
Cash paid for interest (net of interest capitalized)	$	31.0	$	31.6	$	27.1
Cash paid for income taxes (net of refunds received)	$	239.1	$	370.0	$	137.3



	December 31,
(In millions)	2015		2014
Other reportable information:
Unbilled receivables included in receivables	$	638.4	$	804.3
Trading securities included in investments	$	28.4	$	35.8
Net capitalized software costs included in other assets	$	60.1	$	57.3

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, 2015, 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, 2015, 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, 2015, 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 (Proposal 1)” of our Proxy Statement for the 2016 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 2016 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 2016 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 2016 Annual Meeting of Stockholders.

We have adopted a Code of Business Conduct (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—Leadership—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 2016 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 2016 Annual Meeting of Stockholders. Additionally, Equity Plan Compensation Information is incorporated herein by reference from 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 2016 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 “Ratification of the Appointment of KPMG LLP as Our Independent Registered Public Accounting Firm for 2016 (Proposal 2)” of our Proxy Statement for the 2016 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, 2015, 2014 and 2013

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014, and 2013

Consolidated Balance Sheets as of December 31, 2015 and 2014

Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013

Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013

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 millions)			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, 2013:
Allowance for doubtful accounts	$	6.1	$	3.0	$	0.2		$	1.9		$	7.4
Inventory valuation reserve	$	69.9	$	37.5	$	(0.3	)	$	21.1		$	86.0
Valuation allowance for deferred tax assets	$	4.3	$	1.7	$	—		$	1.3		$	4.7
Year Ended December 31, 2014:
Allowance for doubtful accounts	$	7.4	$	3.6	$	(0.6	)	$	1.0		$	9.4
Inventory valuation reserve	$	86.0	$	47.6	$	(8.7	)	$	28.1		$	96.8
Valuation allowance for deferred tax assets	$	4.7	$	39.9	$	—		$	5.7		$	38.9
Year Ended December 31, 2015:
Allowance for doubtful accounts	$	9.4	$	10.1	$	(0.5	)	$	(0.2	)	$	19.2
Inventory valuation reserve	$	96.8	$	94.1	$	(6.2	)	$	31.4		$	153.3
Valuation allowance for deferred tax assets	$	38.9	$	27.7	$	—		$	8.3		$	58.3

______________________________


^(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. MANNEN
		Maryann T. Mannen Executive Vice President and Chief Financial Officer

Date: February 24, 2016

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 24, 2016		/S/ JOHN T. GREMP
		John T. Gremp Chairman and Chief Executive Officer (Principal Executive Officer)

February 24, 2016		/S/ MARYANN T. MANNEN
		Maryann T. Mannen Executive Vice President and Chief Financial Officer (Principal Financial Officer)

February 24, 2016		/S/ JAY A. NUTT
		Jay A. Nutt Vice President, Controller and Treasurer (Principal Accounting Officer)

February 24, 2016		/s/ MIKE R. BOWLIN
		Mike R. Bowlin, Director

February 24, 2016		/S/ ELEAZAR DE CARVALHO FILHO
		Eleazar De Carvalho Filho, Director

February 24, 2016		/S/ CLARENCE P. CAZALOT, JR.
		Clarence P. Cazalot, Jr., Director

February 24, 2016		/S/ C. MAURY DEVINE
		C. Maury Devine, Director

February 24, 2016		/S/ CLAIRE S. FARLEY
		Claire S. Farley, Director

February 24, 2016		/S/ THOMAS M. HAMILTON
		Thomas M. Hamilton, Director

February 24, 2016		/S/ PETER MELLBYE
		Peter Mellbye, Director

February 24, 2016		/S/ JOSEPH H. NETHERLAND
		Joseph H. Netherland, Director

February 24, 2016		/S/ PETER OOSTERVEER
		Peter Oosterveer, Director

February 24, 2016		/S/ RICHARD A. PATTAROZZI
		Richard A. Pattarozzi, Director

February 24, 2016		/S/ KAY G. PRIESTLY
		Kay G. Priestly, Director

February 24, 2016		/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 October 5, 2015) (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 5, 2015) (File No. 001-16489).
10.3*		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).
10.4*		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).
10.5*		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).
10.6*		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).
10.7*		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).
10.8*		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).
10.8.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.
10.8.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).
10.8.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 (incorporated by reference from Exhibit 10.13.c to the Annual Report on Form 10-K filed on February 20, 2015) (File No. 001-16489).
10.8.d*		Fourth Amendment of Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part I Salaried and Nonunion Hourly Employees’ Retirement Plan, dated December 18, 2015.
10.9*		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).
10.9.a*		First Amendment of Amended and Restated FMC Technologies, Inc. Employees’ Retirement Program Part II Union Hourly Employees’ Retirement Plan, dated November 14, 2014 (incorporated by reference from Exhibit 10.14.a to the Annual Report on Form 10-K filed on February 20, 2015) (File No. 001-16489).
10.10*		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).
10.10.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).
10.10.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).
10.11*		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).
10.12*		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).
10.12.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).
10.12.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).
10.12.c*		Third Amendment to the Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated April 30, 2014.
10.12.d*		Fourth Amendment to the Amended and Restated FMC Technologies, Inc. Savings and Investment Plan, dated December 18, 2015.
10.13*		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).
10.14*		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).
10.14.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).
10.14.b*		Second Amendment to the FMC Technologies, Inc. Non-Qualified Savings and Investment Plan, dated December 18, 2015.
10.15*		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).
10.16		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).
10.17		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).
10.18		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).
10.19		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).
10.20		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).
10.21		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).
10.22		$2,000,000,000 Credit Agreement, dated as of September 24, 2015, by and among FMC Technologies, Inc., as Borrower; Wells Fargo Bank, National Association, as Administrative Agent; JPMorgan Chase Bank, N.A., as Syndication Agent; Bank of America, N.A., DNB Bank ASA, New York Branch, Mizuho Bank, Ltd. and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents; Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, DNB Markets, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizhuo Bank, Ltd., and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Joint Bookrunners and Co-Lead Arrangers; and the other lenders party thereto (incorporated by reference from Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on October 23, 2015) (File No. 001-16489).
10.23		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).
10.23.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).
10.24		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).
10.25		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

100