TechnipFMC plc - Annual Report: 2018 (Form 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, 2018



¨	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 001-37983

TechnipFMC plc

(Exact name of registrant as specified in its charter)



England and Wales	98-1283037
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

One St. Paul’s Churchyard London, United Kingdom	EC4M 8AP
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: +44 203-429-3950

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



Title of each class	Name of each exchange on which registered
Ordinary shares, $1.00 par value per share	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 every Interactive Data File required to be submitted 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 such files). YES ý NO ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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



Large accelerated filer	ý	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	o
		Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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 ordinary shares held by non-affiliates of the registrant, determined by multiplying the outstanding shares on June 29, 2018, by the closing price on such day of $31.74 as reported on the New York Stock Exchange, was $11,624,003,759.

The number of shares of the registrant’s ordinary shares outstanding as of March 4, 2019 was 450,129,380.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement relating to its 2019 Annual General Meeting of Shareholders are incorporated by reference into Part III of this Annual Report on Form 10-K where indicated. The 2019 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.

TABLE OF CONTENTS



	Page
PART I
Item 1. Business	4
Executive Officers of the Registrant	19
Item 1A. Risk Factors	21
Item 1B. Unresolved Staff Comments	33
Item 2. Properties	34
Item 3. Legal Proceedings	36
Item 4. Mine Safety Disclosures	36
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6. Selected Financial Data	39
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	62
Item 8. Financial Statements and Supplementary Data	64
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	130
Item 9A. Controls and Procedures	130
Item 9B. Other Information	134
PART III
Item 10. Directors, Executive Officers and Corporate Governance	135
Item 11. Executive Compensation	135
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	136
Item 13. Certain Relationships and Related Transactions, and Director Independence	136
Item 14. Principal Accounting Fees and Services	136
PART IV
Item 15. Exhibits, Financial Statement Schedules	137
Item 16. Form 10-K Summary	139
Signatures	141

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains “forward-looking statements” as defined in Section 27A of the United States Securities Act of 1933, as amended, and Section 21E of the United States Securities 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 actual results to differ materially from those contemplated in the forward-looking statements include those set forth in Part I, Item 1A, “Risk Factors” and elsewhere of this Annual Report on Form 10-K. We 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

TechnipFMC plc, a public limited company incorporated and organized under the laws of England and Wales, with registered number 09909709, and with registered office at One St. Paul’s Churchyard, London EC4M 8AP, United Kingdom (“TechnipFMC”, the “Company,” “we,” or “our”) is a global energy service company with a portfolio of solutions for the production and transformation of hydrocarbons. These solutions range from discreet products and services to fully integrated solutions based on proprietary technologies, with a clear focus to deliver greater efficiency across project lifecycles from concept to delivery and beyond.

We have operational headquarters in Paris, France and Houston, Texas, United States. We operate across three business segments: Subsea, Onshore/Offshore, and Surface Technologies. Through these segments, we are levered to the three energy growth areas of unconventionals, liquified natural gas (“LNG”), and deepwater developments.

We have a unique and comprehensive set of capabilities to serve the oil and gas industry. With our proprietary technologies and production systems, integration expertise, and comprehensive solutions, we are transforming our clients’ project economics.

Enhancement of the Company’s performance and competitiveness is a key component of this strategy that is achieved through technology and innovation differentiation, seamless execution, and reliance on simplification to drive costs down. We are targeting profitable and sustainable growth, seizing growing market opportunities, expanding the range of our services, and managing our assets efficiently to ensure that we are well-prepared to drive and benefit from the recovery we are experiencing in many of the segments we serve.

Each of our more than 37,000 employees is driven by a steadfast commitment to clients and a culture of purposeful innovation, challenging industry conventions, and finding new and better ways of working to unlock possibilities. This leads to fresh thinking, streamlined decisions, and smarter results, enabling us to achieve our vision of enhancing the performance of the world’s energy industry.

History

In March 2015, FMC Technologies, Inc., a U.S. Delaware corporation (“FMC Technologies”), and Technip S.A., a French société anonyme (“Technip”), signed an agreement to form an exclusive alliance and to launch Forsys Subsea, a 50/50 joint venture, that would unite the skills and capabilities of two subsea industry leaders. This alliance, which became operational on June 1, 2015, was established to identify new and innovative approaches to the design, delivery, and maintenance of subsea fields.

Forsys Subsea brought the industry's most talented subsea professionals together early in operators’ project concept phase with the technical capabilities to design and integrate products, systems and installation to significantly reduce the cost of subsea field development and enhance overall project economics.

Based on the success of the Forsys joint venture and its innovative approach to integrate solutions, Technip and FMC Technologies announced in May 2016 that the companies would combine through a merger of equals to create a global leader, TechnipFMC, that would drive change by redefining the production and transformation of oil and gas. The business combination was completed on January 16, 2017 (the “Merger”), and on January 17, 2017, TechnipFMC began operating as a unified, combined company trading on the New York Stock Exchange (“NYSE”) and on the Euronext Paris Stock Exchange (“Euronext Paris”) under the symbol “FTI.”

In 2017, our first year as a merged company, TechnipFMC secured several project awards as many operators moved forward with final investment decisions for major onshore projects and subsea developments. Several of the subsea awards incorporated the use of our integrated approach to project delivery, validating our unique business model aimed at lowering project costs and accelerating the delivery of initial hydrocarbon production. This approach was made possible by bringing together the complimentary work scopes of the merged companies. With the industry’s most comprehensive and only truly integrated market offering, we have continued to expand the deepwater opportunity set for our customers. TechnipFMC’s expertise does not end with the production of hydrocarbons. Because of its best in class project design and execution capabilities, enabled by a portfolio of proprietary technologies, TechnipFMC continues to secure and deliver projects that further enable our clients to monetize resources - from liquefaction of gas, both onshore and on floating vessels, through refining and product facilities.

The Company continues to innovate and introduce new technologies across our portfolio of products and services. TechnipFMC also delivered strong financial performance in 2018, driven by a relentless focus on operational execution and cost reduction activities.

BUSINESS SEGMENTS

Subsea

The Subsea segment provides integrated design, engineering, procurement, manufacturing, fabrication and installation, and life of field services for subsea systems, subsea field infrastructure, and subsea pipe systems used in oil and gas production and transportation.

We are an industry leader in front-end engineering and design (“FEED”), subsea production systems (“SPS”), flexible pipe, and subsea umbilicals, risers, and flowlines (“SURF”). We also have the capability to install these products and related subsea infrastructure with our fleet of highly specialized vessels. By driving even greater value through integrating the SPS and SURF work scopes and more efficiently execute the installation campaign, our strong commercial focus has enabled the successful market introduction of an integrated subsea business model, iEPCI™ (“iEPCI”), which spans a project’s early phase design the life of field. Our integrated model business model is unlocking incremental opportunities and materially expanding the deepwater opportunity set.

Through integrated FEED studies, or iFEED™ (“iFEED”), we are uniquely positioned to influence project concept and design. Using innovative solutions for field architecture, including standardized equipment, new technologies, and simplified installation, we can significantly reduce subsea development costs and accelerate time to first production.

Our first-mover advantage and ability to convert iFEED studies into iEPCI contracts, often as a direct award, creates a unique set of opportunities for the Company that are not available to our peers. This allows us to deliver a fully integrated - and technologically differentiated - subsea system, and to better manage the complete work scope through a single contracting mechanism and single interface, yielding great improvements in project economics and time to first oil.

Our Subsea business depends on our ability to maintain a cost-effective and efficient production system, achieve planned equipment production targets, successfully develop new products, and meet or exceed stringent performance and reliability standards.

Principal Products and Services

Subsea Production 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.

Our subsea production systems and products include subsea trees, chokes and flow modules, manifold pipeline systems, control and data management systems, well access systems, multiphase and wetgas meters, and additional technologies. 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 of deepwater environments, as well as internal pressures of up to 20,000 pounds per square inch (“psi”) and temperatures of up to 400º 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 processing systems, which include subsea boosting, subsea gas compression, and subsea separation, are designed to accelerate production, increase recovery, extend field life, and/or lower operators’ production costs. To provide these products, systems and services, we utilize our engineering, project management, procurement, manufacturing, and assembly and test capabilities.

Flexible Pipe and Umbilical Supply. We perform the engineering and manufacturing of flexible pipes, relying on our engineering centers, and the thermoplastic, steel tube, hybrid (a combination of steel tube, thermoplastic hose, and electrical cables), and power cable umbilical manufacturing units across various regions. In other markets, TechnipFMC vessels will typically perform the installation of the flexible pipes and umbilicals but we will also provide these products to other vessels.

We use our engineering and technical expertise to respond to tenders from a variety of clients including oil companies, engineering, procurement, construction, and installation services (“EPCI”) contractors and other subsea production system manufacturers, often as part of a broader scope.

Vessels. We operate a fleet of 18 vessels, with one additional vessel under construction. Of the 18 vessels currently in operation, we have sole ownership of eight vessels, ownership of seven vessels as part of joint ventures and operate three vessels under long-term charter.

We wholly own five pipelay support vessels and jointly own eight subsea construction vessels, including one under construction. The jointly-owned vessels operate under a 50/50 ownership structure exclusively in the Brazilian market. These vessels are primarily contracted to Petróleo Brasileiro S.A. - Petrobras (“Petrobras”), principally to install umbilical and flexible flowlines and risers to connect subsea wells to floating production units across a range of water depths. We also own one subsea construction and pipelay vessel mostly dedicated to the Asia Pacific market and have long-term charter agreements for three further construction vessels. The Company also owns two dive support vessels.

Subsea Services. We provide an array of subsea services to improve uptime, lower lifecycle costs and increase recovery over the life of the field for our clients’ subsea production systems. These services include: (i) provision of exploration and production well head systems; (ii) installation and well completion; (iii) asset management services for test, maintenance, refurbishment, and upgrade of subsea equipment and tooling; (iv) field performance services based on product data and field data to optimize the performance of the subsea production system; (v) inspection, maintenance, and repair (“IMR”) of subsea infrastructure; (vi) well access and intervention services, both rig-based and vessel-based (riserless light well intervention or “RLWI”), to enhance well production; (vii) remotely operated vehicle (“ROV”) services; and (viii) well plug and abandonment and decommissioning.

Key drivers of subsea services market activity are the inspection and maintenance of subsea infrastructure, driven in large part by aging infrastructure on mature fields. The need for well intervention services also continues to grow, with more than 6,000 wells operated globally, of which 33% are older than 10 years and 65% are older than five years.

With our extensive experience in subsea equipment, our large installed base of subsea production equipment, our broad range of services, and our historical technical leadership, we are in a unique position to offer integrated solutions through “life of field” services combining asset light solutions (e.g., RLWI), digital services (e.g., Condition Performance Monitoring / Flow Manager suite of applications), and leading edge automated systems (e.g., Schilling ROVs, In-service Riser Inspection System or “IRIS”) to enhance the economics of producing fields through maximization of asset uptime, higher production volumes and lower operating expense.

Robotics, Controls and Automation. We design and manufacture ROVs and manipulator arms that are used in subsea drilling, construction, IMR, and life of field services. Our product offering includes electric and hydraulic work-class ROVs, tether-management systems, launch and recovery systems, remote manipulator arms, and modular control systems . We also provide support and services such as product training, pilot simulator training, spare parts, and technical assistance.

We also provide electro-hydraulic and electric production and intervention control systems, allowing accurate control and monitoring of subsea installations to ensure the highest production availability while providing safe and environmentally friendly field operations. These include the sensors, multiphase flow meters, digital infrastructure, integrity monitoring, control functionality, and automation features needed for subsea systems. Robotics capabilities are now being used in the control of manifold valves during production. This is a convergence of our technologies in order to provide better systems for our customers.

Engineering, Manufacturing and Supply Chain (“EMS”) is a new organization we formed in November 2017 to help achieve productivity improvements by reducing the cost of engineering and manufacturing our products, including working with our suppliers to reduce their costs, and optimizing our processes and how we manage workflow. Through EMS, we are focused on implementing world-class manufacturing practices, including lean flow and automation, to improve reliability while reducing total product cost and lead time to delivery. Our EMS organization primarily supports our subsea segment but is also integrated across our business.

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 to fund initial development and working capital requirements. However, our working capital balances can vary significantly depending on the payment terms and execution timing on 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 companies that are engaged in the subsea development of oil and natural gas to promote our integrated systems for subsea production. These alliances are typically related to the procurement of subsea production equipment, although some alliances are related to EPCI services. Development of subsea fields, particularly in deepwater environments, involves substantial capital investments. Operators have also 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 these 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.

No single Subsea customer accounted for 10% or more of our 2018 consolidated revenue.

Competition

As a result of the Merger, we are the only company that can provide the full suite of subsea production equipment, umbilicals, and flowlines, as well as the installation services to develop a subsea production field. Our company competes with companies that supply some of the components as well as installation companies. Our competitors include Aker Solutions ASA, Baker Hughes, a GE Company (“BHGE”), Dril-Quip, Inc., McDermott International, Inc. (“McDermott”), National Oilwell Varco, Oceaneering International, Inc., Saipem S.p.A. (“Saipem”), Schlumberger, Ltd. (“Schlumberger”), and Subsea 7 S.A.

Seasonality

In the North Sea, winter weather generally subdues drilling activity, reducing vessel utilization and demand for subsea services as certain activities cannot be performed. As a result, the level of offshore activity in our Subsea segment is negatively impacted in the first quarter of each year.

Market Environment

The low crude oil price environment over the last three years led many of our customers to reduce their capital spending plans or defer new deepwater projects. The reduction and deferral of projects has resulted in delayed subsea project inbound for the industry. In response to the lower commodity prices and reduced cash flow, operators took actions needed to improve their subsea project economics, and suppliers, in turn, took the steps necessary to further reduce project break-even levels by offering cost-effective approaches for project developments. These actions continue.

The rate of project sanctioning for new subsea developments has moved higher since the market trough as project economics and operator confidence have improved. The risk of project sanctioning delays is still present in the current environment; however, innovative approaches to subsea projects, like our iEPCI solution, have improved project economics, and many offshore discoveries can be developed economically at today’s crude oil prices. In the long-term, deepwater development is expected to remain a significant part of many of our customers’ portfolios.

Strategy

With our proprietary technologies and production systems, integration expertise, and comprehensive solutions, we are transforming our clients’ project economics. We have used these capabilities to develop a new subsea commercial model that is transforming the way we interact with our customers and create value with them.

Our strategy includes the following priorities:


•	Engagement in the conceptual design and integrated front-end engineering, or iFEED, of subsea development projects to create value through technology and integration of scopes (iEPCI) by simplifying field architecture and accelerating both delivery schedules and time to first production;


•	Innovative research and development (“R&D”), often in collaboration with clients and partners, to develop leading products and technologies that deliver greater efficiency to the client, lower development costs, and enable frontier developments;


•	Superior project execution capabilities allowing the Company to mobilize the right teams, assets, and facilities to capture and profitably execute complex subsea projects and services;


•	Capitalize on combined competencies coming from alliances and partnerships with both clients and suppliers; and


•	Leverage supplier relationships to optimize supply chain market dynamics and implement greater simplification and standardization in products and processes.

Recent and Future Developments

With many of our customers reducing their capital spending plans or deferring new deepwater projects in response to the low crude oil price environment, we have adjusted our workforce and manufacturing capacity to align our operations with our anticipated outlook for project inbound. These restructuring actions have resulted in a leaner cost structure. The operational improvements and cost reductions made in 2016, combined with additional actions taken in 2017 and 2018, will partially offset the anticipated decline in operating margins in 2019.

A completely new suite of products called Subsea 2.0™ (“Subsea 2.0”), commercialized in November 2017, is gaining traction, and the first components are already in the water. Relative to traditional subsea equipment, the Subsea 2.0 technology portfolio significantly reduces the size, weight, and part count of the equipment installed on the seabed. Subsea 2.0 technologies can enhance project economics both as a stand-alone offering and as part of an integrated solution, further unlocking oil and gas reserves that otherwise would not be developed.

We believe that 2016 marked the inflection in subsea order activity as demonstrated by the increased number of final investment decisions made on offshore project developments. The Company’s full-year Subsea inbound orders increased significantly in 2017 and remained at this improved level in 2018, with integrated project awards taking greater share of our order activity. Our integrated business model is clearly demonstrating the ability to positively impact project economics and expand the deepwater opportunity set.

In the fourth quarter of 2018, the Company performed impairment assessments and determined that goodwill and certain of our vessels had carrying values that exceeded their fair value, resulting in an impairment. Refer to Note 12 and Note 17 to our consolidated financial statements included in Part II, Item 8 of the Annual Report on Form 10-K for additional information on these impairments.

In 2019, we expect to see another increase in subsea market activity. We also anticipate a further increase in our inbound orders, where we expect our iEPCI capabilities to provide a competitive advantage as we deliver comprehensive and differentiated solutions. In addition, we anticipate the following longer-term trends in the subsea market:


•	Increased market adoption of integrated subsea projects, leading to further penetration of our integrated business model and higher levels of iEPCI order activity for our Company;


•	Growing service opportunities, driven by (i) higher levels of project activity, (ii) increased asset integrity and production management activities focused on improving uptime and production volume, and (iii) increased maintenance and intervention activity resulting from an expanding and aging installed equipment base;

•

Smaller projects and direct awards will continue to contribute meaningfully to our order mix. In 2017 and 2018, these awards collectively represented just under one-half of total subsea inbound orders, with the remainder being publicly announced projects and subsea service activities. Subsea tiebacks are often part of this mix, and these shorter cycle brownfield expansions provide operators with faster paybacks and higher returns;


•	Capital expenditures for new greenfield projects will be sanctioned and average project size will increase as the subsea market recovery develops;


•	There is a growing trend towards independent operators and new entrants undertaking subsea developments; we are a natural partner for this customer group because of our ability to offer fully integrated solutions; and


•	Natural gas developments are growing in prominence. We believe that more than half of offshore capital expenditures could be directed at natural gas developments by early next decade.

We continue to work closely with our customers and believe that, in the context of lower oil prices, with our unique business model we can further reduce their project break-even levels by offering cost-effective approaches to their project developments and accelerate time to first oil and gas.

Product Development

We continue to expand our Subsea portfolio of technology-based solutions to deliver a complete production system for high pressure and high temperature 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. This joint development agreement is delivering standardized design, materials, processes, and interfaces to provide improved reliability and operations over the life of the field.

Technology development progressed on the Subsea 2.0 product platform, the next generation of subsea equipment, using designs that are significantly simpler, leaner, and smarter than current designs. These new products incorporate a modular product architecture and component level standardization to enable a flexible configure-to-order approach that delivers a 70-90% reduction in manual activities during the production process, reducing hardware delivery time for clients. The products are expected to deliver breakthroughs in the way subsea products are manufactured, assembled, installed, and maintained over the life of the field. The smaller, lighter products achieve up to a 50% reduction in size, weight, and part count, while maintaining the same or improved functionality. When combined with iEPCI, our powerful integrated approach to field architecture, and project execution, Subsea 2.0 improves project economics and unlocks first oil and gas faster.

Several major elements of the portfolio were launched to the market during the year, including the compact tree, compact manifold, flexible jumpers, distribution, controls, and horizontal connectors. We have incorporated Subsea 2.0 elements into several projects including the Shell Kaikias subsea development, which sits in 4,575 feet of water in the Gulf of Mexico and is a tieback to the Ursa platform. On March 4, 2018, TechnipFMC and Shell celebrated the successful delivery and installation of the first application of TechnipFMC’s compact pipeline and manifold (“PLEM”) and horizontal connection system technologies with flexible jumpers. We also completed the development of our second generation of electrically trace heated pipe-in-pipe (“ETH-PiP”), which delivers significant advancements in power output and length-enabling hydrate prevention in longer distance tiebacks of 50 kilometers or more.

In addition to investments to develop lower cost production solutions, we also invest in the development of technology to expand our service portfolio. During the year, we qualified new technology to enable the inspection of flexible risers and flowlines. We also are advancing subsea robotic productivity through the development of more efficient ROV systems that are easier to operate and maintain.

Acquisitions and Investments

In February 2018, we signed an agreement with the Island Offshore Group to acquire a 51% stake in Island Offshore’s wholly-owned subsidiary, Island Offshore Subsea AS. Island Offshore Subsea AS provides RLWI project management and engineering services for plug and abandonment (“P&A”), riserless coiled tubing, and well completion operations. In connection with the acquisition of the controlling interest, TechnipFMC and Island Offshore entered into a strategic cooperation agreement to deliver RLWI services on a worldwide basis, which also include TechnipFMC’s RLWI capabilities. Island Offshore Subsea AS has been rebranded to TIOS and is now the operating unit for TechnipFMC’s RLWI activities worldwide.

In March 2018, we announced a collaboration agreement with Magma Global Ltd. to develop a new generation of hybrid flexible pipe (“HFP”) for use in offshore applications. HFP is expected to provide increased strength and fatigue performance, while also achieving dramatic weight and cost reductions, for subsea fluid transport applications. As part of the collaboration, TechnipFMC purchased a minority stake in Magma Global.

Onshore/Offshore

The Onshore/Offshore segment offers a full range of designing and project development services to our customers spanning the entire downstream value chain, including technical consulting, concept selection, and final acceptance test. We have been successful in meeting our clients’ needs given our proven skills in managing large engineering, procurement, and construction (“EPC”) projects.

Our Onshore business combines the study, engineering, procurement, construction, and project management of the entire range of onshore facilities related to the production, treatment, and transportation of oil and gas, as well as the transformation of petrochemicals such as ethylene, polymers, and fertilizers, as well as other activities.

We conduct large-scale, complex, and challenging projects that involve extreme climatic conditions and non-conventional resources and are subject to increasing environmental and regulatory performance standards. We rely on technological know-how for process design and engineering, either through the integration of technologies from leading alliance partners or through our own technologies. We seek to integrate and develop advanced technologies and reinforce our project execution capabilities in each of our Onshore activities.

Our Offshore business combines the study, engineering, procurement, construction, and project management within the entire range of fixed and floating offshore oil and gas facilities, many of which were the first of their kind, including the development of floating liquefied natural gas (“FLNG”) facilities.

Principal Products and Services

Onshore Field Development - We design and build different types of facilities for the development of onshore oil and gas, processing facilities, and product export systems. In addition, we also renovate existing facilities by modernizing production equipment and control systems, in accordance with applicable environmental standards.

Refining - We are a leader in the design and construction of oil refineries. We manage many aspects of these projects, including the preparation of concept and feasibility studies, and the design, construction, and start-up of complex refineries or single refinery units. We have been involved in the design and construction of 30 new refineries, and are one of the few contractors in the world to have built six new refineries since 2000. We have extensive experience with technologies related to refining and have completed more than 850 individual process units, from 100 major expansion or refurbishment projects implemented in more than 75 countries. As a result of our cooperation with the most highly renowned technology licensors and catalyst suppliers and our strong technological expertise and refinery consulting services, we are able to provide an independent selection of appropriate technologies to meet specific project and client targets. These technologies result in direct benefits to the client, such as emission control and environmental protection, including hydrogen and carbon dioxide management, sulfur recovery units, water treatment, and zero flaring. With a strong record of accomplishment in refinery optimization projects, we have experience and competence in relevant technological fields in the oil refining sector.

Natural Gas Treatment and Liquefaction - We offer a complete range of services across the gas value chain to support our clients’ capital projects from concept to delivery. Our capabilities include the design and construction of facilities for LNG, gas-to-liquids (“GTL”), natural gas liquids (“NGL”) recovery, and gas treatment.

In the field of LNG, we pioneered base-load LNG plant construction through the first-ever facility in Arzew, Algeria. Working with our partners, we have constructed facilities that can deliver more than 90 million metric tons per annum (“Mtpa”), representing over 20% of the global liquefaction capacity in operation today. TechnipFMC brings knowledge and conceptual design capabilities that are unique among engineering and construction companies involved in LNG. We have engineered and delivered a broad range of LNG plants, including mid-scale and very large-scale plants, both onshore and offshore, and plants in remote locations. We have experience in the complete range of services for LNG receiving terminals from conceptual design studies to EPC. Reference projects include LNG trains in Qatar (the six largest ever constructed), Yemen, and a series of mid-scale LNG plants in China, and together with our joint venture partners, we are currently delivering the Yamal LNG plant (“Yamal”) in the Russian Arctic with the 3 trains put in production before the end of 2018.

We are also well positioned in the GTL market and are one of the few contractors with experience in large GTL facilities. We have unique experience in delivering plants using Sasol’s “Slurry Phase Distillate” technology, and we have provided front-end engineering design for the Fischer-Tropsch section of more than 60% of commercial coal-to-liquids and GTL capacity worldwide. Our clients also benefit from our development of environmental protection measures, including low nitrogen oxide and sulfur oxide emissions, waste-water treatment, and waste management.

We specialize in the design and construction of large-scale gas treatment complexes as well as existing facility upgrades. Gas treatment includes the removal of carbon dioxide and sulfur components from natural gas using chemical or physical solvents, sulfur recovery, and gas sweetening processes based on the use of an amine solvent. The Company ranks among the top contractors in the field in relation to sulfur recovery units installed in refineries or natural gas processing plants. Given our long-term experience in the field of sour gas processing, we can provide support to clients for the overall evaluation of the gas sweetening/sulfur recovery chain and the selection of optimum technologies.

Ethylene - We hold proprietary technologies and are a leader in the design, construction, and commissioning of ethylene production plants. We design steam crackers, from concept stage through construction and commissioning, for both new plants (including mega-crackers) and plant expansions. We have a portfolio of the latest generation of commercially proven technologies and are uniquely positioned to be both a licensor and an EPC contractor. Our technological developments have improved the energy efficiency in ethylene plants by improving thermal efficiency of the furnaces and reducing the compression power required per ton, reducing carbon dioxide emissions per ton of ethylene by 30% over the last 25 years.

Petrochemicals and Fertilizers - We are one of the world leaders in the process design, licensing, and realization of petrochemical units, including basic chemicals, intermediate and derivative plants. We provide a range of services that includes process technology licensing and development and full EPC complexes. We license a portfolio of chemical technologies through long-standing alliances and relationships with leading manufacturing companies and technology providers. We have research centers to develop and test technologies for polymer and petrochemical applications, where fully automated pilot plants gather design data to scale-up processes for commercialization

Hydrogen - Hydrogen is the most widely used industrial gas in the refining, chemical, and petrochemical industries, and is also widely used in the production of cleaner transport fuels. We offer a single point of responsibility for the design and construction of hydrogen and synthesis gas production units, with solutions ranging from Process Design Packages to full lump-sum turnkey projects. We also offer services for maintenance and performance optimization of running units. We have solutions in place for carbon capture readiness in future hydrogen plants, targeting more than a two-thirds reduction in carbon dioxide release from the hydrogen plant.

Fixed Platforms - We offer a broad range of fixed platform solutions in shallow water, including: (i) large conventional platforms with pile steel jackets whose topsides are installed offshore either by heavy lift vessel or floatover; (ii) small, conventional platforms installed by small crane vessel; (iii) steel gravity-based structure platforms, generally with floatover topsides; and (iv) small to large self-installing platforms.

Floating Production Units - We offer a broad range of floating platform solutions for moderate to ultra-deepwater applications, including:


•	Spar Platforms: Capable of operating in a wide range of water depths, the Spar is a low motion floater that can support full drilling with dry trees or with tender assist and flexible or steel catenary risers. The Spar topside is installed offshore either by heavy lift vessel or floatover.


•	Semi-Submersible Platforms: These platforms are well-suited to oil field developments where subsea wells drilled by the mobile offshore drilling unit are appropriate. Semi-Submersibles can operate in a wide range of water depths and have full drilling and large topside capability. We have our own unique design of low-motion Semi-Submersible platforms that can accommodate dry trees.


•	Tension-Leg Platforms (“TLP”): An appropriate platform for deepwater drilling and production in water depths up to approximately 1,500 meters, the TLP can be configured with full drilling or with tender assist and is generally a dry tree unit. The TLP and our topside can be integrated onto the substructure at a cost-effective manner at quayside.

Floating Production, Storage and Offloading (“FPSO”) - Working with our construction partners, we have delivered some of the largest FPSOs in the world. FPSOs enable offshore production and storage of oil which is then transported by a tanker where pipeline export is uneconomic or technically challenged (for example, ultra-deepwater). FPSOs utilize onshore processes adapted to a floating marine environment. They can support large topsides and hence large production capacities. Leveraging our industry-leading capabilities in gas monetization, particularly FLNG, we are currently well-positioned to leverage the global offshore gas cycle with gas FPSO.

Floating Liquefied Natural Gas (“FLNG”) - FLNG is an innovative alternative to traditional onshore LNG plants and is suitable for remote and stranded gas fields that were previously deemed uneconomical. FLNG is a commercially attractive and environmentally friendly approach to the monetization of offshore gas fields. It avoids the potential environmental impact of building and operating long-distance pipelines and extensive onshore infrastructure. We pioneered the FLNG industry and are the only contractor to integrate all of the core activities required to deliver an FLNG project: LNG process, offshore facilities, loading systems, and subsea infrastructure. We delivered the industry’s first and largest FLNG facilities and are currently executing two FLNG projects, Shell Prelude and ENI Coral South, with the latter being the inaugural LNG facility in Africa.

Capital Intensity

Our Onshore/Offshore business executes turnkey contracts on a lump-sum or reimbursable basis through engineering, procurement, construction, and project management services on both brownfield and greenfield developments and projects. We can execute EPC contracts through sole responsibility, joint ventures, or consortiums with other companies. We often receive advance payments and progress billings from our customers to fund initial development and working capital requirements. However, our working capital balances can vary significantly through the project lifecycle depending on the payment terms and timing on contracts.

Dependence on Key Customers

Generally, our Onshore/Offshore customers are major integrated oil companies or national oil companies. We have developed privileged relationships with our main clients around our portfolio of technologies, expertise in project management, and execution. Our customers have sought the security of alliances with us to ensure timely and cost-effective delivery of their projects.

One customer, JSC Yamal LNG, represented more than 10% of 2018 consolidated revenue. We consolidate all revenue from the JSC Yamal LNG partnership, including revenue associated with the minority partners of the joint venture.

Competition

In the Onshore market, we face a large number of competitors, including U.S. companies (Bechtel Corporation, Fluor Corporation, Jacobs Engineering Group Inc., KBR, Inc. (“KBR”), and McDermott), Japanese companies (Chiyoda Corporation, JGC Corporation, and Toyo Engineering Corporation), European companies (Maire Tecnimont Group, Petrofac, Ltd., Saipem, Tecnicas Reunidas, S.A., and John Wood Group plc), and Korean companies (Daelim Industrial Co., Ltd., GS Caltex Corporation, Hyundai Oilbank, Samsung Engineering Co., Ltd., and SK Energy Co., Ltd.). In addition, we compete against smaller, specialized, and locally-based engineering and construction companies in certain countries or for specific units such as petrochemicals.

Competition in the Offshore market is relatively fragmented and includes various players with different core capabilities, including offshore construction contractors, shipyards, leasing contractors, and local yards in Asia Pacific, the Middle East, and Africa. Competitors include Daewoo Shipbuilding & Marine Engineering Co., Ltd., Hyundai Heavy Industries Co., Ltd., Samsung Heavy Industries Co., Ltd., Saipem, KBR, McDermott, China Offshore Oil Engineering Co., Ltd., and JGC Corporation.

Seasonality

Our Onshore business is generally not impacted by seasonality. Our Offshore business could be impacted by seasonality in the North Sea region during the offshore installation campaign at the end of a project.

Market Environment

The Onshore market is impacted by changes in oil and gas prices, but is typically more resilient than offshore markets. Indeed, some downstream markets have benefited from low commodity prices where market fundamentals are influenced by other economic factors (e.g., petrochemicals and fertilizers that are linked to world growth). This market dynamic is mostly present in developing countries with rapidly growing energy demand (in particular, Asia) and countries with abundant oil and gas reserves that have decided to expand downstream (in particular, the Middle East and Russia). The Onshore market remains relatively small in Western Europe, although with a diversity of projects, including a second generation of bio ethanol plants. The North American Onshore market is experiencing a strong recovery in the wake of the oil and gas shale revolution.

The Offshore market is more directly impacted by changes in oil prices. Offshore fields in the Gulf of Mexico, the Middle East, and the North Sea were the traditional backbone for investments in the last decade. Recent discoveries of offshore fields with reserves in other regions such as Brazil, Australia, and East Africa are expected to become drivers of increased investment. In the long-term, gas is expected to become a bigger portion of the global energy mix, requiring new investments in the upstream industry.

Strategy

Our strategy is based on the following:


•	Selectivity of clients, projects, and geographies, which serves to maintain early engagement, leading to influence over technological choices, design considerations, and project specifications that make projects economically viable;


•	Technology-driven differentiation with strong project management, which eliminates or significantly reduces technical and project risks, leading to both schedule and cost certainty without compromising safety; and


•	Excellence in project execution, because of our global, multi-center project delivery model complemented by deep partnerships and alliances to ensure the best possible execution for complex projects.

TechnipFMC’s Onshore/Offshore segment continually invests in innovation and technology. The Company is at the forefront of digital solutions due in part to our investment in 3D models and interfaces.

Recent and Future Developments

In response to industry challenges to improve project economics in the Offshore market, we are continuing our cost reduction efforts to align capacity and capabilities with market demands. As such, in 2018 we sold our interest in the Pori Offshore yard in Finland.

Onshore market activity continues to provide a tangible set of opportunities, including natural gas, refining, and petrochemical projects.

Activity in LNG is fueled by higher demand for natural gas a fuel source continues to take a greater share of global energy demand. This trend is structural, driven by market preference for cleaner energy sources and the need to satisfy growing domestic demand in markets such as Asia and the Middle East. To meet this demand, we believe that large gas projects will need to be sanctioned in the near future, as evidenced by both the significant increase in pre-FEED and FEED contract awards and higher levels of pre-bid project planning experienced in 2018.

As Onshore market activity levels remain stable, it provides our business with the opportunity to engage early with our clients and pursue additional front-end engineering studies which serve to optimize project economics while also mitigating risks during project execution. Market opportunities for downstream front-end engineering studies and full EPC projects are most prevalent in the Middle East, African, and Asian markets in both LNG and refining. We continue to track near-term prospects for petrochemical and fertilizer projects as well. We believe this broad opportunity set could generate additional inbound orders in the coming years.

Product Development

We are positioned as a premier provider of project execution and technology solutions which enable our customers to unlock resources at advantaged capital and operating economics. We invest Onshore/Offshore R&D in these main areas: (i) the development of process technology and equipment for economy of scale; (ii) continuous improvement of our proprietary process technologies and other solutions to reduce operating and investment cost; and (iii) diversification of our proprietary technology offering.

Our Offshore R&D efforts are focused on improving the economics of FLNG through innovations in design and constructability. We also launched a new program to develop solutions for smaller scale FLNG and LNG import projects. Additionally, to further reduce operating and investment costs, we progressed the development of robotic solutions for offshore platforms and continue work on a standard and adaptable design for Normally Unmanned Installations (“NUI”).

Acquisitions and Investments

In January 2017, we officially opened our Modular Manufacturing Yard at Dahej, in Gujarat state, located in Western India. The approximately 150,000 square meter yard combines our strengths in process technology, modularized engineering, and manufacturing and construction.

The yard represents a culmination of our knowledge, skills, and technological expertise, covering a range of product lines including: (i) designed modular hydrogen plants; (ii) modular process plant and equipment using proprietary process technology as well as partnering with leading technology partners worldwide; (iii) the components and assemblies of fired heaters, reformers, and ethylene furnaces; and (iv) proprietary special application burners.

No acquisitions or significant investments occurred during 2018.

Surface Technologies

The Surface Technologies segment 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. Such products and systems include wellhead systems as well as technologically advanced high pressure valves, flowlines, and pumps used in stimulation activities for oilfield service companies. Surface Technologies also provides: (i) hydraulic fracturing (“frac”) systems and support services; (ii) production, separation, and flow processing systems; and (iii) measurement systems and loading arm solutions for exploration and production companies. We manufacture most of our products in facilities located worldwide.

Principal Products and Services

Upstream: Drilling, Completion, Pressure Control, and Production - We provide a full range of drilling, completion, pressure control, and production systems for both standard and custom-engineered applications. Surface wellheads and trees are used to control and regulate the flow of crude oil and natural gas from the well. Our surface wellheads are used worldwide on conventional and unconventional platform base applications including desert high temperatures and shale fields. Our wellhead product portfolio includes conventional wellheads, unihead drill-thru wellheads designed for faster installations, drill-time optimization conventional wellheads designed to reduce overall rig time, sealing technology, thermal equipment, valves, and actuators.

Our surface completions portfolio includes integrated frac solutions for shale fields that, together with our digitalized control systems, provide customers the fracturing service companies with a one-stop-shop equipment supplier from wellhead to pipeline. Our portfolio includes manifolds, trees, and well testing equipment for timely and cost-effective well completion. We also provide closed-loop flowback services for the recovery of solids, fluids, and hydrocarbons from oil and natural gas wells after the stimulation of the well, and we provide chokes, de-sanding, and early production equipment and services through to permanent production facilities and services for oil and gas operators.

We design and manufacture articulated rigid flowline products under the Weco®/Chiksan® trademarks, flexible flowline and choke-and-kill products under the Coflexip^® trademark, articulating frac arm manifold trailers, manifold skids, well service pumps, compact valves, and reciprocating pumps used in well completion and stimulation activities by major oilfield service and drilling companies, such as BHGE, Halliburton Company, Schlumberger, Transocean, Ltd., and Weatherford International plc, as well as by oil and gas operators directly. Our flowline Coflexip^® products are used in equipment that pumps fluid into a well during the well construction and stimulation processes. Our Coflexip^® products are also used by drilling companies for choke-and-kill lines and other applications. 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.

Our production offering includes separation and processing systems, production monitoring and optimization systems, well control and integrity systems, standard pumps, compact valves, and measurement solutions designed to enhance field project economics and reduce operating expenditures with an integrated system that spans from wellhead to pipeline.

We support our customers through comprehensive service packages that provide solutions to ensure optimal equipment performance and reliability. These service packages include all phases of the asset’s life cycle: from the early planning stages through testing and installation, commissioning and operations, replacement and upgrade, intervention, decommissioning and abandonment, and maintenance, storage, and preservation.

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 FPSO 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 risks associated with custody transfer.

Loading Systems - We provide land- and marine-based loading and transfer systems to the oil and gas, petrochemical, and chemical industries. Our systems provide loading and transfer solutions using articulated rigid Chiksan^® loading arms and Chiksan^® swivel joint technologies and flexible-based Coflexip^® technologies, which are 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 offshore 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, LNG, and chemical products.

Capital Intensity

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

Dependence on Key Customers

No single Surface Technologies customer accounted for 10% or more of our 2018 consolidated revenue.

Competition

Surface Technologies is a market leader for our primary products and services. Some of the factors that distinguish us from other companies in the same sector include our technological innovation, reliability, product quality, and ability to integrate across a broad portfolio scope. Surface Technologies competes with other companies that supply surface production equipment and pressure control products. Some of our major competitors in Surface Technologies include BHGE, Cactus, Inc., Forum Energy Technologies, Inc., Gardner Denver, Inc., Schlumberger, and The Weir Group plc.

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 provided by our Canadian services business, specifically completion services, 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.

Market Environment

Surface Technologies’ performance is typically driven by variations in global drilling activity, creating a dynamic environment. Operating results can be further impacted by pressure pumping activity and completions intensity in the Americas.

The North American market recovery that began in late 2016 continued well into 2018, with rig count and drilling and completion activity steadily improving through the first half of the year. The increased activity resulted in stronger demand for the Company’s products and services. The market also benefited from increased service intensity related to hydraulic fracturing activity. As a result of these market dynamics, we experienced stronger demand for pressure control equipment. When combined with our cost rationalization initiatives, we were able to capture the economic benefits of the higher activity levels. Activity outside of North America remained generally stable after turning down in 2015 but continued to experience competitive pricing pressure in certain markets.

Strategy

Our strategy is focused on being a leading provider of best-cost and high-performance integrated assets and services for our customers in the drilling, completion, upstream production, and midstream transportation sectors. We distinguish our offering by combining three elements – a flawless customer experience, leading digital tools, and integrated systems.

Providing a flawless customer experience is our most important priority and occupies the central pillar of our strategy. For this reason, we have developed the digital tools and customer-centric organizational culture that enable our customers to seamlessly transition into the next era of hydrocarbon production. In addition, our system integration capabilities and automation technologies (i) enable reductions in both capital and operating expenditures by reducing cycle time, allowing our customers to achieve first oil faster, and (ii) optimize the production process by minimizing facility footprint, manual interventions, and environmental impacts.

Recent and Future Developments

We continue to operate in a challenging environment as global activity is still below levels achieved in the prior industry cycle and pricing remains competitive. In the second half of 2018, well completion activity in North America moved lower, negatively impacting demand for pressure control equipment. The activity decline was driven by pipeline takeaway capacity constraints, lower commodity prices, and the depletion of operator budgets, constraining activity to certain oil and gas basins that can generate acceptable returns.

Despite the decline in completions activity, North American drilling activity continued to move higher throughout 2018. With increased well count and reduced completions, the backlog of uncompleted wells continued to grow and further supports our view that completions activity should recover in the second half of 2019 as operator budgets replenish and takeaway capacity improves. As we entered 2019, drilling activity started to decline from the recent peak levels achieved in late 2018. However, with oil prices having rebound from recent lows and operator budgets replenished in the new year, we continue to anticipate that activity levels will move higher for both drilling and completions as we progress through the year.

Outside of the Americas, we expect global activity levels to improve in 2019. Confidence in an improved outlook for our business is further supported by the strong growth experienced in inbound orders and backlog in late 2018. We believe that the Middle East, Asia Pacific, and Northern Europe are best poised for new order growth. Our international business continued to experience competitive pricing pressure throughout much of 2018. We believe market pricing has since stabilized and expect this pricing environment to continue throughout 2019.

Product Development

In early 2018, we successfully launched the 2” 10,000 psi cage choke expanding the Company’s traditional product offering for onshore solutions and delivering our first order to a major Middle East customer. For flow testing and early production, we launched a fully automated and digitized Flow Testing Advanced Automated Package (AAP) leveraging the Company’s superior de-sanding and fluid-separation technology and as well as our digital platform, which allows for remote monitoring and real-time data capture via the cloud. We also launched compact, modular permanent production facility solutions for both onshore-shale and offshore shallow-water fields and have recently received our first contract award.

Acquisitions and Investments

In October 2017, we announced an agreement to acquire Plexus Holding plc’s (“Plexus”) wellhead exploration equipment and services business for jack up applications. In conjunction with our global footprint and market presence, this portfolio expansion in the mudline and high-pressure, high-temperature arena will enable us to be a leading provider of products and services to the global jack-up exploration drilling market. This acquisition fits within our strategy to extend and strengthen our position in exploration-drilling products and services while leveraging our global field presence. The acquisition closed in the first quarter of 2018.

The business has been integrated into our Surface Technologies segment, including the transfer of key personnel from Plexus, with their specialized expertise, to ensure continuity and ongoing customer support. The business continues to operate from the existing location in Dyce, Aberdeen, United Kingdom.

In December 2017, we opened a new 18,000 square meter facility in Abu Dhabi’s Industrial City 2, and in June 2018, we broke ground on a new 52,000 square meter facility in Dhahran, Saudi Arabia. These facilities are part of our continued investment in the United Arab Emirates and Saudi Arabia to reinforce our leading position in delivering local solutions that extend asset life and improve project returns. They position us to respond to the expected increase in activity for Abu Dhabi National Oil Company (“ADNOC”) and Saudi Aramco in 2019 and beyond while strengthening our capabilities, providing a solid platform for us to grow our integrated offerings into this region, including multiple product lines and aftermarket services that are key to our growth strategy. The new facilities will offer a broader range of capabilities and greater value-add in-country, supporting our full portfolio with high-technology equipment in the drilling, completion, production, and pressure-control sectors.

OTHER BUSINESS INFORMATION RELEVANT TO OUR BUSINESS SEGMENTS

Sources and Availability of Raw Materials

Our business segments purchase carbon steel, stainless steel, aluminum, and steel castings and forgings from the global marketplace. 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 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 and Onshore/Offshore products to meet our customer needs.

Patents, Trademarks and Other Intellectual Property

We own a number of patents, trademarks, and licenses that are cumulatively important to our businesses. As part of our ongoing R&D focus, we seek patents when appropriate for new products, product improvements and related service innovations. We have approximately 7,000 issued patents and pending patent applications worldwide. Further, we license intellectual property rights to or from third parties. We also own numerous trademarks and trade names and have approximately 500 registrations and pending applications worldwide.

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, 2018, we had more than 37,000 employees.

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 segment’s revenue is dependent upon worldwide oil and gas exploration, production and petrochemical activity. Financial information about our segments and geographic areas is incorporated herein by reference from Note 5 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.

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.

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 and statements, are available free of charge through our website at www.technipfmc.com, under “Investors—Regulatory filings—Regulatory filings” as soon as reasonably practicable after such material is electronically filed with, or furnished to, the U.S. 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.

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.

The following table indicates the names and ages of our executive officers as of March 11, 2019, including all offices and positions held by each in the past five years:



Name	Age	Current Position and Business Experience (Start Date)
Thierry Pilenko¹	61	Executive Chairman (2017) Chairman and Chief Executive Officer of Technip (2007)
Douglas J. Pferdehirt¹	55	Chief Executive Officer (2017) President and Chief Executive Officer of FMC Technologies (2016) President and Chief Operating Officer of FMC Technologies (2015) Executive Vice President and Chief Operating Officer of FMC Technologies (2012)
Maryann T. Mannen¹	56	Executive Vice President and Chief Financial Officer (2017) Executive Vice President and Chief Financial Officer for FMC Technologies (2014) Senior Vice President and Chief Financial Officer for FMC Technologies (2011)
Dianne B. Ralston¹	52	Executive Vice President, Chief Legal Officer and Secretary (2017) Senior Vice President, General Counsel, and Secretary of FMC Technologies, Inc. (2015) Executive Vice President, General Counsel, and Secretary of Weatherford International plc (2014) Deputy General Counsel—Corporate of Schlumberger Limited (2012)
Justin Rounce¹	52	Executive Vice President and Chief Technology Officer (2018) President—Valves & Measurement for Schlumberger Limited (2018) Senior Vice President—Marketing & Technology for Schlumberger Limited (2016) Vice President—Marketing & Chief Technology Officer for Cameron International Corporation (2015) Vice President—Marketing & Technology for OneSubsea (2013)
Agnieszka Kmieciak¹	45	Executive Vice President—People and Culture (2018) HR Director—Production Group for Schlumberger Limited (2017) Talent Manager and Workforce Planning Manager for Schlumberger Limited (2015) M-I SWACO HR Manager for Schlumberger Limited (2012)
Arnaud Piéton¹	45	President—Subsea (2018) Executive Vice President—People and Culture (2017) President—Asia-Pacific Region of Technip (2016) Chief Operating Officer, Subsea—Asia-Pacific Region of Technip (2014) Vice President, Subsea Projects—North America Region of Technip (2011)
Richard G. Alabaster¹	58	President—Surface Technologies (2017) Vice President—Surface Technologies of FMC Technologies (2015) General Manager—Surface Integrated Services of FMC Technologies (2013) General Manager—Fluid Control of FMC Technologies (2010)
Barry Glickman¹	50	President—Engineering, Manufacturing and Supply Chain (2017) Vice President—Subsea Services of FMC Technologies (2015) General Manager—Subsea Systems Western Region of FMC Technologies (2012)
Nello Uccelletti¹	65	President—Onshore/Offshore (2017) President—Onshore/Offshore of Technip (2014) Senior Vice President—Onshore/Offshore of Technip (2008)
Christophe Bélorgeot²	52	Senior Vice President, Corporate Engagement (2018) Vice President, Corporate Communications (2017) Senior Vice President, Communications and CEO Office of Technip (2014) Vice President, Communications of Technip (2010)
Krisztina Doroghazi³	47	Senior Vice President, Controller, and Chief Accounting Officer (2018) Senior Vice President, Financing Planning and Reporting of MOL Group (2015) Regional Chief Financial Officer of MOL Group (2012)

__________________

¹Member of the Executive Leadership Team and a Rule 3b-7 executive officer and Section 16 officer under the Exchange Act

²Member of the Executive Leadership Team

³Section 16 officer under the Exchange Act

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 10 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 appointed by the Board of Directors to hold office until their successors are appointed.

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.

We operate in a highly competitive environment and unanticipated changes relating to competitive factors in our industry, including ongoing industry consolidation, may impact our results of operations.

We compete on the basis of a number of different factors, such as product offerings, project execution, customer service, and price. In order to compete effectively we must develop and implement innovative technologies and processes, and execute our clients’ projects effectively. We can give no assurances that we will continue to be able to compete effectively with the products and services or prices offered by our competitors.

Our industry, including our customers and competitors, has experienced unanticipated changes in recent years. Moreover, the industry is undergoing vertical and horizontal consolidation to create economies of scale and control the value chain, which may affect demand for our products and services because of price concessions for our competitors or decreased customer capital spending. This consolidation activity could impact our ability to maintain market share, maintain or increase pricing for our products and services or negotiate favorable contract terms with our customers and suppliers, which could have a significant negative impact on our results of operations, financial condition or cash flows. We are unable to predict what effect consolidations and other competitive factors 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.

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 (i) the level of exploration, development and production activity, (ii) capital spending, and (iii) the processing of oil and natural gas in refining units, petrochemical sites, and natural gas liquefaction plants by energy companies that are our customers. 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 exploration of existing wells, which could adversely affect demand for our products and services and, in certain instances, result in the cancellation, modification, or re-scheduling 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 and are likely to continue to be volatile in the future.

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 socio-political unrest;


•	government policies and subsidies related to the production, use, and exportation/importation of oil and natural gas;


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


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


•	technological advances affecting energy consumption;


•	development, exploitation, and relative price, and availability of alternative sources of energy and our customers’ shift of capital to the development of these sources;


•	volatility in, and 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. While oil and natural gas prices have recently started to rebound from the downturn that began in 2014, the market remains quite volatile and the sustainability of the price recovery and business activity levels is dependent on variables beyond our control, such as geopolitical stability, OPEC’s actions to regulate its production capacity, changes in demand patterns, and international sanctions and tariffs. Continued volatility or any future reduction in demand for oilfield services and could further adversely affect our financial condition, results of operations, or cash flows.

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

Our success depends on the ongoing development and implementation of new product designs, including the processes used by us to produce and market our products, and on our ability to protect and maintain critical intellectual property assets related to these developments. If we are not able to obtain patent, trade secret or other protection of our intellectual property rights, if our patents are unenforceable or the claims allowed under our patents are not sufficient to protect our technology, or if we are not able to adequately protect our patents or trade secrets, we may not be able to continue to develop our services, products and related technologies. Additionally, our competitors may be able to independently develop technology that is similar to ours without infringing on our patents or gaining access to our trade secrets. If any of these events occurs, we may be unable to meet evolving industry requirements or do so at prices acceptable to our customers, which could adversely affect our financial condition, results of operations, and cash flows.

The industries in which we operate or have operated expose us to potential liabilities, including the installation or use of our products, which may not be covered by insurance or may be in excess of policy limits, or for which expected recoveries may not be realized.

We are subject to potential liabilities arising from, among other possibilities, equipment malfunctions, equipment misuse, personal injuries, and natural disasters, any of which may result in hazardous situations, including 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.

We may lose money on fixed-price contracts.

As customary for some of our projects, we often agree to provide products and services under fixed-price contracts. We are subject to material risks in connection with such fixed-price contracts. It is not possible to estimate with complete certainty the final cost or margin of a project at the time of bidding or during the early phases of its execution. Actual expenses incurred in executing these fixed-price contracts can vary substantially from those originally anticipated for several reasons including, but not limited to, the following:

•unforeseen additional costs related to the purchase of substantial equipment necessary for contract fulfillment or labor shortages in the markets for where the contracts are performed;


•	mechanical failure of our production equipment and machinery;


•	delays caused by local weather conditions and/or natural disasters (including earthquakes and floods); and


•	a failure of suppliers, subcontractors, or joint venture partners to perform their contractual obligations.

The realization of any material risks and unforeseen circumstances could also lead to delays in the execution schedule of a project. We may be held liable to a customer should we fail to meet project milestones or deadlines or to comply with other contractual provisions. Additionally, delays in certain projects could lead to delays in subsequent projects for which production equipment and machinery currently being utilized on a project were intended.

Pursuant to the terms of fixed-price contracts, we are not always able to increase the price of the contract to reflect factors that were unforeseen at the time its bid was submitted, and this risk may be heightened for projects with

longer terms. Depending on the size of a project, variations from estimated contract performance, or variations in multiple contracts, could have a significant impact on our financial condition, results of operations or cash flows.

New capital asset construction projects for vessels and manufacturing facilities are subject to risks, including delays and cost overruns, which could have a material adverse effect on our financial condition, or results of operations.

We regularly carry out capital asset construction projects to maintain, upgrade, and develop our asset base, and such projects are subject to risks of delay and cost overruns that are inherent to any large construction project, and are the result of numerous factors including, but not limited to, the following:


•	shortages of key equipment, materials or skilled labor;


•	unscheduled delays in the delivery or ordered materials and equipment;


•	design and engineering issues; and


•	shipyard delays and performance issues.

Failure to complete construction in time, or the inability to complete construction in accordance with its design specifications, may result in loss of revenue. Additionally, capital expenditures for construction projects could materially exceed the initially planned investments or can result in delays in putting such assets into operation.

Our failure to timely deliver our backlog could affect future sales, profitability, and 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 upon 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.

We face risks relating to our reliance on subcontractors, suppliers, and our joint venture partners.

We generally rely on subcontractors, suppliers, and our joint venture partners for the performance of our contracts. Although we are not dependent upon any single supplier, certain geographic areas of our business or a project or group of projects may depend heavily on certain suppliers for raw materials or semi-finished goods.

Any difficulty in engaging suitable subcontractors or acquiring equipment and materials could compromise our ability to generate a significant margin on a project or to complete such project within the allocated timeframe. If subcontractors, suppliers or joint venture partners refuse to adhere to their contractual obligations with us or are unable to do so due to a deterioration of their financial condition, we may be unable to find a suitable replacement at a comparable price, or at all. Moreover, the failure of one of our joint venture partners to perform their obligations in a timely and satisfactory manner could lead to additional obligations and costs being imposed on us as we may be obligated to assume our defaulting partner’s obligations or compensate our customers.

Any delay, failure to meet contractual obligations, or other event beyond our control or not foreseeable by us, that is attributable to a subcontractor, supplier or joint venture partner, could lead to delays in the overall progress of the project and/or generate significant extra costs. Even if we are entitled to make a claim for these extra costs against the defaulting supplier, subcontractor or joint venture partner, we may be unable to recover the entirety of these costs and this could materially adversely affect our business, financial condition or results of operations.

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 failure 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.

Pirates endanger our maritime employees and assets.

We face material piracy risks in the Gulf of Guinea, the Somali Basin, and the Gulf of Aden, and, to a lesser extent, in Southeast Asia, Malacca, and the Singapore Straits. Piracy represents a risk for both our projects and our vessels, which operate and transport through sensitive maritime areas. Such risks have the potential to significantly harm our crews and to negatively impact the execution schedule for our projects. If our maritime employees or assets are endangered, additional time may be required to find an alternative solution, which may delay project realization and negatively impact our business, financial condition, or results of operations.

Seasonal and weather conditions could adversely affect demand for our services and operations.

Our business may be materially affected by variation from normal weather patterns, such as cooler or warmer summers and winters. Adverse weather conditions, such as hurricanes in the Gulf of Mexico or extreme winter conditions in Canada, Russia, and the North Sea, may interrupt or curtail our operations, or our customers’ operations, cause supply disruptions or loss of productivity, and may result in a loss of revenue or damage to our equipment and facilities, which may or may not be insured. Any of these events or outcomes could have a material adverse effect on our business, financial condition, cash flows, and results of operations.

Due to the types of contracts we enter into and the markets in which we operate, the cumulative loss of several major contracts, customers, 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. Moreover, the global market for the production, transportation, and transformation of hydrocarbons and by-products, as well as the other industrial markets in which we operate, is dominated by a small number of companies. As a result, our business relies on a limited number of customers. If we were to lose several key contracts, customers, or alliances over a relatively short period of time, we could experience a significant adverse impact on our financial condition, results of operations, or cash flows.

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

Our operations and manufacturing activities are governed by international, regional, transnational, and national laws and regulations in every place where we operate relating to matters such as environmental protection, health and safety, labor and employment, import/export controls, 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 international operations are subject to anti-corruption laws and regulations, such as the U.S. Foreign Corrupt Practices Act (“FCPA”), the U.K. Bribery Act of 2010 (the “Bribery Act”), the anti-corruption provisions of French law n° 2016-1691 dated December 9, 2016 relating to Transparency, Anti-corruption and Modernization of the Business Practice (“Sapin II Law”), the Brazilian Anti-Bribery Act (also known as the Brazilian Clean Company Act), and economic and trade sanctions, including those administered by the United Nations, the European Union, the Office of Foreign Assets Control of the U.S. Department of the Treasury (“U.S. Treasury”), and the U.S. Department of State. The FCPA prohibits providing anything of value to foreign officials for the purposes of obtaining or retaining business or securing any improper business advantage. We may deal with both governments and state-owned business enterprises, the employees of which are considered foreign officials for purposes of the FCPA. The provisions of the Bribery Act extend beyond bribery of foreign public officials and are more onerous than the FCPA in a number of other respects, including jurisdiction, non-exemption of facilitation payments, and penalties. Economic and trade sanctions restrict our transactions or dealings with certain sanctioned countries, territories, and designated persons.

As a result of doing business in foreign countries, including through partners and agents, we are exposed to a risk of violating anti-corruption laws and sanctions regulations. Some of the international locations in which we currently or may, in the future, operate, have developing legal systems and may have higher levels of corruption than more developed nations. Our continued expansion and worldwide operations, including in developing countries, our development of joint venture relationships worldwide, and the employment of local agents in the countries in which

we operate increases the risk of violations of anti-corruption laws and economic and trade sanctions. Violations of anti-corruption laws and economic and trade sanctions are punishable by civil penalties, including fines, denial of export privileges, injunctions, asset seizures, debarment from government contracts (and termination of existing contracts), and revocations or restrictions of licenses, as well as criminal fines and imprisonment. In addition, any major violations could have a significant impact on our reputation and consequently on our ability to win future business.

We have implemented internal controls designed to minimize and detect potential violations of laws and regulations in a timely manner but we can provide no assurance that such policies and procedures will be followed at all times or will effectively detect and prevent violations of the applicable laws by one or more of our employees, consultants, agents, or partners. The occurrence of any such violation could subject us to penalties and material adverse consequences on our business, financial condition, or results of operations.

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

Environmental laws and regulations in various countries affect the equipment, systems, and services we design, market, and sell, as well as the facilities where we manufacture our equipment and systems, and any other operations we undertake. 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, the issuance of orders enjoining our operations, or other claims. 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, are becoming increasingly strict and could adversely affect our business and operating results by increasing our costs, limiting the demand for our products and services, or restricting our operations.

Existing or future laws and regulations relating to greenhouse gas emissions and climate change may adversely affect our business.

Existing or future laws concerning the release of greenhouse gas emissions or that concern climate change (including laws and regulations that seek to mitigate the effects of climate change) may adversely impact demand for the equipment, systems and services we design, market and sell. For example, oil and natural gas exploration and production may decline as a result of such laws and regulations and as a consequence demand for our equipment, systems and services may also decline. In addition, such laws and regulations may also result in more onerous obligations with respect to our operations, including the facilities where we manufacture our equipment and systems. Such decline in demand for our equipment, systems and services and such onerous obligations in respect of our operations may adversely affect our financial condition, results of operations and 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 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 could have an adverse effect on the demand for our services and products, 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;


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


•	trade restrictions, trade protection measures, price controls, or trade disputes;


•	sanctions, such as prohibitions or restrictions by the United States against countries that are the targets of economic sanctions, or are designated as state sponsors of terrorism;


•	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;


•	regime changes;


•	changes in, and the administration of, treaties, 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.

DTC and Euroclear Paris may cease to act as depository and clearing agencies for our shares.

Our shares were issued into the facilities of The Depository Trust Company (“DTC”) with respect to shares listed on the NYSE and Euroclear with respect to shares listed on Euronext Paris (DTC and Euroclear being referred to as the “Clearance Services”). The Clearance Services are widely used mechanisms that allow for rapid electronic transfers of securities between the participants in their respective systems, which include many large banks and brokerage firms. The Clearance Services have general discretion to cease to act as a depository and clearing agencies for our shares. If either of the Clearance Services determine at any time that our shares are not eligible for continued deposit and clearance within its facilities, then we believe that our shares would not be eligible for continued listing on the NYSE or Euronext Paris, as applicable, and trading in our shares would be disrupted. Any such disruption could have a material adverse effect on the trading price of our shares.

The United Kingdom’s proposed withdrawal from the European Union may have a negative effect on global economic conditions, financial markets, and our business.

We are based in the United Kingdom and have operational headquarters in Paris, France; Houston, Texas, United States; and in London, United Kingdom, with worldwide operations, including material business operations in Europe. In June 2016, a majority of voters in the United Kingdom elected to withdraw from the European Union in a national referendum (“Brexit”). The referendum was advisory, and the United Kingdom government served notice under Article 50 of the Treaty of the European Union in March 2017 to formally initiate a withdrawal process. The United Kingdom and the European Union have had a two-year period under Article 50 to negotiate the terms for the United Kingdom’s withdrawal from the European Union. The withdrawal agreement and political declaration that were endorsed at a special meeting of the European Council on November 25, 2018 did not receive the approval of the United Kingdom Parliament in January 2019. Further discussions are ongoing, although the European Commission has stated that the European Union will not reopen the withdrawal agreement. Any extension of the negotiation period for withdrawal will require the consent of the remaining 27 member states of the European Union. Brexit has created significant uncertainty about the future relationship between the United Kingdom and the European Union and has given rise to calls for certain regions within the United Kingdom to preserve their place in the European Union by separating from the United Kingdom.

These developments, or the perception that any of them could occur, could have a material adverse effect on global economic conditions and the stability of the global financial markets and could significantly reduce global market liquidity and restrict the ability of key market participants to operate in certain financial markets. Asset valuations, currency exchange rates, and credit ratings may be especially subject to increased market volatility. Lack of clarity about applicable future laws, regulations, or treaties as the United Kingdom negotiates the terms of a withdrawal, as well as the operation of any such rules pursuant to any withdrawal terms, including financial laws and regulations, tax and free trade agreements, intellectual property rights, supply chain logistics, environmental, health and safety laws and regulations, immigration laws, employment laws, and other rules that would apply to us and our subsidiaries, could increase our costs, restrict our access to capital within the United Kingdom and the European Union, depress economic activity, and further decrease foreign direct investment in the United Kingdom. For

example, withdrawal from the European Union could, depending on the negotiated terms of such withdrawal, eliminate the benefit of certain tax-related E.U. directives currently applicable to U.K. companies such as us, including the Parent-Subsidiary Directive and the Interest and Royalties Directive, which could, subject to any relief under an available tax treaty, raise our tax costs.

If the United Kingdom and the European Union are unable to negotiate mutually acceptable withdrawal terms or if other E.U. member states pursue withdrawal, barrier-free access between the United Kingdom and other E.U. member states or within the European Economic Area overall could be diminished or eliminated. Any of these factors could have a material adverse effect on our business, financial condition, and results of operations.

As an English public limited company, we must meet certain additional financial requirements before we may declare dividends or repurchase shares and certain capital structure decisions may require stockholder approval which may limit our flexibility to manage our capital structure. We may not be able to pay dividends or repurchase shares of our ordinary shares in accordance with our announced intent, or at all.

Under English law, we will only be able to declare dividends, make distributions, or repurchase shares (other than out of the proceeds of a new issuance of shares for that purpose) out of “distributable profits.” Distributable profits are a company’s accumulated, realized profits, to the extent that they have not been previously utilized by distribution or capitalization, less its accumulated, realized losses, to the extent that they have not been previously written off in a reduction or reorganization of capital duly made. In addition, as a public limited company incorporated in England and Wales, we may only make a distribution if the amount of our net assets is not less than the aggregate of our called-up share capital and non-distributable reserves and to the extent that the distribution does not reduce the amount of those assets to less than that aggregate.

Following the Merger, we implemented a court-approved reduction of our capital, which was completed on June 29, 2017, in order to create distributable profits to support the payment of possible future dividends or future share repurchases. Our articles of association permit us by ordinary resolution of the stockholders to declare dividends, provided that the directors have made a recommendation as to its amount. The dividend shall not exceed the amount recommended by the Board of Directors. The directors may also decide to pay interim dividends if it appears to them that the profits available for distribution justify the payment. When recommending or declaring payment of a dividend, the directors are required under English law to comply with their duties, including considering our future financial requirements.

In addition, the Board of Directors’ determinations regarding dividends and share repurchases will depend on a variety of other factors, including our net income, cash flow generated from operations or other sources, liquidity position, and potential alternative uses of cash, such as acquisitions, as well as economic conditions and expected future financial results. Our ability to declare and pay future dividends and make future share repurchases will depend on our future financial performance, which in turn depends on the successful implementation of our strategy and on financial, competitive, regulatory, technical, and other factors, general economic conditions, demand and selling prices for our products and services, and other factors specific to our industry or specific projects, many of which are beyond our control. Therefore, our ability to generate cash depends on the performance of our operations and could be limited by decreases in our profitability or increases in costs, regulatory changes, capital expenditures, or debt servicing requirements.

Any failure to pay dividends or repurchase shares of our ordinary shares could negatively impact our reputation, harm investor confidence in us, and cause the market price of our ordinary shares to decline.

Our existing and future debt may limit cash flow available to invest in the ongoing needs of our business and could prevent us from fulfilling our obligations under our outstanding debt.

We have substantial existing debt. As of December 31, 2018, after giving effect to the Merger, our total debt is $4.2 billion. We also have the capacity under our $2.5 billion credit facility, in addition to our bilateral facilities to incur substantial additional debt. Our level of debt could have important consequences. For example, it could:


•	make it more difficult for us to make payments on our debt;


•	require us to dedicate a substantial portion of our cash flow from operations to the payment of debt service, reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, distributions, and other general partnership purposes;


•	increase our vulnerability to adverse economic or industry conditions;


•	limit our ability to obtain additional financing to enable us to react to changes in our business; or


•	place us at a competitive disadvantage compared to businesses in our industry that have less debt.

Additionally, any failure to meet required payments on our debt or to comply with any covenants in the instruments governing our debt, could result in an event of default under the terms of those instruments. In the event of such default, the holders of such debt could elect to declare all the amounts outstanding under such instruments to be due and payable.

The London Inter-bank Offered Rate (“LIBOR”) and certain other interest “benchmarks” may be subject to regulatory guidance and/or reform that could cause interest rates under our current or future debt agreements to perform differently than in the past or cause other unanticipated consequences. The United Kingdom’s Financial Conduct Authority, which regulates LIBOR, has announced that it intends to stop encouraging or requiring banks to submit LIBOR rates after 2021, and it is unclear if LIBOR will cease to exist or if new methods of calculating LIBOR will evolve. If LIBOR ceases to exist or if the methods of calculating LIBOR change from their current form, interest rates on our current or future debt obligations may be adversely affected.

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 or 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, as well as have a material adverse effect on our business, financial condition, and results of operations.

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 or operating environments in which our employees operate, to the extent deemed prudent by our management and to the extent insurance is available. However, our insurance policies are subject to exclusions, limitations, and other conditions and may not apply in all cases, for example where willful wrongdoing on our part is alleged. Additionally, the nature and amount of that insurance may not be sufficient to fully indemnify us against liabilities arising out of pending and future claims and litigation. Additionally, in individual circumstances, certain proceedings or cases may also lead to our formal or informal exclusion from tenders or the revocation or loss of business licenses or permits. 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. The resolution of these claims could require us to enter into license agreements or develop alternative technologies. The development of these technologies or the payment of royalties under licenses from third parties, if available, would increase our costs. If a license were not available, or we are not able to develop alternative technologies, 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.

Currency exchange rate fluctuations could adversely affect our financial condition, results of operations, or cash flows.

We conduct operations around the world in many different currencies. Because a significant portion of our revenue is denominated in currencies other than our reporting currency, the U.S. dollar, 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 and related equity. Although we do not hedge translation impacts on earnings, we do hedge transaction impacts on margins and earnings where the transaction is not in the functional currency of the business unit. Our efforts to minimize our currency exposure through such hedging transactions may not be successful depending on market and business conditions. Moreover, certain currencies in which the Company trades, specifically currencies in countries such as Angola and Nigeria, do not actively trade in the global foreign exchange markets and may subject us to increased foreign currency exposures. As a result, fluctuations in foreign currency exchange rates may adversely affect our financial condition, results of operations, or cash flows.

We may incur significant Merger-related costs.

We have incurred and expect to incur additional non-recurring direct and indirect costs associated with the Merger. In addition to the costs and expenses associated with the consummation of the Merger, we are also integrating processes, policies, procedures, operations, technologies, and systems. While we have assumed that a certain level of expenses would be incurred relating to the Merger and continue to assess the magnitude of these costs, there are many factors beyond our control that could affect the total amount or the timing of the integration and implementation expenses. These costs and expenses could reduce the realization of efficiencies and strategic benefits we expect to achieve from the Merger, and the expected net benefit of the Merger may not be achieved in the near term or at all.

Our acquisition and divestiture activities involve substantial risks.

We have made and expect to continue to pursue acquisitions, dispositions, or other investments that may strategically fit our business and/or growth objectives. We cannot provide assurances that we will be able to locate suitable acquisitions, dispositions, or investments, or that we will be able to consummate any such transactions on terms and conditions acceptable to us. Even if we do successfully execute such transactions, they may not result in anticipated benefits, which could have a material adverse effect on our financial results. If we are unable to successfully integrate and develop acquired businesses, we could fail to achieve anticipated synergies and cost savings, including any expected increases in revenues and operating results. We may not be able to successfully cause a buyer of a divested business to assume the liabilities of that business or, even if such liabilities are assumed, we may have difficulties enforcing our rights, contractual or otherwise, against the buyer. We may invest in companies or businesses that fail, causing a loss of all or part of our investment. In addition, if we determine that an other-than-temporary decline in the fair value exists for a company in which we have invested, we may have to write down that investment to its fair value and recognize the related write-down as an investment loss.

A failure of our IT infrastructure, including as a result of cyber attacks, could adversely impact our business and results of operations.

The efficient operation of our business is dependent on our 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 changing needs. We have been subject to cyber attacks in the past, including phishing, malware, and ransomware, and although no such attack has had a material adverse effect on our business, this may not be the case with future attacks. Our systems may be vulnerable to damages from such attacks, as well as from natural disasters, failures in hardware or software, power fluctuations, unauthorized access to data and systems, loss or destruction of data (including confidential customer information), human error, and other similar disruptions, and we cannot give assurance that any security measures we have implemented or may in the future implement will be sufficient to identify and prevent or mitigate such disruptions.

We rely on third parties to support the operation of our IT hardware, software infrastructure, and cloud services, and in certain instances, utilize web-based and software-as-a-service applications. The security and privacy measures implemented by such third parties, as well as the measures implemented by any entities we acquire or with whom we do business, may not be sufficient to identify or prevent cyber attacks, and any such attacks may have a material adverse effect on our business. While our IT vendor agreements typically contain provisions that seek to eliminate or limit our exposure to liability for damages from a cyber-attack, we cannot ensure such provisions will withstand legal challenges or cover all or any such damages.

Threats to our IT systems arise from numerous sources, not all of which are within our control, including fraud or malice on the part of third parties, accidental technological failure, electrical or telecommunication outages, failures of computer servers or other damage to our property or assets, outbreaks of hostilities, or terrorist acts. 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 insurance coverage may not cover all of the costs and liabilities we incur as the result of any disruptions or security breaches, and if our business continuity and/or disaster recovery plans do not effectively and timely resolve issues resulting from a cyber-attack, we may suffer material adverse effects on our business.

We are subject to governmental regulation and other legal obligations related to privacy, data protection, and data security. Our actual or perceived failure to comply with such obligations could harm our business.

We are subject to international data protection laws, such as the General Data Protection Regulation, or GDPR, in the European Economic Area. The GDPR imposes several stringent requirements for controllers and processors of personal data which have increased our obligations, including, for example, by requiring more robust disclosures to individuals, notifications, in some cases, of data breaches to regulators and data subjects, and a record of processing and other policies and procedures to be maintained to adhere to the accountability principle. In addition, we are subject to the GDPR’s rules on transferring personal data outside of the EEA (including to the United States), and some of these rules are currently being challenged in the courts. Failure to comply with the requirements of GDPR and the local laws implementing or supplementing the GDPR could result in fines of up to €20,000,000 or up to 4% of the total worldwide annual turnover of the preceding financial year, whichever is higher, as well as other administrative penalties. We are likely to be required to expend significant capital and other resources to ensure ongoing compliance with the GDPR and other applicable data protection legislation, and we may be required to put in place additional control mechanisms which could be onerous and adversely affect our business, financial condition, results of operations, and prospects.

We may not realize the cost savings, synergies, and other benefits expected from the Merger.

The combination of two independent companies is a complex, costly, and time-consuming process. As a result, we will be required to continue to devote management attention and resources to integrating the business practices and operations of Technip and FMC Technologies. The integration process may disrupt our businesses and, if ineffectively implemented, could preclude realization of the full benefits expected from the Merger. Our failure to meet the challenges involved in successfully integrating the operations of Technip and FMC Technologies or otherwise realize the anticipated benefits of the Merger could interrupt, and seriously harm the results of, our operations. In addition, the overall integration of Technip and FMC Technologies may result in unanticipated expenses, liabilities, competitive responses, loss of client relationships, diversion of management’s attention, or other problems, and such problems could, if material, cause our stock price to decline. The difficulties of combining the operations of Technip and FMC Technologies include, but are not limited to, the following:


•	managing a significantly larger company;


•	coordinating geographically separate organizations;


•	the potential diversion of management focus and resources from other strategic opportunities and from operational matters;


•	aligning and executing our strategy;


•	retaining existing customers and attracting new customers;


•	maintaining employee morale and retaining key management and other employees;


•	integrating two unique business cultures,


•	the possibility of faulty assumptions underlying expectations regarding the integration process;


•	consolidating corporate and administrative infrastructures and eliminating duplicative operations;


•	coordinating distribution and marketing efforts;


•	integrating IT, communications, and other systems;


•	changes in applicable laws and regulations;


•	managing tax costs or inefficiencies associated with integrating our operations;


•	unforeseen expenses or delays associated with the Merger; and


•	taking actions that may be required in connection with obtaining regulatory approvals.

Many of these factors are at least partially outside our control and any one of them could result in increased costs, decreased revenue, and diversion of management’s time and energy, which could materially impact our business, financial condition, and results of operations. In addition, even if the operations of Technip and FMC Technologies are successfully integrated, we may not realize the full benefits of the Merger, including the synergies, cost savings, sales, or growth opportunities that we expect. These benefits may not be achieved within the anticipated time frame, or at all. As a result, the combination of Technip and FMC Technologies may not result in the realization of the full benefits expected from the Merger.

The IRS may not agree that we should be treated as a foreign corporation for U.S. federal tax purposes and may seek to impose an excise tax on gains recognized by certain individuals.

Although we are incorporated in the United Kingdom, the U.S. Internal Revenue Service (the “IRS”) may assert that we should be treated as a U.S. “domestic” corporation (and, therefore, a U.S. tax resident) for U.S. federal income tax purposes pursuant to Section 7874 of the U.S. Internal Revenue Code of 1986, as amended (the “Code”). For U.S. federal income tax purposes, a corporation (i) is generally considered a “domestic” corporation (or U.S. tax resident) if it is organized in the United States or of any state or political subdivision therein, and (ii) is generally considered a “foreign” corporation (or non-U.S. tax resident) if it is not considered a domestic corporation. Because we are a U.K. incorporated entity, we would be considered a foreign corporation (and, therefore, a non-U.S. tax resident) under these rules. Section 7874 of the Code (“Section 7874”) provides an exception under which a foreign incorporated entity may, in certain circumstances, be treated as a domestic corporation for U.S. federal income tax purposes.

We do not believe this exception applies. However, the Section 7874 rules are complex and subject to detailed regulations, the application of which is uncertain in various respects. It is possible that the IRS will not agree with our position. Should the IRS successfully challenge our position, it is also possible that an excise tax under Section 4985 of the Code (the “Section 4985 Excise Tax”) may be assessed against certain “disqualified individuals” (including former officers and directors of FMC Technologies, Inc.) on certain stock-based compensation held thereby. We may, if we determine that it is appropriate, provide disqualified individuals with a payment with respect to the Section 4985 Excise Tax, so that, on a net after-tax basis, they would be in the same position as if no such Section 4985 Excise Tax had been applied.

In addition, there can be no assurance that there will not be a change in law or interpretation, including with retroactive effect, that might cause us to be treated as a domestic corporation for U.S. federal income tax purposes.

U.S. tax laws and/or guidance could affect our ability to engage in certain acquisition strategies and certain internal restructurings.

Even if we are treated as a foreign corporation for U.S. federal income tax purposes, Section 7874, U.S. Treasury regulations, and other guidance promulgated thereunder may adversely affect our ability to engage in certain future acquisitions of U.S. businesses or to restructure the non-U.S. members of our group. These limitations, if applicable, may affect the tax efficiencies that otherwise might be achieved in such potential future transactions or restructurings.

In addition, the IRS and the U.S. Treasury have issued final and temporary regulations providing that, even if we are treated as a foreign corporation for U.S. federal income tax purposes, certain intercompany debt instruments issued on or after April 4, 2016 will be treated as equity for U.S. federal income tax purposes, therefore limiting U.S. tax benefits and resulting in possible U.S. withholding taxes. Although recent guidance from the U.S. Treasury proposes deferring certain documentation requirements that would otherwise be imposed with respect to covered debt instruments, and further indicates that these rules generally are the subject of continuing study and may be further materially modified, the current regulations may adversely affect our future effective tax rate and could also

impact our ability to engage in future restructurings if such transactions cause an existing intercompany debt instrument to be treated as reissued for U.S. federal income tax purposes.

We are subject to the tax laws of numerous jurisdictions; challenges to the interpretation of, or future changes to, such laws could adversely affect us.

We and our subsidiaries are subject to tax laws and regulations in the United Kingdom, the United States, France, and numerous other jurisdictions in which we and our subsidiaries operate. These laws and regulations are inherently complex, and we are, and will continue to be, obligated to make judgments and interpretations about the application of these laws and regulations to our operations and businesses. The interpretation and application of these laws and regulations could be challenged by the relevant governmental authorities, which could result in administrative or judicial procedures, actions, or sanctions, which could be material.

In addition, the U.S. Congress, the U.K. Government, the European Union, the Organization for Economic Co-operation and Development (the “OECD”), and other government agencies in jurisdictions where we and our affiliates do business have had an extended focus on issues related to the taxation of multinational corporations. New tax initiatives, directives, and rules, such as the U.S. Tax Cuts and Jobs Act, the OECD’s Base Erosion and Profit Shifting initiative, and the European Union’s Anti-Tax Avoidance Directives, may increase our tax burden and require additional compliance-related expenditures. As a result, our financial condition, results of operations, or cash flows may be adversely affected. Further changes, including with retroactive effect, in the tax laws of the United States, the United Kingdom, the European Union, or other countries in which we and our affiliates do business could also adversely affect us.

We may not qualify for benefits under tax treaties entered into between the United Kingdom and other countries.

We operate in a manner such that we believe we are eligible for benefits under tax treaties between the United Kingdom and other countries. However, our ability to qualify for such benefits will depend on whether we are treated as a U.K. tax resident, the requirements contained in each treaty and applicable domestic laws, on the facts and circumstances surrounding our operations and management, and on the relevant interpretation of the tax authorities and courts. For example, because of the anticipated withdrawal of the United Kingdom from the European Union (“Brexit”), we may lose some or all of the benefits of tax treaties between the United States and the remaining members of the European Union, and face higher tax liabilities, which may be significant. Another example is the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting (the “MLI”), which entered into force for participating jurisdictions on July 1, 2018. The MLI recommends that countries adopt a “limitation-on-benefit” rule and/or a “principle purposes test” rule with regards to their tax treaties. The scope and interpretation of these rules as adopted pursuant to the MLI are presently under development, but the application of either rule might deny us tax treaty benefits that were previously available.

The failure by us or our subsidiaries to qualify for benefits under tax treaties entered into between the United Kingdom and other countries could result in adverse tax consequences to us (including an increased tax burden and increased filing obligations) and could result in certain tax consequences of owning and disposing of our shares.

We intend to be treated exclusively as a resident of the United Kingdom for tax purposes, but French or other tax authorities may seek to treat us as a tax resident of another jurisdiction.

We are incorporated in the United Kingdom. English law currently provides that we will be regarded as a U.K. resident for tax purposes from incorporation and shall remain so unless (i) we are concurrently a resident in another jurisdiction (applying the tax residence rules of that jurisdiction) that has a double tax treaty with the United Kingdom and (ii) there is a tiebreaker provision in that tax treaty which allocates exclusive residence to that other jurisdiction.

In this regard, we have a permanent establishment in France to satisfy certain French tax requirements imposed by the French Tax Code with respect to the Merger. Although it is intended that we will be treated as having our exclusive place of tax residence in the United Kingdom, the French tax authorities may claim that we are a tax resident of France if we were to fail to maintain our “place of effective management” in the United Kingdom. Any such claim would be settled between the French and U.K. tax authorities pursuant to the mutual assistance procedure provided for by the tax treaty concluded between France and the United Kingdom. There is no assurance that these authorities would reach an agreement that we will remain exclusively a U.K. tax resident; a determination which could materially and adversely affect our business, financial condition, results of operations, and future prospects. A failure to maintain exclusive tax residency in the United Kingdom could result in adverse tax

consequences to us and our subsidiaries and could result in certain adverse changes in the tax consequences of owning and disposing of our shares.

The Company has identified material weaknesses relating to internal control over financial reporting. If our remedial measures are insufficient to address the material weaknesses, or if one or more additional material weaknesses or significant deficiencies in our internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to further restate our financial results, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Management identified material weaknesses in the Company’s internal control over financial reporting as of December 31, 2017 and December 31, 2018 as described in Part II, Item 9A of this Annual Report on Form 10-K.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis.

As a result of the material weaknesses, management has concluded that our internal control over financial reporting was not effective as of December 31, 2018. In addition, as a result of these material weaknesses, our chief executive officer and chief financial officer have concluded that, as of December 31, 2018, our disclosure controls and procedures were not effective. Until these material weaknesses are remediated, they could lead to errors in our financial results and could have a material adverse effect on our financial condition, results of operations, and cash flows.

If our remedial measures are insufficient to address the material weaknesses, or if one or more additional material weaknesses or significant deficiencies in our disclosure controls and procedures or internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to restate our financial results, which could have a material adverse effect on our financial condition, results of operations, and cash flows, restrict our ability to access the capital markets, require significant resources to correct the weaknesses or deficiencies, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in investor confidence and in the market price of our stock.

Additional material weaknesses or significant deficiencies in our internal control over financial reporting could be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could result in additional significant deficiencies or material weaknesses, cause us to fail to meet our periodic reporting obligations or result in material misstatements in our financial statements. Any such failure could also adversely affect the results of periodic management evaluations and annual auditor attestation reports regarding the effectiveness of our internal control over financial reporting required under Section 404 of the U.S. Sarbanes-Oxley Act of 2002 and the rules promulgated under Section 404. The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, cause us to fail to meet our reporting obligations and cause investors to lose confidence in our reported financial information, leading to, among other things, a decline in our stock price.

We can give no assurances that the measures we have taken to date, or any future measures we may take, will fully remediate the material weaknesses identified or that any additional material weaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or ensure the fair and accurate presentation of our financial statements included in our periodic reports filed with the U.S. Securities and Exchange Commission.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Our corporate headquarters is in London, England. We also maintain corporate offices in Houston, Texas and Paris, France, where significant worldwide global support activity occurs. In addition, we own or lease numerous properties throughout the world.

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, 2018:



Location		Segment
Africa
Dande, Angola		Subsea
Hassi-Messaoud, Algeria		Surface
Lagos, Nigeria		Subsea
Lobito, Angola		Subsea
Luanda, Angola		Subsea
Malabo, Equatorial New Guinea		Subsea
Port Harcourt, Nigeria		Subsea
Takoradi, Ghana		Subsea
Asia
Hyderabad, India		Surface
Jakarta, Indonesia		Subsea, Onshore/Offshore, Surface
Kuala Lumpur, Malaysia		Subsea, Onshore/Offshore
Labuan, Malaysia		Subsea
New Delhi, India		Onshore/Offshore
Noida, India		Subsea, Onshore/Offshore, Surface
Nusajaya, Malaysia		Subsea, Surface
Singapore		Surface
Australia
Henderson, Australia		Subsea
Perth, Australia		Subsea, Onshore/Offshore
Europe
Aberdeen, United Kingdom		Subsea, Surface
Aktau, Kazakhstan		Subsea, Surface
Atyrau, Kazakhstan		Subsea, Surface
Arnhem, The Netherlands		Surface
Barcelona, Spain		Onshore/Offshore
Bergen, Norway		Subsea, Surface
Compiegne, France		Subsea
Courbevoie (Paris - La Défense), France		Subsea, Onshore/Offshore
Dunfermline, United Kingdom		Subsea, Surface
Ellerbeck, Germany		Surface
Evanton, United Kingdom		Subsea
Horten, Norway		Subsea
Kongsberg, Norway		Subsea, Surface
Le Trait, France		Subsea
London, United Kingdom		Subsea, Onshore/Offshore
Lyon, France		Subsea
Newcastle, United Kingdom		Subsea
Lysaker, Norway		Subsea
Orkanger, Norway		Subsea



Paris, France		Subsea, Onshore/Offshore
Rome, Italy		Onshore/Offshore
Schoonebeck, Netherlands		Surface
Sens, France		Surface
Stavanger, Norway		Subsea, Surface
Zoetermeer, Netherlands		Onshore/Offshore
Middle East
Abu Dhabi, United Arab Emirates		Onshore/Offshore, Surface
Dammam, Saudi Arabia		Surface
North America
Brighton (Colorado), United States		Surface
Calgary (Alberta), Canada		Surface
Corpus Christi (Texas), United States		Surface
Davis (California), United States		Subsea
Houston (Texas), United States		Subsea, Onshore/Offshore, Surface
Edmonton (Alberta), Canada		Surface
Erie (Pennsylvania), United States		Surface
Odessa (Texas), United States		Surface
Oklahoma City (Oklahoma), United States		Surface
San Antonio (Texas), United States		Surface
Stephenville (Texas), United States		Surface
St. John’s (Newfoundland), Canada		Subsea
Theodore (Alabama), United States		Subsea
South America
Bogota, Colombia		Onshore/Offshore
Macaé, Brazil		Subsea
Neuquén, Argentina		Surface
Rio de Janeiro, Brazil		Subsea, Surface
São João da Barra, Brazil		Subsea
Vitória, Brazil		Subsea
Yogal, Colombia		Surface

The following table shows marine vessels in which we held an interest or operated as of December 31, 2018:



Vessel Name	Vessel Type	Special Equipment
Deep Blue	PLSV	Reeled pipelay/flexible pipelay/umbilical systems
Deep Energy	PLSV	Reeled pipelay/flexible pipelay/umbilical systems
Apache II	PLSV	Reeled pipelay/umbilical systems
Global 1200	PLSV/HCV	Conventional pipelay/Heavy handling operations
Global 1201	PLSV/HCV	Conventional pipelay/Heavy handling operations
Deep Orient	HCV	Construction/installation systems
North Sea Atlantic ^(a)	HCV	Construction/installation systems
Skandi Africa ^(a)	HCV	Construction/installation systems
North Sea Giant ^(a)	HCV	Construction/installation systems
Deep Arctic	DSV/HCV	Diver support systems
Deep Explorer	DSV/HCV	Diver support systems
Skandi Vitória	PLSV	Flexible pipelay/umbilical systems
Skandi Niterói	PLSV	Flexible pipelay/umbilical systems
Coral do Atlantico	PLSV	Flexible pipelay/umbilical systems
Estrela do Mar	PLSV	Flexible pipelay/umbilical systems
Skandi Açu	PLSV	Flexible pipelay/umbilical systems
Skandi Búzios	PLSV	Flexible pipelay/umbilical systems
Skandi Olinda ^(b)	PLSV	Flexible pipelay/umbilical systems
Skandi Recife	PLSV	Flexible pipelay/umbilical systems


(a)	Vessels under long term charter.


(b)	Vessel under construction.

PLSV: Pipelay Support Vessel

HCV: Heavy Duty Construction Vessel

LCV: Light Construction Vessel

DSV: Diving Support Vessel

MSV: Multi Service Vessel

ITEM 3. LEGAL PROCEEDINGS

A purported shareholder class action filed in 2017 and amended in January 2018 and captioned Prause v. TechnipFMC, et al., No. 4:17-cv-02368 (S.D. Texas) is pending in the U.S. District Court for the Southern District of Texas against the Company and certain current and former officers and employees of the Company. The suit alleged violations of the federal securities laws in connection with the Company's restatement of our first quarter 2017 financial results and a material weakness in our internal control over financial reporting announced on July 24, 2017. On January 18, 2019, the District Court dismissed claims under Section 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Section 15 of the Securities Act of 1933, as amended (“Securities Act”). A remaining claim for alleged violation of Section 11 of the Securities Act in connection with the reporting of certain financial results in the Company’s Form S-4 Registration Statement filed in 2016 is pending and seeks unspecified damages. The Company is vigorously contesting the litigation and cannot predict its duration or outcome.

In addition to the above-referenced matters, we are involved in various other pending or potential legal actions or disputes in the ordinary course of our business. Management is unable to predict the ultimate outcome of these actions because of their inherent uncertainty. 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 ordinary shares are listed on the NYSE and the regulated market of Euronext Paris, in each case trading under the “FTI” symbol. Prior to the Merger, FMC Technologies common stock was quoted on the NYSE under the FTI symbol and Technip ordinary shares were listed on Euronext Paris. FMC Technologies common stock and Technip ordinary shares were suspended from trading on the NYSE and Euronext Paris, respectively, prior to the open of trading on January 17, 2017.

For information about dividends, see Item 6 “Selected Financial Data” and Note 15 “Stockholders’ Equity” to the Consolidated Financial Statements in Item 8.

As of February 25, 2019, we had 81 registered shareholders.

We had no unregistered sales of equity securities during the year ended December 31, 2018.

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, 2018 – October 31, 2018	408,691	$	29.29	408,691	3,650,795
November 1, 2018 – November 30, 2018	1,202,133	$	23.38	1,202,057	2,448,738
December 1, 2018 – December 31, 2018	928,273	$	19.67	927,809	16,091,108
Total	2,539,097			2,538,557	16,091,108

(a)

Represents 2,538,557 ordinary shares purchased and canceled and 540 ordinary shares purchased and held in an employee benefit trust established for the FMC Technologies, Inc. Non-Qualified Savings and Investment Plan (the “Non-Qualified Plan”). In addition to these shares purchased on the open market, we sold 760 registered ordinary shares held in this trust, as directed by the beneficiaries during the three months ended December 31, 2018.

(b)

In April 2017, we announced a repurchase plan approved by our Board of Directors authorizing up to $500 million to repurchase shares of our issued and outstanding ordinary shares through open market purchases. Following a court-approved reduction of our capital, we implemented our share repurchase program on September 25, 2017. The Board of Directors authorized an extension of this program, adding $300 million in December 2018 for a total of $800 million in ordinary shares.

Performance Graph

The graph below compares the cumulative total shareholder return on our ordinary shares for the period from January 17, 2017 to December 31, 2018 with the Standard & Poor’s 500 Index (“S&P 500 Index”) and PHLX Oil Services Index. The comparison assumes $100 was invested, including reinvestment of dividends, if any, in our ordinary shares on January 17, 2017 and in both of the indexes on the same date. The results shown in the graph below are not necessarily indicative of future performance.



	January 17		December 31
	2017		2017		2018
TechnipFMC plc	$	100.00	$	87.76	$	55.89
S&P 500 Index	100.00		119.82		114.56
PHLX Oil Services Index	100.00		82.00		44.93

ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth selected financial data of the Company for each of the four years in the period ended December 31, 2018. 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.



	Year Ended December 31,
(In millions, except per share data)	2018 ^(a)			2017 ^(b)		2016		2015
Statement of income data
Total revenue	$	12,552.9		$	15,056.9	$	9,199.6	$	11,471.9
Total costs and expenses	$	13,470.5		$	14,091.7	$	8,743.6	$	11,198.3
Net income (loss)	$	(1,910.8	)	$	134.2	$	371.1	$	14.0
Net income (loss) attributable to TechnipFMC plc	$	(1,921.6	)	$	113.3	$	393.3	$	14.4

Earnings (loss) per share from continuing operations attributable to TechnipFMC plc
Basic earnings (loss) per share	$	(4.20	)	$	0.24	$	3.29	$	0.13
Diluted earnings (loss) per share	$	(4.20	)	$	0.24	$	3.16	$	0.13



	December 31,
(In millions)	2018		2017 ^(b)		2016		2015
Balance sheet data
Total assets	$	24,784.5	$	28,263.7	$	18,679.3	$	14,953.6
Long-term debt, less current portion	$	4,124.3	$	3,777.9	$	1,869.3	$	2,005.0
Total TechnipFMC plc stockholders’ equity	$	10,399.6	$	13,387.9	$	5,055.8	$	4,947.2



	Year Ended December 31,
(In millions)	2018			2017 ^(b)		2016		2015
Other financial information
Capital expenditures	$	368.1		$	255.7	$	312.9	$	325.5
Cash flows provided (required) by operating activities	$	(185.4	)	$	210.7	$	493.8	$	700.3
Net cash ^(c)	$	1,348.3		$	2,882.4	$	3,716.4	$	370.4
Order backlog ^(d)	$	14,560.0		$	12,982.8	$	15,002.0	$	18,475.5

(a)

The results of our operations for the year ended December 31, 2018 includes goodwill and vessels impairment charges of $1,383.0 million and $372.9 million, respectively, and a legal provision of $280.0 million. Refer to Notes 17 and 18 to our consolidated financial statements included in Part II, Item 8 of this Annual Report of Form 10-K for additional information on the impairments and legal provision, respectively.

(b)

The results of our operations for the year ended December 31, 2017 consist of the combined results of operations of Technip and FMC Technologies. Due to the Merger, FMC Technologies’ results of operations have been included in our financial statements for periods subsequent to the consummation of the merger on January 16, 2017 and as result data presented for the year December 31, 2017 is not comparable to actual results presented in prior periods. Since Technip was identified as the accounting acquiree for the Merger, our actual results for the years ended December 31, 2016 and December 31, 2015 represent Technip only.

Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information related to the Merger. In order to provide for improved comparability of the 2017 actual results, unaudited pro forma results for 2016 are presented in Part II, Item 7 of this Annual Report on Form 10-K.

(c)

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 and reconciliations of net (debt) cash.


(d)	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 are a global leader in oil and gas projects, technologies, systems and services. We have manufacturing operations worldwide, strategically located to facilitate efficient delivery of these products, technologies, systems and services to our customers. We report our results of operations in the following segments: Subsea, Onshore/Offshore and Surface Technologies. 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 Executive Officer reviews and evaluates operating performance to make decisions about resource 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 5 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, 2018, 2017 and 2016 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 both onshore and offshore 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 segment is affected by changes in commodity prices and trends in deepwater oil and natural gas production. Our Onshore/Offshore segment is impacted by change in commodity prices, population growth and demand for natural gas, although the onshore market is typically more resilient to these changes impacting the segment. Our Subsea and Onshore/Offshore segments both benefit from the current market fundamentals supporting the demand for new liquefied natural gas facilities. Onshore/Offshore also benefits from the construction of petrochemical and fertilizer plants.

Our Surface Technologies segment is primarily affected by changes in commodity prices and 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 results reflect our ability to build long-term alliances with oil and natural gas companies 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.

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 2018, approximately 90% 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.

BUSINESS OUTLOOK

Overall Outlook - Following the steep decline from prior years, the price of crude oil has been on a gradual upward trend since the cyclical trough experienced in early 2016, though the price of crude oil remains quite volatile. In addition, the sustainability of the price recovery and business activity levels is dependent on several variables, including geopolitical stability, OPEC’s actions to regulate its production capacity, changes in demand patterns, and international sanctions and tariffs. However, as long-term demand is forecast to rise and base production continues to naturally decline, we believe the macroeconomic backdrop will provide our customers with greater confidence to increase their investments in new sources of oil and natural gas production.

Subsea - The impact of the low crude oil price environment over the last three years led many of our customers to reduce their capital spending plans and defer new offshore projects. Through this period, we have lowered our cost base through reductions in workforce as well as in manufacturing. This has helped align our operations with the anticipated reductions in activity in order to mitigate some of the negative impact to our operating profit. We have been realizing the benefits from restructuring actions through greater cost efficiency, most notably in our manufacturing operations. We have taken additional actions in 2018, but we have balanced further reductions with the need to preserve capacity in preparation for increased market activity and higher order inbound as industry conditions continue to improve. The operational improvements we have made through the downturn are providing us with the capability to respond to an increase in order activity despite the reductions in both personnel and manufacturing capacity. However, the subsea industry continues to have both underutilized manufacturing and vessel capacity, which may lead to continued pricing pressure. We also recognize the need to further develop and invest in our people to ensure we have the core competencies and capabilities necessary for continued success during the market recovery.

Our lowered cost base combined with the aggressive cost reductions taken by our customers has caused project economics to improve. Many current and future offshore projects are deemed to be economic at prices below those experienced in the third quarter. While customer investment decisions can be delayed for a variety of reasons, we continue to work closely with our customers through early engagement in (FEED) studies and the use of our unique integrated approach to subsea development (iEPCI) to allow more project final investment decisions through the cycle. iEPCI™ can support clients’ initiatives to improve subsea project economics by helping to reduce cost and accelerate time to first oil. In the long term, we continue to believe that offshore and deepwater developments will remain a significant part of our customers’ portfolios.

Onshore/Offshore - Onshore market activity continues to provide a tangible set of opportunities, particularly for natural gas monetization projects, as natural gas continues to take a larger share of global energy demand. Market conditions for liquefied natural gas (“LNG”) have improved as rising demand continues to rebalance an oversupplied market. This is driving an improved outlook for our business, and we are confident that the pace of LNG investments will continue to grow in the near and intermediate term. As an industry leader, we are well positioned for the growth in new liquefaction and regasification capacity and are actively engaged in several LNG FEED studies across multiple geographies. These FEED studies provide a platform for early engagement with clients and can significantly de-risk project execution while also supporting our pursuit of the engineering, procurement and construction (“EPC”) contract. Additionally, we continue to selectively pursue refining, petrochemical, and fertilizer project opportunities in the Middle East, Africa, Asia, and North American markets.

Surface Technologies - After a period of rapid growth, the North America unconventional market is undergoing near-term volatility. While drilling activity has proved to be resilient, completions activity has been reduced, stemming from pipeline take-away capacity constraints and exhaustion of operator capital budgets for exploration and production. Hydraulic fracturing activity has slowed sequentially, particularly in the Permian basin through 2018. These constraints should prove to be transitory, though, as operator budgets renew and pipeline take-away capacity improves and we expect improvement in activity in the second half of 2019. Despite the near-term volatility, we are continuing to introduce new, innovative commercial models in North America. Activity in our surface business outside of North America has been more resilient but continues to experience pressure from competitive pricing; however, growth prospects for these markets are expected to improve further in 2019.

Pro Forma Results of Operations

Unaudited supplemental pro forma results of operations for the year ended December 31, 2016 present consolidated information as if (i) the Merger and (ii) the consolidation of legal onshore/offshore contract entities that own and account for the design, engineering and construction of the Yamal had been completed as of January 1, 2016. The pro forma results do not include any potential synergies, cost savings or other expected benefits of these transactions. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the transactions had been consummated as of January 1, 2016, nor are they indicative of future results.

Refer to Note 2 and Note 14 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information related to the Merger and Yamal, respectively.

Due to the size of the aforementioned transactions relative to the size of historical results of operations and for purposes of comparability, management’s discussion of the consolidated and segment results of operations are provided on the basis of comparing actual results of operations for the year ended December 31, 2017 to pro forma results of operations for the year ended December 31, 2016. Actual results for the year ended December 31, 2016 represent Technip only.

CONSOLIDATED RESULTS OF OPERATIONS



	Year Ended December 31,												Change
(In millions, except percentages)	2018			2017			2016 Pro Forma*			2016			2018 vs. 2017					2017 vs. 2016 Pro Forma
Revenue	$	12,552.9		$	15,056.9		$	19,068.8		$	9,199.6		$	(2,504.0	)	(16.6	)%	$	(4,011.9	)	(21)%
Costs and expenses
Cost of sales	10,273.0			12,524.6			16,382.5			7,630.0			(2,251.6		)	(18.0	)%	(3,857.9		)	(24)%
Selling, general and administrative expense	1,140.6			1,060.9			1,229.9			572.6			79.7			7.5	%	(169.0		)	(14)%
Research and development expense	189.2			212.9			219.5			105.4			(23.7		)	(11.1	)%	(6.6		)	(3)%
Impairment, restructuring and other expense	1,831.2			191.5			443.6			343.0			1,639.7			856.2	%	(252.1		)	(57)%
Merger transaction and integration costs	36.5			101.8			137.8			92.6			(65.3		)	(64.1	)%	(36.0		)	(26)%
Total costs and expenses	13,470.5			14,091.7			18,413.3			8,743.6			(621.2		)	(4.4	)%	(4,321.6		)	(23)%
Other income (expense), net	(323.9		)	(25.9		)	12.1			6.5			(298.0		)	(1,150.6	)%	(38.0		)	(314)%
Income from equity affiliates	114.3			55.6			10.9			117.7			58.7			105.6	%	44.7			410%
Net interest expense	(360.9		)	(315.2		)	(29.1		)	(28.8		)	(45.7		)	(14.5	)%	(286.1		)	(983)%
Income (loss) before income taxes	(1,488.1		)	679.7			649.4			551.4			(2,167.8		)	(318.9	)%	30.3			5%
Provision for income taxes	422.7			545.5			284.7			180.3			(122.8		)	(22.5	)%	260.8			92%
Income (loss) from continuing operations	(1,910.8		)	134.2			364.7			371.1			(2,045.0		)	(1,523.8	)%	(230.5		)	(63)%
Income (loss) from discontinued operations, net of income taxes	—			—			(10.1		)	—			—			—	%	10.1			100%
Net income (loss)	(1,910.8		)	134.2			354.6			371.1			(2,045.0		)	(1,523.8	)%	(220.4		)	(62)%
Net loss (income) attributable to noncontrolling interests	(10.8		)	(20.9		)	23.6			22.2			10.1			48.3	%	(44.5		)	(189)%
Net income (loss) attributable to TechnipFMC plc	$	(1,921.6	)	$	113.3		$	378.2		$	393.3		$	(2,034.9	)	(1,796.0	)%	$	(264.9	)	(70)%



*	Refer to “Pro Forma Results of Operations” above for further information related to the presentation of and transactions included in pro forma results for the year ended December 31, 2016.

2018 Compared With 2017

Revenue

Revenue decreased $2.5 billion in 2018 compared to the prior-year period, primarily as a result of declining project activity. Subsea project activity declined in Africa, Asia Pacific, and North America. Onshore/Offshore activity also declined as projects progressed towards completion, driven primarily by Yamal LNG, partially offset by an increase in project activity in the Middle East and Asia Pacific. Surface Technologies’ revenue increased primarily as a result of strong demand for the North American land market recovery.

Gross profit

Gross profit (revenue less cost of sales) increased as a percentage of sales to 18.2% in 2018, from 16.8% in the prior-year. The increase in gross profit as a percentage of sales was primarily due to the realization of cost reduction opportunities on certain projects, a lower overall cost structure due to cost reduction and synergy initiatives, the successful progression of several major projects with strong economic performance, and the benefit of a better product and service mix.

Selling, general and administrative expense

Selling, general and administrative expense increased $79.7 million year-over-year. FMC Technologies operations prior to the Merger date of January, 17, 2017 is excluded from 2017. FMC Technologies' selling, general and administrative expenses for this period were $63.0 million. On a comparable basis, selling, general and administrative expense increased by $16.7 million, primarily due to increased tendering costs related to an increasing number of FEED studies and future project awards.

Impairment, restructuring and other expense

We incurred impairment, restructuring and other expense of $1.8 billion primarily driven by a $1.4 billion impairment of goodwill and $372.9 million impairment of our vessels. Refer to Note 17 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to impairments.

Merger transaction and integration costs

We incurred integration costs of $36.5 million during 2018. Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to the Merger.

Other income (expense), net

Other income (expense), net, primarily reflects $280.0 million in legal provisions and $116.5 million of net foreign exchange losses associated with the remeasurement of net cash positions and foreign currency derivatives.

Net interest expense

During the year ended December 31, 2018, we revalued the mandatorily redeemable financial liability to reflect current expectations about the obligation and recognized a loss of $322.3 million. Refer to Note 22 for further information regarding the fair value measurement assumptions of the mandatorily redeemable financial liability and related changes in its fair value. Net interest expense, excluding the fair value measurement of the mandatorily redeemable financial liability, also includes interest income and expenses, which were higher by $17.2 million on a net basis compared to 2017.

Provision for income taxes

The effective tax rate was (28.4)% in 2018 and 80.3% in 2017. The effective tax rate for 2018 was significantly impacted by impairments which were only partially tax-effective and non-deductible legal provision. The change in the effective tax rate in 2018 as compared to 2017, excluding these items, was primarily attributable to an unfavorable change in actual country mix of earnings.

2017 Compared With 2016 Pro Forma

Revenue

Revenue decreased $4.0 billion in 2017 compared to the prior-year period on a pro forma basis, primarily resulting from a sharp decline in Subsea activities in the Europe and Africa region due to lower order activity during 2015 and 2016, resulting in a lower backlog of business coming into 2017. The decrease was also attributable to the completion of several projects, combined with lower Subsea vessel utilization. Revenue also decreased across all Onshore/Offshore businesses year-over-year on a pro forma basis, primarily driven by lower levels of project backlog coming into 2017 for the Middle East, North America, and South America regions.

Gross profit

Gross profit (revenue less cost of sales) increased as a percentage of sales to 16.8% in 2017, from 14.1% in the prior-year on a pro forma basis. The improvement in gross profit as a percentage of sales was primarily due to the reduction of cost of sales year-over-year on a pro forma basis as a result of the realization of cost reduction opportunities on certain projects, a lower overall cost structure due to cost reduction and synergy initiatives, the successful progression of several major projects with strong economic performance, and the benefit of a better product and service mix.

Selling, general and administrative expense

Selling, general and administrative expense decreased $169.0 million year-over-year on a pro forma basis, resulting from lower headcount across all reporting segments, due in part to the benefit of Merger synergies and decreased sales commissions due to the reduced revenue.

Impairment, restructuring and other expense

Impairment, restructuring and other expense decreased by $252.1 million year-over-year on a pro forma basis. Impairment, restructuring and other expense for 2017 included $157.2 million of restructuring expense and $34.3 million of impairment expense.

In the comparable periods, on a pro forma basis, we have implemented restructuring plans across our segments to reduce costs and better align our workforce with anticipated activity levels. Thus, we previously incurred significant restructuring expenses in 2016 on a pro forma basis. In 2017 we continued to align our capacity to expected operating activity levels for 2018 and beyond and we were also negatively impacted by Hurricane Harvey, as a result of which we incurred expenses of $10.9 million due to lost productivity.

Merger transaction and integration costs

We incurred merger transaction and integration costs of $101.8 million during 2017 due to the Merger. A significant portion of the expenses recorded in the period are related to transaction and leased facility termination fees, with a lower portion but still material related to integration activities pertaining to combining the two legacy companies. Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information related to the Merger.

Other income (expense), net

Other income (expense), net, primarily reflects foreign currency gains and losses. These include gains and losses associated with the remeasurement of net cash positions as well as foreign currency derivatives. During 2017, we incurred $40.1 million of additional net foreign exchange losses compared to 2016.

Net interest expense

The increase in interest expense was due to the changes in the fair value of a mandatorily redeemable financial liability. During the year ended December 31, 2017, we revalued the liability to reflect current expectations about the obligation and recognized a loss of $293.7 million. Refer to Note 22 for further information regarding the fair value measurement assumptions of the mandatorily redeemable financial liability and related changes in its fair value.

Provision for income taxes

Our income tax provisions for 2017 and 2016 on a historical basis reflected effective tax rates of 80.3% and 32.7%, respectively. The year-over-year increase in the effective tax rate was primarily due to increases in our valuation allowance due to additional losses generated during the year for which no tax benefit is expected to be realized and an unfavorable change in actual country mix of earnings. In addition, due to U.S. legislation passed in the fourth quarter of 2017, we incurred a one-time deemed repatriation transition tax of $148.7 million and an unfavorable tax provision impact of $18.9 million from the revaluation of the U.S. deferred individual tax assets and liabilities.

OPERATING RESULTS OF BUSINESS SEGMENTS

Segment operating profit is defined as total segment revenue less segment operating expenses. Certain items have been excluded in computing segment operating profit and are included in corporate items. Refer to Note 5 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information.

We report our results of operations in U.S. dollars; however, our earnings are generated in various currencies worldwide. 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



	Year Ended December 31,												Favorable/(Unfavorable)
(In millions, except %)	2018			2017^(a)			2016 Pro Forma			2016			2018 vs. 2017				2017 vs. 2016 Pro Forma
Revenue	$	4,840.0		$	5,877.4		$	9,150.5		$	5,850.5		$	(1,037.4	)	(18)%	$	(3,273.1	)	(36)%
Operating profit (loss)	$	(1,529.5	)	$	460.5		$	982.6		$	732.0		$	(1,990.0	)	(432)%	$	(522.1	)	(53)%

Operating profit as a percent of revenue	n/a			7.8		%	10.7		%	12.5		%				n/a				(2.9	) pts.


(a)	Due to the Merger, there were 11.5 months included in the year ended 2017 for legacy FMC Technologies, compared with twelve months in pro forma 2016. Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information related to the Merger.

2018 Compared With 2017

Subsea revenue decreased $1.0 billion year-over-year, primarily due to projects in Africa, Asia Pacific and North America regions that progressed towards completion, partially offset by increased activity in Europe. Subsea revenue continued to be negatively impacted by prior period lower inbound orders related to the market downturn.

Subsea operating profit, excluding $1,784.2 million of asset impairment charges, totaled $254.7 million, compared to the prior-year’s operating profit of $460.5 million. The reduction was primarily due to the anticipated revenue decline related to the prior period lower inbound orders, partially offset by Merger synergies and other cost reduction activities, and the successful completion of key project milestones. Additionally, 2018 included $1,784.2 million of asset impairment charges primarily related to the impairment of goodwill and certain of our vessels. Refer to Note 17 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to these asset impairments.

Refer to ‘Non-GAAP Measures’ for further information regarding our segment operating results.

2017 Compared With 2016 Pro Forma

Subsea revenue decreased $3.3 billion year-over-year on a pro forma basis primarily due to lower overall activity in the Europe, Africa and North America regions as a result of the reduced backlog from 2015 and 2016. Additionally, the decrease in revenue was attributable to the completion of several projects during the first nine months of 2017 and lower vessel utilization year-over-year on a pro forma basis primarily due to high vessel campaigns in Africa and Asia in the prior year that did not continue into the current year at similar levels.

Subsea operating profit as a percent of revenue decreased year-over-year on a pro forma basis due to lower revenue in our Subsea projects business across most Subsea regions.

Onshore/Offshore



	Year Ended December 31,												Favorable/(Unfavorable)
(In millions, except %)	2018			2017			2016 Pro Forma			2016			2018 vs. 2017					2017 vs. 2016 Pro Forma
Revenue	$	6,120.7		$	7,904.5		$	8,690.0		$	3,349.1		$	(1,783.8	)	(23)%		$	(785.5	)	(9)%
Operating profit	$	824.0		$	810.9		$	184.5		$	34.1		$	13.1		2%		$	626.4		340%

Operating profit as a percent of revenue	13.5		%	10.3		%	2.1		%	1.0		%				3.2	pts.				8.2	pts.

2018 Compared With 2017

Onshore/Offshore revenue decreased $1.8 billion year-over-year. The decrease was primarily driven by major projects including Yamal LNG, Silbur, and Martin Linge, that progressed towards completion. The decrease was partially offset by the Energean Karish project awarded in early 2018, FEED work for the Arctic LNG project, and increased work in our Process and Technology business.

Operating profit year-over-year was favorably impacted by reduced costs, strong project execution and bonus achievements on Yamal LNG due to completion of key milestones ahead of schedule. Additionally, 2018 was favorably impacted by $3.4 million related to settlements on restructured projects and operations.

Onshore/Offshore operating profit as a percentage of revenue increased to 13.5% compared to 2017.

Refer to ‘Non-GAAP Measures’ for further information regarding our segment operating results.

2017 Compared With 2016 Pro Forma

Onshore/Offshore revenue decreased $785.5 million year-over-year. The decrease in revenue was attributable to lower activity in North America, due to the delivery of several projects in 2016 and early 2017, as well as reduced activity in Yamal, partially offset by increases projects in Prelude FLNG and the Middle East.

Operating profit and operating profit as a percentage of revenue for the year ended 2017 were both favorable compared to the year ended 2016 on a pro forma basis in comparison and both benefited by successful progression of several major projects, including Yamal and Prelude FLNG, and the successful resolution of certain contract disputes. In addition, the year-over-year performances were favorably impacted by a decrease of $209.7 million related to impairment, restructuring and other expense.

Surface Technologies^(b)



	Year Ended December 31,									Favorable/(Unfavorable)
(In millions, except %)	2018			2017 ^(a)			2016 Pro Forma			2018 vs. 2017				2017 vs. 2016 Pro Forma
Revenue	$	1,592.2		$	1,274.6		$	1,252.2		$	317.6	25%		$	22.4	2%
Operating profit (loss)	$	172.8		$	82.7		$	(122.0	)	$	90.1	109%		$	204.7	168%

Operating profit (loss) as a percent of revenue	10.9		%	6.5		%	(9.7		)%			4.4	pts.			16.2	pts.


(a)	Due to the Merger, there were 11.5 months included in the year ended 2017 for legacy FMC Technologies, compared with twelve months in pro forma 2016. Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.


(b)	Prior to the Merger, we reported our business in two segments, Subsea and Onshore/Offshore. As a result of the Merger and the addition of FMC Technologies, we began reporting our business in three segments. As such, actual results of operations for 2016 do not include Surface Technologies.

2018 Compared With 2017

Surface Technologies revenue increased $317.6 million year-over-year primarily driven by increased activity in the North American market. The solid growth in North America reflected increased demand for flowline, hydraulic fracturing services, wellhead systems, and pressure control equipment and services. Outside of North America, revenue also increased year-over-year primarily driven by increased demand for pressure control equipment and services.

Surface Technologies operating profit as a percent of revenue increased significantly year-over-year. The increase was primarily driven by increased volume in North America and cost reductions, partially offset by continued international pricing pressure. Additionally, 2018 included $13.8 million of impairment and restructuring and other severance charges compared to $19.2 million in the prior year.

Surface Technologies operating profit as a percentage of revenue increased to 10.9% compared to 2017.

Refer to ‘Non-GAAP Measures’ for further information regarding our segment operating results.

2017 Compared With 2016 Pro Forma

Surface Technologies revenue increased $22.4 million year-over-year on a pro forma basis. Lower revenue in our surface international, measurement solutions, and loading systems businesses year-over-year on a pro forma basis was more than offset by revenue increase in our surface Americas business. The increase for surface Americas was driven primarily by a higher rig count, which had a positive impact on our flowline and well service pump revenues.

Surface Technologies operating profit as a percent of revenue increased year-over-year on a pro forma basis and was driven primarily by increased volume in flowline and well service pump products in our surface Americas business, and a $48.8 million decrease in impairment, restructuring and other severance charges.

Corporate Items



	Year Ended December 31,												Favorable/(Unfavorable)
(In millions, except %)	2018			2017			2016 Pro Forma			2016			2018 vs. 2017				2017 vs. 2016 Pro Forma
Corporate expense	$	(594.5	)	$	(359.2	)	$	(366.6	)	$	(185.9	)	$	(235.3	)	(66)%	$	7.4	2%

2018 Compared With 2017

Corporate expense increased by $235.3 million year-over-year. The increase is due primarily to a legal provision of $280.0 million recorded in 2018. See Note 18 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. Offsetting the increase was $65.3 million less integration costs and $24.4 million less restructuring costs than in 2017.

Refer to ‘Non-GAAP Measures’ for further information regarding our segment operating results.

2017 Compared With 2016 Pro Forma

Corporate expense decreased by $7.4 million year-over-year on a pro forma basis. The decrease is primarily attributable to a reduction of business combination transaction and integration costs of $34.4 million in 2017 compared to 2016 on a pro forma basis.

NON-GAAP MEASURES

In addition to financial results determined in accordance with U.S. generally accepted accounting principles (GAAP), we provide non-GAAP financial measures (as defined in Item 10 of Regulation S-K of the Securities Exchange Act of 1934, as amended) below.

Net income, excluding charges and credits, as well as measures derived from it (excluding charges and credits; Income before net interest expense and taxes, excluding charges and credits ("Adjusted Operating profit"); Depreciation and amortization, excluding charges and credits; Earnings before net interest expense, income taxes, depreciation and amortization, excluding charges and credits ("Adjusted EBITDA"); and net cash) are non-GAAP financial measures.

Management believes that the exclusion of charges and credits from these financial measures enables investors and management to more effectively evaluate TechnipFMC's operations and consolidated results of operations period-over-period, and to identify operating trends that could otherwise be masked or misleading to both investors and management by the excluded items. These measures are also used by management as performance measures in determining certain incentive compensation. The foregoing non-GAAP financial measures should be considered in addition to, not as a substitute for or superior to, other measures of financial performance prepared in accordance with GAAP.

The following is a reconciliation of the most comparable financial measures under GAAP to the non-GAAP financial measures.



	Year Ended
	December 31, 2018
	Subsea			Onshore/ Offshore			Surface Technologies			Corporate and Other			Total
Revenue	$	4,840.0		$	6,120.7		$	1,592.2		$	—		$	12,552.9

Operating profit (loss), as reported (pre-tax)	$	(1,529.5	)	$	824.0		$	172.8		$	(594.5	)	$	(1,127.2	)

Charges and (credits):
Impairment and other charges	1,784.2			—			4.5			3.9			1,792.6
Restructuring and other severance charges	17.7			(3.4		)	9.3			15.0			38.6
Business combination transaction and integration costs	—			—			—			36.5			36.5
Legal provision	—			—			—			280.0			280.0
Gain on divestitures	(3.3		)	(28.3		)	—			—			(31.6		)
Purchase price accounting adjustments - non-amortization related	(9.4		)	—			7.1			(0.2		)	(2.5		)
Purchase price accounting adjustments - amortization related	91.3			—			—			—			91.3
Subtotal	1,880.5			(31.7		)	20.9			335.2			2,204.9

Adjusted Operating profit (loss)	351.0			792.3			193.7			(259.3		)	1,077.7

Adjusted Depreciation and amortization	349.2			38.1			66.6			5.2			459.1

Adjusted EBITDA	$	700.2		$	830.4		$	260.3		$	(254.1	)	$	1,536.8

Operating profit margin	(31.6		)%	13.5		%	10.9		%				(9.0		)%

Adjusted Operating profit margin	7.3		%	12.9		%	12.2		%				8.6		%

Adjusted EBITDA margin	14.5		%	13.6		%	16.3		%				12.2		%



	Year Ended
	December 31, 2017
	Subsea			Onshore/ Offshore			Surface Technologies			Corporate and Other			Total
Revenue	$	5,877.4		$	7,904.5		$	1,274.6		$	0.4		$	15,056.9

Operating profit (loss), as reported (pre-tax)	$	460.5		$	810.9		$	82.7		$	(359.2	)	$	994.9

Charges and (credits):
Impairment and other charges	11.5			—			10.2			12.6			34.3
Restructuring and other severance charges	88.4			27.0			9.0			32.8			157.2
Business combination transaction and integration costs	—			—			—			101.8			101.8
Change in accounting estimate	11.8			—			10.1			—			21.9
Purchase price accounting adjustments - non-amortization related	40.5			—			43.3			(25.6		)	58.2
Purchase price accounting adjustments - amortization related	139.2			—			12.4			(1.2		)	150.4
Subtotal	291.4			27.0			85.0			120.4			523.8

Adjusted Operating profit (loss)	751.9			837.9			167.7			(238.8		)	1,518.7

Adjusted Depreciation and amortization	368.0			41.1			51.1			4.1			464.3

Adjusted EBITDA	$	1,119.9		$	879.0		$	218.8		$	(234.7	)	$	1,983.0

Operating profit margin	7.8		%	10.3		%	6.5		%				6.6		%

Adjusted Operating profit margin	12.8		%	10.6		%	13.2		%				10.1		%

Adjusted EBITDA margin	19.1		%	11.1		%	17.2		%				13.2		%

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)	2018		2017
Subsea	$	5,178.5	$	5,143.6
Onshore/Offshore	7,425.9		3,812.9
Surface Technologies	1,686.6		1,239.8
Total inbound orders	$	14,291.0	$	10,196.3

Order backlog - Order backlog is calculated as the estimated sales value of unfilled, confirmed customer orders at the reporting date. See “Transaction Price Allocated to the Remaining Unsatisfied Performance Obligations” in Note 4 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for more information on order backlog.



	Order Backlog December 31,
(In millions)	2018		2017
Subsea	$	5,999.6	$	6,203.9
Onshore/Offshore	8,090.5		6,369.1
Surface Technologies	469.9		409.8
Total order backlog	$	14,560.0	$	12,982.8

Subsea - Order backlog for Subsea at December 31, 2018, decreased by $204.3 million from December 31, 2017. Subsea backlog of $6.0 billion at December 31, 2018, was composed of various subsea projects, including Petrobras’ pipelay support vessel and pre-salt tree awards; the Eni Coral project; Total’s Kaombo; VNG’s Fenja; Peregrino Phase II; and BP’s Shah Deniz.

Onshore/Offshore - Onshore/Offshore order backlog at December 31, 2018, increased by $1.7 billion compared to December 31, 2017. Onshore/Offshore backlog of $8.1 billion was composed of various projects, including Yamal; Long Son EPC contract, Energean Karish project, HURL Ammonia fertilizer projects, and Neste bio-diesel expansion project in Singapore.

Non-consolidated backlog - Non-consolidated backlog reflects the proportional share of backlog related to joint ventures that is not consolidated due to our minority ownership position.



	Non-consolidated backlog
(In millions)	December 31, 2018
Subsea	$	974.0
Onshore/Offshore	1,748.5
Total order backlog	$	2,722.5

LIQUIDITY AND CAPITAL RESOURCES

Most of our cash is managed centrally and flowed through centralized bank accounts controlled and maintained by TechnipFMC in the US and in other jurisdictions to best meet the liquidity needs of our global operations. Under current U.S. law, as amended by the Tax Cuts and Jobs Act (TCJA), signed into law on December 22, 2017, any repatriation to the U.S. in the form of a dividend would be eligible for a 100% dividend received deduction and therefore would not be subject to U.S. federal income tax.

We expect to meet the continuing funding requirements of our global operations with cash generated by such operations, our commercial paper programs, and our existing revolving credit facility.

Net (Debt) Cash - Net (debt) 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 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 table provides a reconciliation of our cash and cash equivalents to net (debt) cash, utilizing details of classifications from our consolidated balance sheets.



(In millions)	December 31, 2018			December 31, 2017
Cash and cash equivalents	$	5,540.0		$	6,737.4
Short-term debt and current portion of long-term debt	(67.4		)	(77.1		)
Long-term debt, less current portion	(4,124.3		)	(3,777.9		)
Net cash	$	1,348.3		$	2,882.4

Cash Flows

Cash flows for each of the years in the three-year period ended December 31, 2018, were as follows:



	Year Ended December 31,
(In millions)	2018			2017			2016
Cash provided (required) by operating activities	$	(185.4	)	$	210.7		$	493.8
Cash provided (required) by investing activities	(460.2		)	1,250.0			3,110.5
Cash required by financing activities	(444.8		)	(1,054.8		)	(534.6		)
Effect of exchange rate changes on cash and cash equivalents	(107.0		)	62.2			21.6
Increase (decrease) in cash and cash equivalents	$	(1,197.4	)	$	468.1		$	3,091.3

Working capital	$	(759.0	)	$	(725.2	)	$	(142.7	)

Operating cash flows - During 2018, we used $185.4 million in cash flows from operating activities as compared to $210.7 million generated in 2017, resulting in a $396.1 million decrease compared to 2017. Our cash flows from operating activities in 2017 were $283.1 million lower than 2016.

Our working capital balances can vary significantly depending on the payment and delivery terms on key contracts in our portfolio of projects. The year-over-year changes in operating cash flow were primarily due to the changes in trade receivables, net and contract assets and accounts payable, trade.

Investing cash flows - Investing activities used $460.2 million of cash in 2018 primarily due to capital expenditures of $368.1 million and business acquisitions of $104.9 million.

Cash provided by investing activities in 2017 was $1,250.0 million, primarily reflecting cash acquired in the Merger. Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information related to the Merger.

Cash provided by investing activities in 2016 was $3,110.5 million, primarily reflecting cash acquired through an acquisition. Refer to Note 9 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information related to the acquisition and consolidation of legal onshore/offshore contract entities that own and account for Yamal.

Financing cash flows - Financing activities used $444.8 million in 2018. The decrease of $610.0 million in cash required for financing activities was primarily due to repayments of long-term debt in 2017.

Financing activities used $1,054.8 million in 2017. The increase of $520.2 million in cash required for financing activities was primarily due to a decrease in proceeds from the issuance of long-term debt in 2016, an increase in settlements on mandatorily redeemable liability, and an increase in payments of taxes withheld on share-based compensation, offset by increased borrowings of our commercial paper during 2017.

Debt and Liquidity

Total borrowings at December 31, 2018 and 2017, comprised the following:



(In millions)	December 31, 2018			December 31, 2017
Revolving credit facility	$	—		$	—
Bilateral credit facilities	—			—
Commercial paper	1,916.1			1,450.4
Synthetic bonds due 2021	490.9			502.4
3.45% Senior Notes due 2022	500.0			500.0
5.00% Notes due 2020	229.0			239.9
3.40% Notes due 2022	171.8			179.9
3.15% Notes due 2023	148.9			155.9
3.15% Notes due 2023	143.1			149.9
4.00% Notes due 2027	85.9			89.9
4.00% Notes due 2032	114.5			119.9
3.75% Notes due 2033	114.5			119.9
Bank borrowings	265.2			332.5
Other	23.2			28.2
Unamortized debt issuance costs and discounts	(11.4		)	(13.8		)
Total borrowings	$	4,191.7		$	3,855.0

The following is a summary of our revolving credit facility at December 31, 2018:



(In millions) Description	Amount		Debt Outstanding		Commercial Paper Outstanding (a)		Letters of Credit		Unused Capacity		Maturity
Five-year revolving credit facility	$	2,500.0	$	—	$	1,916.1	$	—	$	583.9	January 2023


(a)	Under our commercial paper program, we have the ability to access up to $1.5 billion and €1.0 billion of financing through our commercial paper dealers. Our available capacity under our revolving credit facility is reduced by any outstanding commercial paper.

Committed credit available under our revolving credit facility provides the ability to issue our commercial paper obligations on a long-term basis. We had $1,916.1 million of commercial paper issued under our facilities at December 31, 2018. 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 debt in the accompanying consolidated balance sheets at December 31, 2018.

Our revolving credit facility contains customary covenants as defined by the credit facility agreement which includes a financial covenant requiring that our total capitalization ratio not exceed 60% at the end of any financial quarter. The facility agreement also contains covenants restricting our ability and our subsidiaries ability to incur additional liens and indebtedness, enter into asset sales, make certain investments. As of December 31, 2018, we were in compliance with all restrictive covenants under our revolving credit facility.

Refer to Note 13 and Note 14 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for further information related to our credit facility and our mandatorily redeemable liability, respectively.

Credit Risk Analysis

Valuations of derivative assets and liabilities reflect the fair value of the instruments, including the values associated with counterparty risk. These values must also take into account our credit standing, thus including in the valuation of the derivative instrument and the value of the net credit differential between the counterparties to the derivative contract. Our methodology includes the impact of both counterparty and our own credit standing. Adjustments to our derivative assets and liabilities related to credit risk were not material for any period presented.

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

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

Additional information about credit risk is incorporated herein by reference to Note 22 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Outlook

Historically, we have generated our liquidity and capital resources primarily through operations and, when needed, through our credit facility. We have $583.9 million of capacity available under our revolving credit facility that we expect to utilize if working capital needs temporarily increase. The volatility in credit, equity and commodity markets creates some uncertainty for our business. Any payment deferrals or discounts on pricing granted to clients in prior years may adversely affect our results of operations and cash flows in 2019 and beyond.

We project spending approximately $350 million in 2019 for capital expenditures. However, projected capital expenditures for 2019 do not include any contingent capital that may be needed to respond to a contract award.

We implemented a U.K. court-approved reduction of our capital, which was completed on June 29, 2017, in order to create distributable profits to support the payment of future dividends or future share repurchases. Our board of directors authorized $500 million for the repurchase of shares which was completed in 2018. The Board of Directors authorized an extension of this program, adding $300 million in December 2018 for a total of $800 million in ordinary shares. Also, on October 23, 2018, it was announced that our Board of Directors authorized and declared a quarterly cash dividend of $0.13 per ordinary share.

During 2019, we expect to make contributions of approximately $2.7 million to our international pension plans, representing primarily the Netherlands qualified pension plans and U.K. 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 during the fourth quarter or more frequently upon the occurrence of significant events. We do not expect to make any contributions to our U.S. Qualified Pension Plan and our U.S. Non-Qualified Defined Benefit Pension Plan in 2019.

CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual obligations at December 31, 2018:



	Payments Due by Period
(In millions)	Total payments		Less than 1 year		1-3 years		3-5 years		After 5 years
Debt ^(a)	$	4,191.7	$	67.4	$	2,854.2	$	962.9	$	307.2
Interest on debt^(a)	394.8		60.6		121.1		93.7		119.4
Operating leases ^(b)	1,519.7		329.8		478.4		225.9		485.6
Purchase obligations ^(c)	3,766.1		3,211.8		552.0		0.4		1.9
Pension and other post-retirement benefits ^(d)	14.5		14.5		—		—		—
Unrecognized tax benefits ^(e)	93.8		1.3		69.1		23.4		—
Other contractual obligations ^(f)	1,028.3		358.3		400.0		220.0		50.0
Total contractual obligations	$	11,008.9	$	4,043.7	$	4,474.8	$	1,526.3	$	964.1


(a)	Our available 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 2018, we paid $99.0 million for interest charges, net of interest capitalized.

(b)

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. In addition, 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 $2.7 million to our international pension plans during 2019. Required contributions for future years depend on factors that cannot be determined at this time. Additionally, we expect to pay directly to beneficiaries approximately $9.0 million for international unfunded pension plan and $5.5 million for U.S. Non-Qualified unfunded pension plan during 2019.


(e)	It is reasonably possible that $1.3 million of liabilities for unrecognized tax benefits will be settled during 2019, and this amount is reflected in income taxes payable in our consolidated balance sheet as of December 31, 2018. Although unrecognized tax benefits are not contractual obligations, they are presented in this table because they represent demands on our liquidity.

(f)

Other contractual obligations represent a mandatorily redeemable financial liability. In the fourth quarter of 2016, we obtained voting control interests in legal onshore/offshore contract entities which own and account for the design, engineering and construction of the Yamal LNG plant. Prior to the amendments of the contractual terms that provided us with voting interest control, we accounted for these entities under the equity method of accounting based on our previously held interests in each of these entities. A mandatorily redeemable financial liability of $174.8 million was recognized as of December 31, 2016 to account for the fair value of the non-controlling interests. During the year ended December 31, 2018 we revalued the liability to reflect current expectations about the obligation. Refer to Note 22 for further information regarding the fair value measurement assumptions of the mandatorily redeemable financial liability and related changes in its fair value.

OTHER OFF-BALANCE SHEET ARRANGEMENTS

The following is a summary of other off-balance sheet arrangements at December 31, 2018:



	Amount of Commitment Expiration per Period
(In millions)	Total amount		Less than 1 year		1-3 years		3-5 years		After 5 years
Letters of credit and bank guarantees ^(a)	$	4,796.9	$	1,932.5	$	2,024.5	$	670.4	$	169.5
Surety bonds ^(a)	1.1		1.1		—		—		—
Total other off-balance sheet arrangements	$	4,798.0	$	1,933.6	$	2,024.5	$	670.4	$	169.5

(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.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with GAAP 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.

Revenue Recognition

The majority of our revenue is derived from long-term contracts that can span several years. We account for revenue in accordance with Accounting Standard Codification (“ASC”) Topic 606, Revenues from Contracts with Customers. The unit of account in ASC Topic 606 is a performance obligation. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. Our performance obligations are satisfied over time as work progresses or at a point in time.

A significant portion of our total revenue recognized over time relates to our Onshore/Offshore and Subsea segments, primarily for the entire range of onshore facilities, fixed and floating offshore oil and gas facilities, and subsea exploration and production equipment projects that involve the design, engineering, manufacturing, construction, and assembly of complex, customer-specific systems. Because of control transferring over time, revenue is recognized based on the extent of progress towards completion of the performance obligation. The selection of the method to measure progress towards completion requires judgment and is based on the nature of the products or services to be provided. We generally use the cost-to-cost measure of progress for our contracts because it best depicts the transfer of control to the customer that occurs as we incur costs on our contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of costs incurred to date to the total estimated costs at completion of the performance obligation. Revenues, including estimated fees or profits, are recorded proportionally as costs are incurred.

Due to the nature of the work required to be performed on many of our performance obligations, the estimation of total revenue and cost at completion is complex, subject to many variables, and requires significant judgment. It is common for our long-term contracts to contain award fees, incentive fees, or other provisions that can either increase or decrease the transaction price. We include estimated amounts in the transaction price when we believe we have an enforceable right to the modification, the amount can be estimated reliably, and its realization is probable. The estimated amounts are included in the transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is resolved.

We execute contracts with our customers that clearly describe the equipment, systems, and/or services. 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.

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 long-term contracts 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 over time is sensitive to changes in our estimates of total contract costs. There are many factors, including, but not limited to, the ability to properly execute the engineering and design phases consistent with our customers’ expectations, the availability and costs of labor and material resources, productivity, and weather, all of which can affect the accuracy of our cost estimates, and ultimately, our future profitability.

Our operating profit for the year ended December 31, 2018 was negatively impacted by approximately $6.7 million, as a result of changes in contract estimates related to projects that were in progress at December 31, 2017. During the year ended December 31, 2018, we recognized changes in our estimates that had an impact on our margin in the amounts of $(5.1) million, $(5.9) million and $4.3 million in our Onshore/Offshore, Subsea and Surface technologies segments, respectively. The changes in contract estimates are attributed to better than expected performance throughout our execution of our projects.

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 Kingdom 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 a valuation allowance to reduce 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 our judgment related to the expected realizability of a deferred tax asset results in an adjustment to the associated valuation allowance.

As of December 31, 2018, we have provided a valuation allowance against the related deferred tax assets where we believe it is more likely than not that we will generate future taxable income in jurisdictions in which we have cumulative net operating losses.

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

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 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.

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 2018 Pension Expense Before Income Taxes			Increase (Decrease) in Projected Benefit Obligation at December 31, 2018
25 basis point decrease in discount rate	$	1.1		$	48.2
25 basis point increase in discount rate	$	(1.0	)	$	(49.0	)
25 basis point decrease in expected long-term rate of return on plan assets	$	2.6		N/A
25 basis point increase in expected long-term rate of return on plan assets	$	(2.6	)	N/A

Determination of Fair Value in Business Combinations

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets acquired and liabilities assumed at their respective fair values. The determination of fair value requires the use of significant estimates and assumptions, and in making these determinations, management uses all available information. If necessary, we have up to one year after the acquisition closing date to finalize these fair value determinations. For tangible and identifiable intangible assets acquired in a business combination, the determination of fair value utilizes several valuation methodologies including discounted cash flows which has assumptions with respect to the timing and amount of future revenue and expenses associated with an asset. The assumptions made in performing these valuations include, but are not limited to, discount rates, future revenues and operating costs, projections of capital costs, and other assumptions believed to be consistent with those used by principal market participants. Due to the specialized nature of these calculations, we engage third-party specialists to assist management in evaluating our assumptions as well as appropriately measuring the fair value of assets acquired and liabilities assumed. Business combinations are described in Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Impairment of Long-Lived and Intangible Assets

Long-lived assets, including vessels, 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. If future market conditions deteriorate beyond our current expectations and assumptions, impairments of long-lived assets may be identified if we conclude that the carrying amounts are no longer recoverable.

Impairment of Goodwill

Goodwill represents the excess of cost over the fair market value of net assets acquired in business combinations. Goodwill is not subject to amortization but is tested for impairment on an annual basis at a reporting level unit, or more frequently if impairment indicators arise. We have established October 31 as the date of our annual test for impairment of goodwill. We identify a potential impairment by comparing the fair value of the applicable reporting unit to its net book value, including goodwill. If the net book value exceeds the fair value of the reporting unit, we measure the impairment by comparing the carrying value of the reporting unit to its fair value. Reporting units with goodwill are tested for impairment using a quantitative impairment test.

When using the quantitative impairment test, determining the fair value of a reporting unit is judgmental in nature and involves the use of significant estimates and assumptions. We estimate the fair value of our reporting units using a discounted future cash flow model. The majority of the estimates and assumptions used in a discounted future cash flow model involve unobservable inputs reflecting management’s own assumptions about the assumptions market participants would use in estimating the fair value of a business. These estimates and assumptions include revenue growth rates and operating margins used to calculate projected future cash flows, discount rates and future economic and market conditions. Our estimates are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable and do not reflect unanticipated events and circumstances that may occur.

A lower fair value estimate in the future for any of our reporting units 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 based on internal forecasts of revenues and expenses over a specified period plus a terminal value (the income approach). When assessing triggering factors, on a quarterly and also on an annual basis, we also analyze the relationship between our market capitalization and our consolidated book value of equity.

The income approach estimates fair value by discounting each reporting unit’s estimated future cash flows using a weighted-average cost of capital that reflects current market conditions and the risk profile of the reporting unit. To arrive at our future cash flows, we use estimates of economic and market assumptions, including growth rates in revenues, costs, estimates of future expected changes in operating margins, tax rates and cash expenditures. Future revenues are also adjusted to match changes in our business strategy. We believe this approach is an appropriate valuation method. Under the market multiple approach, we determine the estimated fair value of each of our reporting units by applying transaction multiples to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using either a one, two or three year average. Our reporting unit valuations were determined primarily by utilizing the income approach, with a lesser weighting attributed the market multiple approach.

Late in the fourth quarter of 2018, oil prices fell dramatically and our market capitalization declined significantly, together with other companies in the oil service industry. This short-term event is not expected to have significant negative impact on our short-term performance and it is not changing materially our medium-term and long-term cash flow projections.

The excess of fair value over carrying amount for our Surface Technologies and Onshore/Offshore reporting units ranged from approximately 56% to in excess of 200% of the respective carrying amounts.

During the year ended December 31, 2018, we recorded $1,383.0 million of goodwill impairment charges in our Subsea reporting unit. Refer to Note 17 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional disclosure related to the impairment of goodwill during the year ended December 31, 2018.

The following table presents the significant estimates used by management in determining the fair values of our reporting units at December 31, 2018:



	2018
Year of cash flows before terminal value	5
Discount rates	12.0% to 13.0%
EBITDA multiples	7.0 - 8.5x

Refer to Note 12 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to goodwill impairment testing during 2018.

OTHER MATTERS

On March 28, 2016, FMC Technologies received an inquiry from the U.S. Department of Justice ("DOJ") related to the DOJ's investigation of whether certain services Unaoil S.A.M. provided to its clients, including FMC Technologies, violated the U.S. Foreign Corrupt Practices Act ("FCPA"). On March 29, 2016, Technip S.A. also received an inquiry from the DOJ related to Unaoil. We are cooperating with the DOJ's investigations and, with regard to FMC Technologies, a related investigation by the U.S. Securities and Exchange Commission.

In late 2016, Technip S.A. was contacted by the DOJ regarding its investigation of offshore platform projects awarded between 2003 and 2007, performed in Brazil by a joint venture company in which Technip S.A. was a minority participant, and we have also raised with DOJ certain other projects performed by Technip S.A. subsidiaries in Brazil between 2002 and 2013. The DOJ has also inquired about projects in Ghana and Equatorial Guinea that were awarded to Technip S.A. subsidiaries in 2008 and 2009, respectively. We are cooperating with the DOJ in its investigation into potential violations of the FCPA in connection with these projects. We have contacted the Brazilian authorities (Federal Prosecution Service (MPF), the Comptroller General of Brazil (CGU) and the Attorney General of Brazil (AGU)) and are cooperating with their investigation concerning the projects in Brazil and have also contacted French authorities (the Parquet National Financier (PNF)) about these existing matters.

We have been informed that these authorities in Brazil, the U.S. and France have been coordinating their investigations, which could result in a global resolution. These matters have progressed to a point where a probable estimate of the aggregate settlement amount with all authorities is $280.0 million for which we have taken a provision in the fourth quarter and year ended December 31, 2018.

These matters involve negotiations with law enforcement authorities in three separate jurisdictions, and there is no certainty that a global settlement will be reached or that the settlement will not exceed current accruals. These authorities have a broad range of civil and criminal sanctions under anticorruption laws and regulations, which they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, fines, penalties and modifications to business practices and compliance programs. These authorities have entered into agreements with, and obtained a range of sanctions against, numerous public corporations and individuals arising from allegations of improper payments whereby civil and/or criminal penalties were imposed. Recent civil and criminal settlements have included fines, deferred prosecution agreements, guilty pleas and other sanctions, including the requirement that the relevant corporation retain a monitor to oversee its compliance with anticorruption laws. Any of these remedial measures, if applicable to us, as well as potential customer reaction to such remedial measures, could have a material adverse impact on our business, results of operations and financial condition.

RECENTLY ISSUED ACCOUNTING STANDARDS

Refer to Note 3 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, 2018 and December 31, 2017, 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, 2018, would have changed our revenue and income before income taxes attributable to TechnipFMC by approximately $134.6 million and $5.7 million, 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 derivative 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 of these assets and liabilities 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.

For our foreign currency forward contracts hedging anticipated transactions that are accounted for as cash flow hedges, a 10% increase in the value of the U.S. dollar would have resulted in an additional loss of $50.7 million in the net fair value of cash flow hedges reflected in our consolidated balance sheet at December 31, 2018.

Interest Rate Risk

At December 31, 2018, we had commercial paper of approximately $1.9 billion with a weighted average interest rate of 1.82%. Using sensitivity analysis to measure the impact of a 10% adverse movement in the interest rate, or eighteen basis points, would result in an increase to interest expense of $3.5 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 $1.1 million in unrealized earnings in the period of change. Based on our portfolio as of December 31, 2018, we have material positions with exposure to 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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of TechnipFMC plc

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of TechnipFMC plc and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of income, comprehensive income, changes in stockholders’ equity, and cash flows for the years then ended, including the related notes and financial statement schedule of valuation and qualifying accounts for the years ended December 31, 2018 and 2017 appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two years then ended in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the COSO because material weaknesses in internal control over financial reporting existed as of that date related to the design and operating effectiveness of internal controls over (i) the period end financial reporting process, and (ii) the accounting for income taxes.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses referred to above are described in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. We considered these material weaknesses in determining the nature, timing and extent of audit tests applied in our audit of the 2018 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in management’s report referred to above. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting were maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 11, 2019

We have served as the Company's auditor since 2017.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of TechnipFMC plc

In our opinion, the accompanying consolidated statements of income, comprehensive income, cash flows and changes in stockholders’ equity for the year ended December 31, 2016 present fairly, in all material respects, the results of operations and cash flows of TechnipFMC plc and its subsidiaries for the year ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the year ended December 31, 2016 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these financial statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers Audit

Paris, France

April 2, 2018

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



	Year Ended
(In millions, except per share data)	2018			2017			2016
Revenue
Service revenue	$	9,765.0		$	12,210.5		$	9,128.7
Product revenue	2,565.2			2,651.8			70.9
Lease and other revenue	222.7			194.6			—
Total revenue	12,552.9			15,056.9			9,199.6

Costs and expenses
Cost of service revenue	7,895.1			9,984.0			7,585.7
Cost of product revenue	2,234.5			2,403.4			44.3
Cost of lease and other revenue	143.4			137.2			—
Selling, general and administrative expense	1,140.6			1,060.9			572.6
Research and development expense	189.2			212.9			105.4
Impairment, restructuring and other expense (Note 17)	1,831.2			191.5			343.0
Merger transaction and integration costs (Note 2)	36.5			101.8			92.6
Total costs and expenses	13,470.5			14,091.7			8,743.6

Other income (expense), net	(323.9		)	(25.9		)	6.5
Income from equity affiliates (Note 9)	114.3			55.6			117.7
Income before interest income, interest expense and income taxes	(1,127.2		)	994.9			580.2
Interest income	121.4			140.8			85.3
Interest expense	(482.3		)	(456.0		)	(114.1		)
Income (loss) before income taxes	(1,488.1		)	679.7			551.4
Provision for income taxes (Note 19)	422.7			545.5			180.3
Net income (loss)	(1,910.8		)	134.2			371.1
Net (income) loss attributable to noncontrolling interests	(10.8		)	(20.9		)	22.2
Net income (loss) attributable to TechnipFMC plc	$	(1,921.6	)	$	113.3		$	393.3

Earnings (loss) per share attributable to TechnipFMC plc (Note 6)
Basic	$	(4.20	)	$	0.24		$	3.29
Diluted	$	(4.20	)	$	0.24		$	3.16
Weighted average shares outstanding (Note 6)
Basic	458.0			466.7			119.4
Diluted	458.0			468.3			125.1

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

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended
(In millions)	2018			2017			2016
Net income (loss)	$	(1,910.8	)	$	134.2		$	371.1
Foreign currency translation adjustments
Net gain (losses) arising during the period	(183.3		)	(87.2		)	(71.4		)
Reclassification adjustment for net gains included in net income	(41.1		)	—			—
Net gains (losses) on foreign currency translation adjustments^(a)	(224.4		)	(87.2		)	(71.4		)

Net gains (losses) on hedging instruments
Net gains (losses) arising during the period	(58.7		)	53.8			(64.8		)
Reclassification adjustment for net gains included in net income	(2.0		)	101.2			120.1
Net gains (losses) on hedging instruments ^(b)	(60.7		)	155.0			55.3

Pension and other post-retirement benefits
Net gains arising during the period	(72.4		)	43.2			7.0
Prior service cost arising during the period	(2.1		)	—			—
Reclassification adjustment for settlement losses included in net income	(2.5		)	(15.2		)	(7.4		)
Reclassification adjustment for amortization of prior service cost included in net income	1.2			0.7			0.5
Reclassification adjustment for amortization of net actuarial loss included in net income	0.3			1.8			0.7
Net pension and other post-retirement benefits ^(c)	(75.5		)	30.5			0.8
Other comprehensive income (loss), net of tax	(360.6		)	98.3			(15.3		)
Comprehensive income (loss)	(2,271.4		)	232.5			355.8
Comprehensive (income) loss attributable to noncontrolling interest	(6.2		)	(21.3		)	20.9
Comprehensive income (loss) attributable to TechnipFMC plc	$	(2,277.6	)	$	211.2		$	376.7


(a)	Net of income tax (expense) benefit of $3.6, $(11.5) and nil for the years ended December 31, 2018, 2017 and 2016, respectively.


(b)	Net of income tax (expense) benefit of $16.6, $(52.5) and $(24.3) for the years ended December 31, 2018, 2017 and 2016, respectively.


(c)	Net of income tax (expense) benefit of $15.5, $(11.7) and $1.0 for the years ended December 31, 2018, 2017 and 2016, respectively.

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

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

(In millions, except par value data)	December 31,
Assets	2018				2017
Cash and cash equivalents	$	5,540.0			$	6,737.4
Trade receivables, net of allowances of $119.6 in 2018 and $117.4 in 2017	2,469.7				1,484.4
Contract assets	1,295.0				1,755.5
Inventories, net (Note 7)	1,251.2				987.0
Derivative financial instruments (Note 21)	95.7				78.3
Income taxes receivable	284.3				337.0
Advances paid to suppliers	189.7				391.3
Other current assets (Note 8)	655.6				1,206.2
Total current assets	11,781.2				12,977.1
Investments in equity affiliates (Note 9)	394.5				272.5
Property, plant and equipment, net (Note 11)	3,259.8				3,871.5
Goodwill (Note 12)	7,607.6				8,929.8
Intangible assets, net (Note 12)	1,176.7				1,333.8
Deferred income taxes (Note 19)	232.4				454.7
Derivative financial instruments (Note 21)	18.3				94.9
Other assets	314.0				329.4
Total assets	$	24,784.5			$	28,263.7

Liabilities and equity
Short-term debt and current portion of long-term debt (Note 13)	$	67.4			$	77.1
Accounts payable, trade	2,600.3				3,958.7
Contract liabilities	4,085.1				3,314.2
Accrued payroll	394.7				402.2
Derivative financial instruments (Note 21)	138.4				69.0
Income taxes payable	81.9				320.3
Other current liabilities (Note 8)	1,766.6			—	1,687.9
Total current liabilities	9,134.4				9,829.4
Long-term debt, less current portion (Note 13)	4,124.3				3,777.9
Deferred income taxes (Note 19)	209.2				419.7
Accrued pension and other post-retirement benefits, less current portion (Note 20)	298.9				282.0
Derivative financial instruments (Note 21)	44.9				68.1
Other liabilities	503.4				477.2
Total liabilities	14,315.1				14,854.3
Commitments and contingent liabilities (Note 18)
Mezzanine equity
Redeemable noncontrolling interest	38.5				—
Stockholders’ equity (Note 15)
Ordinary shares, $1.00 par value; 618.3 shares and 525.0 shares authorized in 2018 and 2017, respectively; 450.5 shares and 465.1 shares issued and outstanding in 2018 and 2017, respectively; 14.8 and 2.1 shares canceled in 2018 and 2017, respectively	450.5				465.1
Ordinary shares held in employee benefit trust, at cost; 0.1 and 0.1 shares in 2018 and 2017, respectively	(2.4		)		(4.8		)
Capital in excess of par value of ordinary shares	10,197.0				10,483.3
Retained earnings	1,114.2				3,448.0
Accumulated other comprehensive loss	(1,359.7		)		(1,003.7		)
Total TechnipFMC plc stockholders’ equity	10,399.6				13,387.9
Noncontrolling interests	31.3				21.5
Total equity	10,430.9				13,409.4
Total liabilities and equity	$	24,784.5			$	28,263.7

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

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
(In millions)	2018			2017			2016
Cash provided (required) by operating activities
Net income (loss)	$	(1,910.8	)	$	134.2		$	371.1
Adjustments to reconcile net income to cash provided (required) by operating activities
Depreciation	367.8			370.2			283.2
Amortization	182.6			244.5			17.5
Employee benefit plan and share-based compensation costs	22.4			18.7			27.4
Deferred income tax provision (benefit), net	48.8			141.6			(172.1		)
Unrealized loss (gain) on derivative instruments and foreign exchange	102.7			(73.5		)	(123.2		)
Impairments (Note 17)	1,792.6			34.3			38.2
Income from equity affiliates, net of dividends received	(110.7		)	(37.9		)	(48.1		)
Other	291.8			4.7			161.8
Changes in operating assets and liabilities, net of effects of acquisitions
Trade receivables, net and contract assets	(664.1		)	286.8			(268.7		)
Inventories, net	(339.4		)	130.9			172.7
Accounts payable, trade	(1,248.7		)	(525.8		)	115.5
Contract liabilities	762.7			(1,111.4		)	(498.3		)
Income taxes payable (receivable), net	(190.7		)	(152.2		)	71.7
Other current assets and liabilities, net	921.2			646.5			264.4
Other noncurrent assets and liabilities, net	(213.6		)	99.1			80.7
Cash provided (required) by operating activities	(185.4		)	210.7			493.8

Cash provided (required) by investing activities
Capital expenditures	(368.1		)	(255.7		)	(312.9		)
Cash acquired in merger of FMC Technologies, Inc. and Technip S.A. (Note 2)	—			1,479.2			—
Acquisitions, net of cash acquired	(104.9		)	—			—
Cash acquired upon consolidation of investee	—			—			3,480.7
Cash divested from deconsolidation	(6.7		)	—			(89.1		)
Proceeds from sale of assets	19.5			14.4			39.2
Other	—			12.1			(7.4		)
Cash provided (required) by investing activities	(460.2		)	1,250.0			3,110.5

Cash provided (required) by financing activities
Net increase (decrease) in short-term debt	(34.9		)	(106.4		)	8.6
Net increase in commercial paper	496.6			234.9			—
Proceeds from issuance of long-term debt	—			25.7			644.5
Repayments of long-term debt	—			(888.0		)	(891.2		)
Purchase of ordinary shares	(442.6		)	(58.5		)	(186.8		)
Dividends paid	(238.1		)	(60.6		)	(111.5		)
Payments related to taxes withheld on share-based compensation	—			(46.6		)	—
Settlements of mandatorily redeemable financial liability	(225.8		)	(156.5		)	—
Other	—			1.2			1.8
Cash provided (required) by financing activities	(444.8		)	(1,054.8		)	(534.6		)
Effect of changes in foreign exchange rates on cash and cash equivalents	(107.0		)	62.2			21.6
Increase (decrease) in cash and cash equivalents	(1,197.4		)	468.1			3,091.3
Cash and cash equivalents, beginning of year	6,737.4			6,269.3			3,178.0
Cash and cash equivalents, end of year	$	5,540.0		$	6,737.4		$	6,269.3



	Year Ended December 31,
(In millions)	2018		2017		2016
Supplemental disclosures of cash flow information
Cash paid for interest (net of interest capitalized)	$	99.0	$	50.3	$	40.2
Cash paid for income taxes (net of refunds received)	$	410.6	$	424.7	$	261.3

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

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY



(In millions)	Ordinary Shares			Ordinary Shares Held in Treasury and Employee Benefit Trust			Capital in Excess of Par Value of Ordinary Shares			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interest			Total Stockholders’ Equity
Balance as of December 31, 2015	$	114.5		$	(81.1	)	$	2,725.4		$	3,273.4		$	(1,085.0	)	$	9.2		$	4,956.4
Net income (loss)	—			—			—			393.3			—			(22.2		)	371.1
Other comprehensive income (loss)	—			—			—			—			(16.6		)	1.3			(15.3		)
Net capital transactions	0.2			—			(35.1		)	—			—			—			(34.9		)
Treasury shares (Note 15)	—			36.6			(31.1		)	—			—			—			5.5
Dividends (€2.00 per share) (Note 15)	—			—			—			(262.6		)	—			—			(262.6		)
Share-based compensation (Note 16)	—			—			22.0			—			—			—			22.0
Other	—			—			1.9			—			—			—			1.9
Balance as of December 31, 2016	$	114.7		$	(44.5	)	$	2,683.1		$	3,404.1		$	(1,101.6	)	$	(11.7	)	$	5,044.1
Net income (loss)	—			—			—			113.3			—			20.9			134.2
Other comprehensive income (loss)	—			—			—			—			97.9			0.4			98.3
Issuance of ordinary shares due to the merger of FMC Technologies and Technip	351.9			(6.6		)	7,825.4			—			—			—			8,170.7
Cancellation of treasury shares due to the merger of FMC Technologies and Technip	—			44.5			(23.3		)	—			—			—			21.2
Cancellation treasury shares (Note 15)	(2.1		)	—			(47.6		)	(8.8		)	—			—			(58.5		)
Net sales of ordinary shares for employee benefit trust	—			1.8			—			—			—			—			1.8
Issuance of ordinary shares	0.6			—			0.6			—			—			—			1.2
Dividends ($0.13 per share) (Note 15)	—			—			—			(60.6		)	—			—			(60.6		)
Share-based compensation (Note 16)	—			—			44.4			—			—			—			44.4
Other	—			—			0.7			—			—			11.9			12.6
Balance as of December 31, 2017	$	465.1		$	(4.8	)	$	10,483.3		$	3,448.0		$	(1,003.7	)	$	21.5		$	13,409.4
Adoption of accounting standards (Note 4)	—			—			—			(91.5		)	—			0.1			(91.4		)
Net income (loss)	—			—			—			(1,921.6		)	—			10.8			(1,910.8		)
Other comprehensive income (loss)	—			—			—			—			(356.0		)	(4.6		)	(360.6		)
Cancellation of treasury shares (Note 15)	(14.8		)	—			(333.5		)	(94.5		)	—			—			(442.8		)
Issuance of ordinary shares	0.2			—			—			—			—			—			0.2
Net sales of ordinary shares for employee benefit trust	—			2.4			—			—			—			—			2.4
Dividends ($0.52 per share) (Note 15)	—			—			—			(238.1		)	—			—			(238.1		)
Share-based compensation (Note 16)	—			—			49.1			—			—			—			49.1
Other	—			—			(1.9		)	11.9			—			3.5			13.5
Balance as of December 31, 2018	$	450.5		$	(2.4	)	$	10,197.0		$	1,114.2		$	(1,359.7	)	$	31.3		$	10,430.9

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

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Nature of operations - TechnipFMC plc and consolidated subsidiaries (“TechnipFMC,” “we,” “us” or “our”) is a global leader in oil and gas projects, technologies, systems and services through our business segments: Subsea, Onshore/Offshore and Surface Technologies. 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 accounting principles generally accepted in the United States of America (“GAAP”) and rules and regulations of the Securities and Exchange Commission (“SEC”) pertaining to annual financial information. The preparation of financial statements in conformity with these accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Ultimate results could differ from our estimates. Certain prior-year amounts have been reclassified to conform to the current year’s presentation.

In this Annual Report on Form 10-K, we are reporting the results of our operations for the year ended December 31, 2018, which consist of the combined results of operations of Technip S.A. (“Technip”) and FMC Technologies, Inc. (“FMC Technologies”). Due to the merger of FMC Technologies and Technip, FMC Technologies’ results of operations have been included in our financial statements for periods subsequent to the consummation of the merger on January 16, 2017.

Since TechnipFMC is the successor company to Technip, we are presenting the results of Technip’s operations for the year ended December 31, 2016. Refer to Note 2 for further information related to the merger of FMC Technologies and Technip.

Principles of consolidation - The consolidated financial statements include the accounts of TechnipFMC 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 of fair value in business combinations and estimates related to income taxes.

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 affiliates’ operating and financial policies. The cost method of accounting is used where significant influence over the affiliate is not present. For certain construction joint ventures, we use the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.

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 subjectively 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.

Investments in which ownership is less than 20% or that do not represent significant investments are reported in other assets on the consolidated balance sheets. Where no active market exists and where no other valuation method can be used, these financial assets are maintained at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer.

We determine whether investments involve a variable interest entity (“VIE”) based on the characteristics of the subject entity. If the entity is determined to be a VIE, then management determines if we are the primary beneficiary of the entity and whether or not consolidation of the VIE is required. The primary beneficiary consolidating the VIE must normally have both (i) the power to direct the activities that most significantly affect the VIE’s economic performance and (ii) the obligation to absorb significant losses of or the right to receive significant benefits from the VIE. If we are deemed to be the primary beneficiary, the VIE is consolidated and the other party’s equity interest in the VIE is accounted for as a noncontrolling interest. Our unconsolidated VIEs are accounted for using the equity method of accounting.

Business combinations - Business combinations are accounted for using the acquisition method of accounting. Under the acquisition method, assets acquired and liabilities assumed are recorded at their respective fair values as of the acquisition date. Determining the fair value of assets and liabilities involves significant judgment regarding methods and assumptions used to calculate estimated fair values. The purchase price is allocated to the assets, assumed liabilities and identifiable intangible assets based on their estimated fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Transaction related costs are expensed as incurred.

Revenue recognition - The majority of our revenue is derived from long-term contracts that can span several years. We account for revenue in accordance with Accounting Standard Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, which we adopted on January 1, 2018, using the modified retrospective method. Refer to Note 4 for further discussion of the adoption, including the impact on our 2018 financial statements.

Contract costs to obtain a contract - Our incremental direct costs of obtaining a contract are deferred and amortized over the period of contract performance or a longer period, generally the estimated life of the customer relationship, if renewals are expected and the renewal commission is not commensurate with the initial commission. We classify deferred commissions as current or noncurrent based on the timing of when we expect to recognize the expense. The current and noncurrent portions of deferred commissions are included in other current assets and other assets, respectively, in our consolidated balance sheets.

Amortization of deferred commissions is included in selling, general and administrative expenses.

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

Trade 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 receivables balance.

Inventories - Inventories are stated at the lower of cost or net realizable value, except as it relates to inventory measured using the last-in, first-out (“LIFO”) method, for which the 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 for a significant portion of the U.S. domiciled inventories is determined on the LIFO method. The first-in, first-out (“FIFO”) or weighted average methods are used to determine the cost for the remaining inventories. Write-down on inventories are recorded when the net realizable value of inventories is lower than their net book value.

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 (vessels - 10 to 30 years; buildings - 10 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 an asset group 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.

Goodwill - Goodwill is not subject to amortization but is tested for impairment on an annual basis (or more frequently if impairment indicators arise) by comparing the estimated fair value of each reporting unit to its carrying value, including goodwill. A reporting unit is defined as an operating segment or one level below the operating segment. We have established October 31 as the date of our annual test for impairment of goodwill. Reporting units with goodwill are tested for impairment using a quantitative impairment test known as the income approach, which estimates fair value by discounting each reporting unit’s estimated future cash flows using a weighted-average cost of capital that reflects current market conditions and the risk profile of the reporting unit. To arrive at our future cash flows, we use estimates of economic and market assumptions, including growth rates in revenues, costs, estimates of future expected changes in operating margins, tax rates and cash expenditures. Future revenues are also adjusted to match changes in our business strategy. If the fair value of the reporting unit is less than its carrying amount as a result of this method, then an impairment loss is recorded.

Intangible assets - Our acquired intangible assets are generally amortized on a straight-line basis over their estimated useful lives, which generally range from 2 to 20 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.

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. 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.

Research and development expense is expensed as incurred. Research and development expense includes improvement of existing products and services, design and development of new products and services and test of new technologies.

Debt instruments - Debt instruments include synthetic bonds, senior and private placement notes and other borrowings. Issuance fees and redemption premium on debt instruments are included in the cost of debt in the consolidated balance sheets, as an adjustment to the nominal amount of the debt. Loan origination costs for revolving credit facilities are recorded as an asset and amortized over the life of the underlying debt.

Fair value measurements - 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 measured at fair value 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 basis 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.

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. 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.

Share-based employee compensation - The measurement of share-based compensation expense on restricted share awards and performance share awards is based on the market price at the grant date and the number of shares awarded. We used the Cox Ross Rubinstein binomial model to measure the fair value of stock options granted prior to December 31, 2016 and Black-Scholes options pricing model to measure the fair value of stock options granted on or after January 1, 2017. The stock-based compensation expense for each award is recognized ratably over the applicable service period or the period beginning at the start of the service period and ending when an employee becomes eligible for retirement, after taking into account estimated forfeitures,.

Ordinary shares held in employee benefit trust - Our ordinary shares are purchased by the plan administrator of the FMC Technologies, Inc. Non-Qualified Savings and Investment Plan and placed in a trust that we own. Purchased shares are recorded at cost and classified as a reduction of stockholders’ equity on the consolidated balance sheets.

Earnings per ordinary share (“EPS”) - Basic EPS is computed using the weighted-average number of ordinary 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 ordinary shares at the average market price during the period.

Convertible bonds that could be converted into or be exchangeable for new or existing shares would additionally result in a dilution of earnings per share. The ordinary shares assumed to be converted as of the issuance date are included to compute diluted EPS under the if-converted method. Additionally, the net profit of the period is adjusted as if converted for the after-tax interest expense related to these dilutive shares.

Foreign currency - Financial statements of operations for which the U.S. dollar is not the functional currency, and which 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 highly inflationary economies are included in interest income or expense.

For certain committed and anticipated future cash flows and recognized assets and liabilities which are denominated in a foreign currency, we may choose to manage our risk against changes in the exchange rates, when compared against the functional currency, through the economic netting of exposures instead of derivative instruments. Cash outflows or liabilities in a foreign currency are matched against cash inflows or assets in the same currency, such that movements in exchange rates will result in offsetting gains or losses. Due to the inherent unpredictability of the timing of cash flows, gains and losses in the current period may be economically offset by gains and losses in a future period. All gains and losses are recorded in our consolidated statements of income in the period in which they are incurred. Gains and losses from the remeasurement of assets and liabilities are recognized in other income (expense), net.

During the second half of 2018, Argentina’s three year cumulative inflation rate exceeded 100% based on published inflation data, and effective July 1, 2018, Argentina’s currency is considered highly inflationary. Our local operations in Argentina use U.S. dollars as the functional currency and both monetary and non-monetary assets and liabilities denominated in Argentina pesos were remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. This event did not have a material impact on the Company’s condensed consolidated financial statements.

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 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.

NOTE 2. BUSINESS COMBINATION TRANSACTIONS

Description of the merger of FMC Technologies and Technip

On June 14, 2016, FMC Technologies and Technip entered into a definitive business combination agreement providing for the business combination among FMC Technologies, FMC Technologies SIS Limited, a private limited company incorporated under the laws of England and Wales and a wholly-owned subsidiary of FMC Technologies, and Technip. On August 4, 2016, the legal name of FMC Technologies SIS Limited was changed to TechnipFMC Limited, and on January 11, 2017, was subsequently re-registered as TechnipFMC plc, a public limited company incorporated under the laws of England and Wales.

On January 16, 2017, the business combination was completed. Pursuant to the terms of the definitive business combination agreement, Technip merged with and into TechnipFMC, with TechnipFMC continuing as the surviving company (the “Technip Merger”), and each ordinary share of Technip (the “Technip Shares”), other than Technip Shares owned by Technip or its wholly-owned subsidiaries, were exchanged for 2.0 ordinary shares of TechnipFMC, subject to the terms of the definitive business combination agreement. Immediately following the Technip Merger, a wholly-owned indirect subsidiary of TechnipFMC (“Merger Sub”) merged with and into FMC Technologies, with FMC Technologies continuing as the surviving company and as a wholly-owned indirect subsidiary of TechnipFMC (the “FMCTI Merger”), and each share of common stock of FMC Technologies (the “FMCTI Shares”), other than FMCTI Shares owned by FMC Technologies, TechnipFMC, Merger Sub or their wholly-owned subsidiaries, were exchanged for 1.0 ordinary share of TechnipFMC, subject to the terms of the definitive business combination agreement.

Under the acquisition method of accounting, Technip was identified as the accounting acquirer and acquired a 100% interest in FMC Technologies.

The merger of FMC Technologies and Technip (the “Merger”) has created a larger and more diversified company that is better equipped to respond to economic and industry developments and better positioned to develop and build on its offerings in the subsea, surface, and onshore/offshore markets as compared to the former companies on a standalone basis. More importantly, the Merger has brought about the ability of the combined company to (i) standardize its product and service offerings to customers, (ii) reduce costs to customers, and (iii) provide integrated product offerings to the oil and gas industry with the aim to innovate the markets in which the combined company operates.

We incurred merger transaction and integration costs of $36.5 million, $101.8 million and $92.6 million during the years ended December 31, 2018, 2017 and 2016, respectively.

Description of FMC Technologies as Accounting Acquiree - FMC Technologies is a global provider of technology solutions for the energy industry. FMC Technologies designs, manufactures and services 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. Subsea systems produced by FMC Technologies are used in the offshore production of crude oil and natural gas and are placed on the seafloor to control the flow of crude oil and natural gas from the reservoir to a host processing facility. Additionally, FMC Technologies provides 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 and are used in both onshore and offshore applications.

Consideration Transferred - The acquisition-date fair value of the consideration transferred consisted of the following:



(In millions, except per share data)
Total FMC Technologies, Inc. shares subject to exchange as of January 16, 2017	228.9
FMC Technologies, Inc. exchange ratio ^(a)	0.5
Shares of TechnipFMC issued	114.4
Value per share of Technip as of January 16, 2017 ^(b)	$	71.4
Total purchase consideration	$	8,170.7

(a)

As the calculation is deemed to reflect a share capital increase of the accounting acquirer, the FMC Technologies exchange ratio (1 share of TechnipFMC for 1 share of FMC Technologies as provided in the business combination agreement) is adjusted by dividing the FMC Technologies exchange ratio by the Technip exchange ratio (2 shares of TechnipFMC for 1 share of Technip as provided in the business combination agreement), i.e., 1 ⁄ 2 = 0.5 in order to reflect the number of shares of Technip that FMC Technologies stockholders would have received if Technip was to have issued its own shares.


(b)	Closing price of Technip’s ordinary shares on Euronext Paris on January 16, 2017 in Euro converted at the Euro to U.S. dollar exchange rate of $1.0594 on January 16, 2017.

Assets Acquired and Liabilities Assumed - The following table summarizes the final allocation of the fair values of the assets acquired and liabilities assumed at the acquisition date:



(In millions)
Assets
Cash	$	1,479.2
Accounts receivable	647.8
Costs and estimated earnings in excess of billings on uncompleted contracts	599.6
Inventory	764.8
Income taxes receivable	139.2
Other current assets	282.2
Property, plant and equipment	1,293.3
Intangible assets	1,390.3
Other long-term assets	167.3
Total identifiable assets acquired	6,763.7
Liabilities
Short-term and current portion of long-term debt	319.5
Accounts payable, trade	386.0
Billings in excess of costs and estimated earnings on uncompleted contracts	454.0
Income taxes payable	92.1
Other current liabilities	524.3
Long-term debt, less current portion	1,444.2
Accrued pension and other post-retirement benefits, less current portion	195.5
Deferred income taxes	219.4
Other long-term liabilities	138.7
Total liabilities assumed	3,773.7
Net identifiable assets acquired	2,990.0
Goodwill	5,180.7
Net assets acquired	$	8,170.7

Segment Allocation of Goodwill - The final allocation of goodwill to the reporting segments based on the final valuation is as follows:



(In millions)	Allocated Goodwill
Subsea	$	2,527.7
Onshore/Offshore	1,635.5
Surface Technologies	1,017.5
Total	$	5,180.7

Goodwill is calculated as the excess of the consideration transferred over the net assets recognized and represents the expected revenue and cost synergies of the combined company, which are further described above. Goodwill recognized as a result of the acquisition is not deductible for tax purposes.

Acquired Identifiable Intangible Assets - The identifiable intangible assets acquired include the following:



(In millions, except estimated useful lives)	Fair Value		Estimated Useful Lives
Acquired technology	$	240.0	10
Backlog	175.0		2
Customer relationships	285.0		10
Tradenames	635.0		20
Software	55.3		Various
Total identifiable intangible assets acquired	$	1,390.3

FMC Technologies’ results of operations have been included in our financial statements for periods subsequent to the consummation of the Merger on January 16, 2017. FMC Technologies contributed revenues and a net loss of $3,441.1 million and $251.2 million, respectively, for the period from January 17, 2017 through December 31, 2017.

As part of the ongoing review of the purchase price allocation, a $19.7 million adjustment to our deferred tax liability balance was recorded during the first quarter of 2018 which increased Surface Technologies goodwill.

Pro Forma Impact of the Merger (unaudited) - The following unaudited supplemental pro forma results present consolidated information as if the Merger had been completed as of January 1, 2016. The pro forma results do not include any potential synergies, cost savings or other expected benefits of the Merger. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the Merger had been consummated as of January 1, 2016, nor are they indicative of future results. For comparative purposes, the weighted average shares outstanding used for the diluted earnings per share calculation for the year ended December 31, 2017 was also used to calculate the diluted earnings per share for the year ended December 31, 2016.



	Unaudited
	Year Ended December 31,
(In millions, except per share data)	2017 Pro Forma		2016 Pro Forma
Revenue	$	15,169.8	$	13,727.9
Net income attributable to TechnipFMC adjusted for dilutive effects	$	28.5	$	291.8
Diluted earnings per share	0.06		0.62

Other Transactions

On July 18, 2018, we entered into a share sale and purchase agreement with POC Holding Oy to sell 100% of the outstanding shares of Technip Offshore Finland Oy. The total gain before tax recognized in the third quarter of 2018 was $27.8 million.

Additional acquisitions, including purchased interests in equity method investments, during the year ended December 31, 2018 totaled $62.5 million in consideration paid.

NOTE 3. NEW ACCOUNTING STANDARDS

Recently Adopted Accounting Standards under U.S. GAAP

Effective January 1, 2018, we adopted Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” 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. See Note 4 for more information.

In March 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”, which clarifies the implementation guidance on principal versus agent considerations. Entities are permitted to apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. The adoption of this update did not have a material impact on our consolidated financial statements.

Effective January 1, 2018, we adopted ASU No. 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities.” This update addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Among other amendments, this update requires equity investments not accounted for under the equity method of accounting to be measured at fair value with changes in fair value recognized in net income. An entity may choose to measure equity investments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. This updated guidance also simplifies the impairment assessment of equity investments without readily determinable fair values and eliminates the requirement to disclose significant assumptions and methods used to estimate the fair value of financial instruments measured at amortized cost. The updated guidance further requires the use of an exit price notion when measuring the fair value of financial instruments for disclosure purposes. All amendments are required to be adopted on a modified retrospective basis, with two exceptions. The amendments related to equity investments without readily determinable fair values and the requirement to use an exit price notion are required to be adopted prospectively. In February 2018, the FASB issued ASU No. 2018-03, “Technical Corrections and Improvements to Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities”. These amendments clarify the guidance in ASU No. 2016-01, on the following issues (among other things): Equity Securities without a Readily Determinable Fair Value-Discontinuation; Equity Securities without a Readily Determinable Fair Value - Adjustment; Forward Contracts and Purchase Options; Presentation Requirements for Certain Fair Value Option Liabilities; Fair Value Option Liabilities Denominated in a Foreign Currency; and Transition Guidance for Equity Securities without a Readily Determinable Fair Value. The amendments in this ASU are effective in conjunction with the adoption of ASU No. 2016-01. In March 2018, the FASB issued ASU No. 2018-04, “Investments-Debt Securities (Topic 320) and Regulated Operations (Topic 980): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 117 and SEC Release No. 33-9273.” This ASU supersedes SEC paragraphs pursuant to the SEC Staff Accounting Bulletin No. 117, which brings existing guidance into conformity with Topic 321, Investments-Equity Securities, and SEC Release No. 33-9273, which removed Regulation S-X Rule 3A-05, Special Requirements as to Public Utility Holding Companies. The adoption of these updates did not have a material impact on our consolidated financial statements.

Effective January 1, 2018, we adopted ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This update amends the existing guidance for the statement of cash flows and provides guidance on eight classification issues related to the statement of cash flows. The amendments in this ASU are required to be adopted retrospectively. For issues that are impracticable to adopt retrospectively, the amendments may be adopted prospectively as of the earliest date practicable. The adoption of this update did not have a material impact on our consolidated financial statements.

Effective January 1, 2018, we adopted ASU No. 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” This update requires that income tax consequences are recognized on an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this ASU are required to be adopted on a modified retrospective basis. The adoption of this update did not have a material impact on our consolidated financial statements.

Effective January 1, 2018, we adopted ASU No. 2017-01, “Clarifying the Definition of a Business.” This update clarifies the definition of a business and provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, such set of assets is not a business. The amendments in this ASU are required to be adopted prospectively. The adoption of this update did not have a material impact on our consolidated financial statements.

Effective January 1, 2018, we adopted ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This update requires employers to disaggregate the service cost component from the other components of net benefit cost and disclose the amount of net benefit cost that is included in the income statement or capitalized in assets, by line item. The updated guidance requires employers to report the service cost component in the same line item(s) as other compensation costs and to report other pension-related costs (which include interest costs, amortization of pension-related costs from prior periods, and the gains or losses on plan assets) separately and exclude them from the subtotal of operating income. The updated guidance also allows only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for us on January 1, 2018. The guidance requires adoption on a retrospective basis for the presentation of the service cost component and the other components of net periodic pension cost and net periodic post-retirement benefit cost in the income statement and on a prospective basis for the capitalization of the service cost component of net periodic pension cost and net periodic post-retirement benefit in assets. The adoption of this update did not have a material impact on our consolidated financial statements.

Effective January 1, 2018, we adopted ASU No. 2017-09, “Scope of Modification Accounting.” This update provides clarity on when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The amendments in this ASU are effective for us January 1, 2018 and are required to be adopted prospectively. The adoption of this update did not have a material impact on our consolidated financial statements.

In March 2018, the FASB issued ASU No. 2018-05, “Income Taxes (Topic 740)-Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118.” This ASU adds SEC paragraphs pursuant to the SEC Staff Accounting Bulletin No. 118, which expresses the view of the staff regarding application of Topic 740, Income Taxes, in the reporting period that includes December 22, 2017 - the date on which the Tax Cuts and Jobs Act of 2017 (the “Tax Cuts and Jobs Act”) was signed into law. The amendments in this ASU are effective upon issuance. The adoption of this update did not have a material impact on our consolidated financial statements.

Recently Issued Accounting Standards under U.S. GAAP

Lease Accounting

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This update requires that a lessee recognize a liability to make lease payments and a right-of-use (“ROU”) asset representing its right to use the underlying asset for the lease term. Similar to current guidance, the update continues to differentiate between finance leases and operating leases, however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The updated guidance leaves the accounting for leases by lessors largely unchanged from existing GAAP. Early application is permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The guidance will become effective for us on January 1, 2019.

In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842.” The amendments in this update permit an entity to elect an optional transition practical expedient to not evaluate land easements that existed or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840.

In July 2018 and December 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842, Lease” and ASU 2018-20, “Narrow-scope Improvements for Lessors”, respectively. The amendments in these updates affect narrow aspects of the guidance issued in ASU 2016-02 and is intended to simplify adoption of the new standard. The amendments do not make substantive changes to the core provisions or principles of the new standard and will be considered during our implementation process.

In July 2018, the FASB also issued ASU 2018-11, “Leases (Topic 842): Targeted Improvements.” The amendments in this update provide entities with an optional transition method, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. In addition, the amendments in this update also provide lessors with a practical expedient (provided certain conditions are met), by class of underlying asset, to not separate the non-lease component(s) from the associated lease component for purposes of income statement presentation. We plan to not elect this practical expedient for lessors and will account for lease and non-lease components within our lessor contracts separately. We plan to elect the practical expedient available for lessees to not separate lease and non-lease components for all asset classes other than vessels, which typically include significant non-lease components.

We will adopt Topic 842 on January 1, 2019, electing the optional transition method that allows for a cumulative-effect adjustment in the period of adoption and, as a result, we will not restate prior periods. We expect to elect certain practical expedients permitted under Topic 842, including the practical expedient for short-term leases in which a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities for leases with a term of 12 months or less. In addition, we expect to elect the package of practical expedients permitted under the transition guidance within Topic 842, which among other things, allows us to carry forward the historical lease classification.

As part of our assessment work-to-date, we have formed an implementation work team, conducted region-specific training for the relevant staff regarding the potential impacts of Topic 842 and are continuing our contract analysis and policy review. We have engaged external resources to assist us in our efforts of completing the analysis of potential changes to current accounting practices and are in the process of implementing a new lease accounting system in connection with the adoption of the updated guidance. We are also evaluating the impact of Topic 842 on our internal control over financial reporting and other changes in business practices and processes.

On adoption, we currently expect to recognize material operating liabilities with corresponding ROU assets of approximately the same amount, based on the present value of the lease payments not yet paid under current leasing standards for existing operating leases where we are a lessee.

Other

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses.” This update introduces a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. The updated guidance applies to (i) loans, accounts receivable, trade receivables and other financial assets measured at amortized cost, (ii) loan commitments and other off-balance sheet credit exposures, (iii) debt securities and other financial assets measured at fair value through other comprehensive income and (iv) beneficial interests in securitized financial assets. The amendments in this ASU are effective for us on January 1, 2020 and are required to be adopted on a modified retrospective basis. Early adoption is not permitted. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In November 2018, the FASB also issued ASU No. 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses.” The update amends the transition requirements and scope of the credit losses standard issued in 2016. This update clarifies that receivables arising from operating leases are not within the scope of the credit losses standard, but rather, should be accounted for in accordance with the leases standard. The amendments in this ASU are effective for us on January 1, 2020 and are required to be adopted on a modified retrospective basis. Early adoption is not permitted. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This update improves the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. The amendments in this update better align an entity's risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. The amendments in this ASU are effective for us January 1, 2019. Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required to be adopted prospectively. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In February 2018, the FASB issued ASU No. 2018-02, “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (AOCI).” This update provides an option to reclassify stranded tax effects with AOCI to retained earnings in each period in which the effect of the change in the U.S. federal corporate tax rate in the Tax Cuts and Jobs Act (or portion thereof) is recorded. The ASU requires financial statement disclosures that indicate a description of the accounting policy for releasing income tax effects from AOCI; whether there is an election to reclassify the stranded income tax effects from the Tax Cuts and Jobs Act and information about the other income tax effects are reclassified. These amendments affect any organization that is required to apply the provisions of Topic 220, Income Statement-Reporting Comprehensive Income, and has items of other comprehensive income for which the related tax effects are presented in other comprehensive income as required by GAAP. The amendments in this ASU are effective for us January 1, 2019. The adoption of this update will not have a material effect on our consolidated financial statements.

In June 2018, the FASB issued ASU No. 2018-07, “Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting.” This update expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. The amendments in this update specify that Topic 718 applies to all share-based payment transactions in which the grantor acquires goods and services to be used or consumed in its own operations by issuing share-based payment awards. The amendments in this update also clarify that Topic 718 does not apply to share-based payments used to effectively provide (1) financing to the issuer or (2) awards granted in conjunction with selling goods or services to customers as part of a contract accounted for under ASC Topic 606. The amendments in this update are effective for us on January 1, 2019, with early adoption permitted, but no earlier than our adoption of ASC Topic 606. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement.” This update modifies the disclosure requirement on fair value measurements in Topic 820. The amendments in this ASU are effective for us January 1, 2020. Early adoption is permitted. The amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty should be applied prospectively. All other amendments should be applied retrospectively. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-14, “Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans.” This update amends ASC 715 to add, remove and clarify disclosure requirements related to defined benefit pension and other postretirement plans. The amendments in this ASU are effective for us January 1, 2021. Early adoption is permitted. The amendments in this update is required to be adopted retrospectively. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force).” This update requires that the implementation costs incurred in a cloud computing arrangement that is a service contract are deferred if they would be capitalized based on the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amendments in this ASU are effective for us January 1, 2020. Early adoption is permitted. The amendments in this update is required to be adopted either retrospectively or prospectively. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808) -Clarifying the Interaction between Topic 808 and Topic 606.” This update clarifies the interaction between the guidance for certain collaborative arrangements and the Revenue Recognition financial accounting and reporting standard. The amendments in this ASU are effective for us January 1, 2020. Early adoption is permitted. The amendments in this update is required to be adopted retrospectively to the date of initial application of Topic 606. An entity should recognize the cumulative effect of initially applying the amendments as an adjustment to the opening balance of retained earnings of the later of the earliest annual period presented and the annual period that includes the date of the entity’s initial application of Topic 606. We are currently evaluating the impact of this ASU on our consolidated financial statements.

NOTE 4. REVENUE

The majority of our revenue is from long-term contracts associated with designing and manufacturing products and systems and providing services to customers involved in exploration and production of crude oil and natural gas. On January 1, 2018, we adopted ASC Topic 606 of GAAP using the modified retrospective method applied to those contracts that were not completed as of January 1, 2018 resulting in a $91.5 million reduction to retained earnings. Results for reporting periods beginning after January 1, 2018 are presented under ASC Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under Topic 605.

Significant Revenue Recognition Criteria Explained

Allocation of transaction price to performance obligations - A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. To determine the proper revenue recognition method, we evaluate whether two or more contracts should be combined and accounted for as one single contract and whether the combined or single contract should be accounted for as more than one performance obligation. This evaluation requires significant judgment; some of our contracts have a single performance obligation as the promise to transfer the individual goods or services is not separately identifiable from other promises in the contracts and, therefore, not distinct.

Variable consideration - Due to the nature of the work required to be performed on many of our performance obligations, the estimation of total revenue and cost at completion is complex, subject to many variables and requires significant judgment. It is common for our long-term contracts to contain variable considerations that can either increase or decrease the transaction price. Variability in the transaction price arises primarily due to liquidated damages. The Company considers its experience with similar transactions and expectations regarding the contract in estimating the amount of variable consideration to which it will be entitled, and determining whether the estimated variable consideration should be constrained. We include estimated amounts in the transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is resolved. Our estimates of variable consideration are based largely on an assessment of our anticipated performance and all information (historical, current and forecasted) that is reasonably available to us.

Payment terms - Progress billings are generally issued upon completion of certain phases of the work as stipulated in the contract. Payment terms may either be fixed, lump-sum or driven by time and materials (e.g., daily or hourly rates, plus materials). Because typically the customer retains a small portion of the contract price until completion of the contract, our contracts generally result in revenue recognized in excess of billings which we present as contract assets on the balance sheet. Amounts billed and due from our customers are classified as receivables on the balance sheet. The portion of the payments retained by the customer until final contract settlement is not considered a significant financing component because the intent is to protect the customer. For some contracts, we may be entitled to receive an advance payment. We recognize a liability for these advance payments in excess of revenue recognized and present it as contract liabilities on the balance sheet. The advance payment typically is not considered a significant financing component because it is used to meet working capital demands that can be higher in the early stages of a contract and to protect us from the other party failing to adequately complete some or all of its obligations under the contract.

Warranty - Certain contracts include an assurance-type warranty clause, typically between 18 to 36 months, to guarantee that the products comply with agreed specifications. A service-type warranty may also be provided to the customer; in such a case, management allocates a portion of the transaction price to the warranty based on the estimated stand-alone selling price of the service-type warranty.

Revenue recognized over time - Our performance obligations are satisfied over time as work progresses or at a point in time. Revenue from products and services transferred to customers over time accounted for approximately 82.4% of our revenue for the year ended December 31, 2018, respectively. Typically, revenue is recognized over time using an input measure (e.g., costs incurred to date relative to total estimated costs at completion) to measure progress.

Cost-to-cost method - For our long-term contracts, because of control transferring over time, revenue is recognized based on the extent of progress towards completion of the performance obligation. Upon adoption of the new standard we generally use the cost-to-cost measure of progress for our contracts because it best depicts the transfer of control to the customer which occurs as we incur costs on our contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of costs incurred to date to the total estimated costs at completion of the performance obligation. Revenues, including estimated fees or profits, are recorded proportionally as costs are incurred. Any expected losses on construction-type contracts in progress are charged to earnings, in total, in the period the losses are identified.

Right to invoice practical expedient - The right-to-invoice practical expedient can be applied to a performance obligation satisfied over time if we have a right to invoice the customer for an amount that corresponds directly with the value transferred to the customer for our performance completed to date. When this practical expedient is used, we do not estimate variable consideration at the inception of the contract to determine the transaction price or for disclosure purposes. We have contracts which have payment terms dictated by daily or hourly rates where some contracts may have mixed pricing terms which include a fixed fee portion. For contracts in which we charge the customer a fixed rate based on the time or materials spent during the project that correspond to the value transferred to the customer, we recognize revenue in the amount to which we have the right to invoice.

Contract modifications - Contracts are often modified to account for changes in contract specifications and requirements. We consider contract modifications to exist when the modification either creates new, or changes the existing, enforceable rights and obligations. Most of our contract modifications are for goods or services that are not distinct from the existing contract due to the significant integration service provided in the context of the contract and are accounted for as if they were part of that existing contract. The effect of a contract modification on the transaction price and our measure of progress for the performance obligation to which it relates is recognized as an adjustment to revenue (either as an increase in or a reduction of revenue) on a cumulative catch-up basis.

Revenue Recognition by Segment

The following is a description of principal activities separated by reportable segments from which the Company generates its revenue. See Note 5 for more detailed information about reportable segments.


a.	Subsea

Our Subsea segment manufactures and designs products and systems, performs engineering, procurement and project management and provides services used by oil and gas companies involved in offshore exploration and production of crude oil and natural gas. Systems and services may be sold separately or as combined integrated systems and services offered within one contract. Many of the systems and products the Company supplies 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 working capital requirements.

Under Subsea engineering, procurement, construction and installation contracts, revenue is principally generated from long-term contracts with customers. We have determined these contracts generally have one performance obligation as the delivered product is highly customized to customer and field specifications. We generally recognize revenue over time for such contracts as the customized products do not have an alternative use for the Company and we have an enforceable right to payment plus a reasonable profit for performance completed to date.

Our Subsea segment also performs an array of subsea services including (i) installation services, (ii) asset management services (iii) product optimization, (iv) inspection, maintenance and repair services, and (v) well access and intervention services, where revenue is generally earned through the execution of either installation-type or maintenance-type contracts. For either contract-type, management has determined that the performance of the service generally represents one single performance obligation. We have determined that revenue from these contracts is recognized over time as the customer simultaneously receives and consumes the benefit of the services.


b.	Onshore/Offshore

Our Onshore/Offshore segment designs and builds onshore facilities related to the production, treatment, transformation and transportation of oil and gas; and designs, manufactures and installs fixed and floating platforms for the offshore production and processing of oil and gas reserves.

Our onshore business combines the design, engineering, procurement, construction and project management of the entire range of onshore facilities. Our onshore activity covers all types of onshore facilities related to the production, treatment and transportation of oil and gas, as well as transformation with petrochemicals such as ethylene, polymers and fertilizers. Some of the onshore activities include the development of onshore fields, refining, natural gas treatment and liquefaction, and design and construction of hydrogen and synthesis gas production units.

Many of these contracts provide a combination of engineering, procurement, construction, project management and installation services, which may last several years. We have determined that contracts of this nature have generally one performance obligation. In these contracts, the final product is highly customized to the specifications of the field and the customer’s requirements. Therefore, the customer obtains control of the asset over time, and thus revenue is recognized over time.

Our offshore business combines the design, engineering, procurement, construction and project management within the entire range of fixed and floating offshore oil and gas facilities, many of which were the first of their kind, including the development of floating liquefied natural gas (“FLNG”) facilities. Similar to onshore contracts, contracts grouped under this segment provide a combination of services, which may last several years.

We have determined that contracts of this nature have one performance obligation. In these contracts, the final product is highly customized to the specifications of the field and the customer’s requirements. We have determined that the customer obtains control of the asset over time, and thus revenue is recognized over time as the customized products do not have an alternative use for us and we have an enforceable right to payment plus reasonable profit for performance completed to date.


c.	Surface Technologies

Our Surface Technologies segment designs, manufactures and supplies technologically advanced wellhead systems and high pressure valves and pumps used in stimulation activities for oilfield service companies and provides installation, flowback and other services for exploration and production companies.

We provide a full range of drilling, completion and production wellhead systems for both standard and custom-engineered applications. Under pressure control product contracts, 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. Performance obligations within these systems are satisfied either through delivery of a standardized product or equipment or the delivery of a customized product or equipment.

For contracts with a standardized product or equipment performance obligation, management has determined that because there is limited customization to products sold within such contracts and the asset delivered can be resold to another customer, revenue should be recognized as of a point in time, upon transfer of control to the customer and after the customer acceptance provisions have been met.

For contracts with a customized product or equipment performance obligation, the revenue is recognized over time, as the manufacturing of our product does not create an asset with an alternative use for us.

This segment also designs, manufactures and services measurement products globally. Contract-types include standard product or equipment and maintenance-type services where we have determined that each contract under this product line represents one performance obligation.

Revenue from standard measurement equipment contracts is recognized at a point in time, while maintenance-type contracts are typically priced at a daily or hourly rate. We have determined that revenue for these contracts is recognized over time because the customer simultaneously receives and consumes the benefit of the services.

Disaggregation of Revenue

The Company disaggregates revenue by geographic location and contract types. The tables also include a reconciliation of the disaggregated revenue with the reportable segments.

The following tables present products and services revenue by geography for each reportable segment for the year ended December 31, 2018:



	Reportable Segments
	Year Ended
	December 31, 2018
(In millions)	Subsea		Onshore/ Offshore		Surface Technologies
Europe, Russia, Central Asia	1,528.1		3,506.1		227.7
America	1,721.5		365.1		865.5
Asia Pacific	532.9		1,236.1		123.2
Africa	758.1		252.7		57.9
Middle East	181.2		760.7		213.4
Total products and services revenue	$	4,721.8	$	6,120.7	$	1,487.7

The following tables represent revenue by contract type for each reportable segment for the year ended December 31, 2018:



	Reportable Segments
	Year Ended
	December 31, 2018
(In millions)	Subsea		Onshore/ Offshore		Surface Technologies
Services	3,394.5		6,120.7		249.8
Products	1,327.3		—		1,237.9
Total products and services revenue	4,721.8		6,120.7		1,487.7
Lease and other^(a)	118.2		—		104.5
Total revenue	$	4,840.0	$	6,120.7	$	1,592.2


(a)	Represents revenue not subject to ASC Topic 606.

Contract Balances

The timing of revenue recognition, billings and cash collections results in billed accounts receivable, costs and estimated earnings in excess of billings on uncompleted contracts (contract assets), and billings in excess of costs and estimated earnings on uncompleted contracts (contract liabilities) on the consolidated balance sheets.

Contract Assets - Contract Assets, previously disclosed as costs and estimated earnings in excess of billings on uncompleted contracts, include unbilled amounts typically resulting from sales under long-term contracts when revenue is recognized over time and revenue recognized exceeds the amount billed to the customer, and right to payment is not just subject to the passage of time. Amounts may not exceed their net realizable value. Costs and estimated earnings in excess of billings on uncompleted contracts are generally classified as current.

Contract Liabilities - We sometimes receive advances or deposits from our customers, before revenue is recognized, resulting in contract liabilities.

The following table provides information about net contract assets (liabilities) as of December 31, 2018 and December 31, 2017:



(In millions)	December 31, 2018			December 31, 2017			$ change			% change
Contract assets	$	1,295.0		$	1,755.5		$	(460.5	)	(26.2	)
Contract (liabilities)	(4,085.1		)	(3,314.2		)	(770.9		)	(23.3	)
Net contract assets (liabilities)	$	(2,790.1	)	$	(1,558.7	)	$	(1,231.4	)	(79.0	)

The majority of the change in net contract assets (liabilities) was due to the adoption of ASC Topic 606. The adoption resulted in a net reclassification from net contract assets (liabilities) to trade receivables. See ‘Impact on Primary Financial Statements’ below. Certain amounts that were previously reported in contract assets and contract liabilities have been reclassified to trade receivables as of December 31, 2018.

The remaining decrease not related to the adoption of ASC Topic 606 in our contract assets from December 31, 2017 to December 31, 2018 was primarily due to the timing of milestone payments, partially offset by an increase of $5.7 million in contract assets due to acquisitions.

The remaining increase not related to the adoption of ASC Topic 606 in our contract liabilities was primarily due to cash received, excluding amounts recognized as revenue during the period.

In order to determine revenue recognized in the period from contract liabilities, we first allocate revenue to the individual contract liability balance outstanding at the beginning of the period until the revenue exceeds that balance. Revenue recognized for the year ended December 31, 2018 that were included in the contract liabilities balance at December 31, 2017 was $2,814.6 million.

In addition, net revenue recognized for the year ended December 31, 2018 from our performance obligations satisfied in previous periods has favorable impact of $21.8 million. This primarily relates to the changes in the estimate of the stage of completion that impacted revenue.

Transaction Price Allocated to the Remaining Unsatisfied Performance Obligations

Remaining unsatisfied performance obligations (“RUPO” or “order backlog”) represent the transaction price for products and services for which we have a material right but work has not been performed. Transaction price of the order backlog includes the base transaction price, variable consideration and changes in transaction price. The order backlog table does not include contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed. The transaction price of order backlog related to unfilled, confirmed customer orders is estimated at each reporting date. As of December 31, 2018, the aggregate amount of the transaction price allocated to order backlog was $14,560.0 million. The Company expects to recognize revenue on approximately 63.1% of the order backlog through 2019 and 36.9% thereafter.

The following table details the order backlog for each business segment as of December 31, 2018:



(In millions)	2019			2020		Thereafter
Subsea	3,379.2			1,382.1		1,238.3
Onshore/Offshore	5,335.1			1,732.9		1,022.5
Surface Technologies	469.9			—		—
Total remaining unsatisfied performance obligations	$	9,184.2	—	$	3,115.0	2,260.8

Impact on Primary Financial Statements

The impact to revenues for the year ended December 31, 2018 was an increase of $27.1 million, as a result of applying ASC Topic 606. A difference between revenue recognized under ASC Topic 606 as compared to ASC Topic 605 exists for certain contracts in which physical progress was used as the measure of progress for which the cost-to-cost method best depicts the transfer of control to the customer.

A difference exists in the presentation of trade receivables, contract assets and contract liabilities. Upon adoption of ASC Topic 606, we recognize trade receivables when we have the unconditional right to payment. Previously, we reported certain billed amounts on a net basis within contract assets and contract liabilities when the legal right of offset was present within the contract.

Consolidated Statements of Income for the year ended December 31, 2018:



	Year Ended
	December 31, 2018
(In millions, except per share data)	As reported			Effect of ASC Topic 606			Under ASC Topic 605
Revenue
Service revenue	$	9,765.0		$	(32.0	)	$	9,733.0
Product revenue	2,565.2			4.9			2,570.1
Lease and other revenue	222.7			—			222.7
Total revenue	12,552.9			(27.1		)	12,525.8

Costs and expenses
Cost of service revenue	7,895.1			(17.7		)	7,877.4
Cost of product revenue	2,234.5			5.9			2,240.4
Cost of lease and other revenue	143.4			—			143.4
Selling, general and administrative expense	1,140.6			—			1,140.6
Research and development expense	189.2			—			189.2
Impairment, restructuring and other expenses (Note 17)	1,831.2			—			1,831.2
Merger transaction and integration costs (Note 2)	36.5			—			36.5
Total costs and expenses	13,470.5			(11.8		)	13,458.7

Other income (expense), net	(323.9		)	—			(323.9		)
Income from equity affiliates	114.3			(8.0		)	106.3
Income before net interest expense and income taxes	(1,127.2		)	(23.3		)	(1,150.5		)
Net interest expense	(360.9		)	—			(360.9		)
Income before income taxes	(1,488.1		)	(23.3		)	(1,511.4		)
Provision for income taxes (Note 19)	422.7			(8.9		)	413.8
Net income (loss)	(1,910.8		)	(14.4		)	(1,925.2		)
Net (income) loss attributable to noncontrolling interests	(10.8		)	—			(10.8		)
Net income (loss) attributable to TechnipFMC plc	$	(1,921.6	)	$	(14.4	)	$	(1,936.0	)

Consolidated Balance Sheets as of December 31, 2018:



	December 31, 2018
(In millions, except par value data)	As reported			Effect of ASC Topic 606			Under ASC Topic 605
Assets
Cash and cash equivalents	$	5,540.0		$	—		$	5,540.0
Trade receivables, net	2,469.7			(1,513.4		)	956.3
Contract assets	1,295.0			450.2			1,745.2
Inventories, net (Note 7)	1,251.2			16.4			1,267.6
Derivative financial instruments (Note 21)	95.7			—			95.7
Income taxes receivable	284.3			(1.2		)	283.1
Advances paid to suppliers	189.7			—			189.7
Other current assets (Note 8)	655.6			—			655.6
Total current assets	11,781.2			(1,048.0		)	10,733.2
Investments in equity affiliates	394.5			(8.0		)	386.5
Property, plant and equipment, net of accumulated depreciation	3,259.8			—			3,259.8
Goodwill	7,607.6			—			7,607.6
Intangible assets, net of accumulated amortization	1,176.7			—			1,176.7
Deferred income taxes	232.4			(0.2		)	232.2
Derivative financial instruments (Note 21)	18.3			—			18.3
Other assets	314.0			—			314.0
Total assets	$	24,784.5		$	(1,056.2	)	$	23,728.3

Liabilities and equity
Short-term debt and current portion of long-term debt (Note 13)	$	67.4		$	—		$	67.4
Accounts payable, trade	2,600.3			17.6			2,617.9
Contract liabilities	4,085.1			(1,116.1		)	2,969.0
Accrued payroll	394.7			—			394.7
Derivative financial instruments (Note 21)	138.4			—			138.4
Income taxes payable	81.9			2.2			84.1
Other current liabilities (Note 8)	1,766.6			(39.0		)	1,727.6
Total current liabilities	9,134.4			(1,135.3		)	7,999.1
Long-term debt, less current portion (Note 13)	4,124.3			—			4,124.3
Accrued pension and other post-retirement benefits, less current portion	298.9			—			298.9
Derivative financial instruments (Note 21)	44.9			—			44.9
Deferred income taxes	209.2			2.1			211.3
Other liabilities	503.4			—			503.4
Total liabilities	14,315.1			(1,133.2		)	13,181.9
Commitments and contingent liabilities (Note 18)
Mezzanine equity
Redeemable noncontrolling interest	38.5			—			38.5
Stockholders’ equity (Note 15)
Ordinary shares	450.5			—			450.5
Ordinary shares held in employee benefit trust	(2.4		)	—			(2.4		)
Capital in excess of par value of ordinary shares	10,197.0			—			10,197.0
Retained earnings	1,114.2			77.1			1,191.3
Accumulated other comprehensive loss	(1,359.7		)	—			(1,359.7		)
Total TechnipFMC plc stockholders’ equity	10,399.6			77.1			10,476.7
Noncontrolling interests	31.3			(0.1		)	31.2
Total equity	10,430.9			77.0			10,507.9
Total liabilities and equity	$	24,784.5		$	(1,056.2	)	$	23,728.3

NOTE 5. BUSINESS SEGMENTS

Management’s determination of our reporting segments was made on the basis of our strategic priorities within each segment and the differences in the products and services we provide, which corresponds to the manner in which our Chief Executive Officer, as our chief operating decision maker, reviews and evaluates operating performance to make decisions about resources to be allocated to the segment.

Upon completion of the Merger, we reorganized our reporting structure and aligned our segments and the underlying businesses to execute the strategy of TechnipFMC. As a result, we report the results of operations in the following segments: Subsea, Onshore/Offshore and Surface Technologies.

Our reportable segments are:


•	Subsea - manufactures and designs products and systems, performs engineering, procurement and project management and provides services used by oil and gas companies involved in offshore exploration and production of crude oil and natural gas.


•	Onshore/Offshore - designs and builds onshore facilities related to the production, treatment, transformation and transportation of oil and gas; and designs, manufactures and installs fixed and floating platforms for the production and processing of oil and gas reserves.


•	Surface Technologies - designs and manufactures systems and provides services used by oil and gas companies involved in land and shallow water 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 well testing services.

Segment operating profit is defined as total segment revenue less segment operating expenses. Income (loss) from equity method investments is included in computing segment operating profit. Refer to Note 9 for additional information. 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)	2018			2017			2016
Segment revenue
Subsea	$	4,840.0		$	5,877.4		$	5,850.5
Onshore/Offshore	6,120.7			7,904.5			3,349.1
Surface Technologies	1,592.2			1,274.6			—
Other revenue and intercompany eliminations	—			0.4			—
Total revenue	$	12,552.9		$	15,056.9		$	9,199.6

Segment operating profit (loss)
Subsea	$	(1,529.5	)	$	460.5		$	732.0
Onshore/Offshore	824.0			810.9			34.1
Surface Technologies	172.8			82.7			—
Total segment operating profit (loss)	(532.7		)	1,354.1			766.1

Corporate items
Corporate expense ^(a)	(594.5		)	(359.2		)	(185.9		)
Interest income	121.4			140.8			85.3
Interest expense	(482.3		)	(456.0		)	(114.1		)
Total corporate items	(955.4		)	(674.4		)	(214.7		)
Income (loss) before income taxes ^(b)	$	(1,488.1	)	$	679.7		$	551.4


(a)	Corporate expense primarily includes corporate staff expenses, legal reserve, stock-based compensation expenses, other employee benefits, certain foreign exchange gains and losses, and merger-related transaction expenses.


(b)	Includes amounts attributable to noncontrolling interests.

Segment assets



	December 31,
(In millions)	2018			2017
Segment assets
Subsea	$	11,037.8		$	12,944.4
Onshore/Offshore	4,355.2			4,604.8
Surface Technologies	2,825.6			2,453.3
Intercompany eliminations	(26.4		)	(24.3		)
Total segment assets	18,192.2			19,978.2
Corporate ^(a)	6,592.3			8,285.5
Total assets	$	24,784.5		$	28,263.7


(a)	Corporate includes cash, LIFO adjustments, deferred income tax balances, legal provisions, 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 country where our products and services were delivered.



	Year Ended December 31,
(In millions)	2018		2017		2016
Revenue
Russia	$	2,773.3	$	4,894.2	$	283.3
Brazil	1,478.7		911.1		1,006.9
United States	1,275.8		1,534.7		1,033.7
Norway	1,202.6		971.2		574.4
Australia	926.6		953.9		776.6
United Kingdom	442.1		465.9		761.5
Angola	385.7		1,016.2		935.3
All other countries	4,068.1		4,309.7		3,827.9
Total revenue	$	12,552.9	$	15,056.9	$	9,199.6

Geographic segment long-lived assets represent property, plant and equipment, net.



	December 31,
(In millions)	2018		2017
Long-lived assets
United Kingdom	$	925.6	$	1,190.1
United States	589.9		567.1
Netherlands	360.5		574.2
Brazil	325.8		408.3
Norway	311.4		321.4
All other countries	746.6		810.4
Total long-lived assets	$	3,259.8	$	3,871.5

Other business segment information



	Capital Expenditures						Depreciation and Amortization						Research and Development Expense
	Year Ended December 31,						Year Ended December 31,						Year Ended December 31,
(In millions)	2018		2017		2016		2018		2017		2016		2018		2017		2016
Subsea	$	223.2	$	179.1	$	286.9	$	440.4	$	507.2	$	256.8	$	145.2	$	169.2	$	75.4
Onshore/Offshore	7.6		16.2		26.0		38.2		41.1		43.9		29.7		31.4		30.0
Surface Technologies	111.9		35.4		—		66.6		63.6		—		14.3		12.3		—
Corporate	25.4		25.0		—		5.2		2.8		—		—		—		—
Total	$	368.1	$	255.7	$	312.9	$	550.4	$	614.7	$	300.7	$	189.2	$	212.9	$	105.4

During the years ended December 31, 2018, 2017 and 2016, revenue from JSC Yamal LNG exceeded 10% of our consolidated revenue. During the year ended December 31, 2016, revenue from Total exceeded 10% of our consolidated revenue.

NOTE 6. EARNINGS (LOSS) 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)	2018			2017		2016
Net income (loss) attributable to TechnipFMC plc	$	(1,921.6	)	$	113.3	$	393.3
After-tax interest expense related to dilutive shares	—			—		1.5
Net income (loss) attributable to TechnipFMC plc adjusted for dilutive effects	(1,921.6		)	113.3		394.8

Weighted average number of shares outstanding	458.0			466.7		119.4
Dilutive effect of restricted stock units	—			0.2		—
Dilutive effect of stock options	—			—		—
Dilutive effect of performance shares	—			1.4		0.5
Dilutive effect of convertible bonds	—			—		5.2
Total shares and dilutive securities	458.0			468.3		125.1

Basic earnings (loss) per share attributable to TechnipFMC plc	$	(4.20	)	$	0.24	$	3.29
Diluted earnings (loss) per share attributable to TechnipFMC plc	$	(4.20	)	$	0.24	$	3.16

NOTE 7. INVENTORIES

Inventories consisted of the following:



	December 31,
(In millions)	2018		2017
Raw materials	$	366.4	$	271.4
Work in process	146.4		130.2
Finished goods	738.4		585.4
Inventory, net	1,251.2		987.0

All amounts in the table above are reported net of obsolescence reserves of $97.5 million and $70.8 million at December 31, 2018 and 2017, respectively.

Net inventories accounted for under the LIFO method totaled $387.2 million and $300.9 million at December 31, 2018 and 2017, respectively. The current replacement costs of LIFO inventories exceeded their recorded values by $7.9 million and $0.6 million at December 31, 2018 and 2017, respectively. There was no reduction to the base LIFO inventory in 2018.

NOTE 8. OTHER CURRENT ASSETS & OTHER CURRENT LIABILITIES

Other current assets consisted of the following:



	December 31,
(In millions)	2018		2017
Value-added tax receivables	$	305.8	$	532.5
Prepaid expenses	91.3		136.2
Sundry receivables	87.0		170.9
Other taxes receivables	85.0		155.8
Held-to-maturity investments	—		60.0
Asset held for sale	9.6		50.2
Available-for-sale securities	—		9.9
Other	76.9		90.7
Other current assets	$	655.6	$	1,206.2

Other current liabilities consisted of the following:



(In millions)	December 31, 2018		December 31, 2017
Legal provisions	$	418.2	$	74.6
Warranty accruals and project contingencies	418.2		616.3
Value added tax and other taxes payable	214.3		204.4
Provisions	135.5		83.4
Redeemable financial liability	173.0		69.7
Social security liability	112.3		145.0
Compensation accrual	87.3		123.5
Liabilities held for sale	16.2		13.7
Current portion of accrued pension and other post-retirement benefits	14.0		10.3
Other accrued liabilities	177.6		347.0
Total other current liabilities	$	1,766.6	$	1,687.9

NOTE 9. EQUITY METHOD INVESTMENTS

The equity method of accounting is used to account for investments in unconsolidated affiliates where we can have the ability to exert significant influence over the affiliates operating and financial policies.

For certain construction joint ventures, we use the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. None of our proportionate consolidation investments, individually or in the aggregate, are significant to our consolidated results for 2018, 2017, or 2016.

Our equity investments were as follows as of December 31, 2018 and 2017:



	December 31, 2018
	Percentage Owned		Carrying Value (in millions)
Technip Odebrecht PLSV CV	50.0	%	$	136.1
Dofcon Brasil AS	50.0	%	126.2
Serimax Holdings SAS	20.0	%	23.2
Magma Global Limited	25.0	%	49.8
Other			59.2
Investments in equity affiliates			$	394.5



	December 31, 2017
	Percentage Owned		Carrying Value (in millions)
Technip Odebrecht PLSV CV	50.0	%	$	111.4
Dofcon Brasil AS	50.0	%	74.1
Serimax Holdings SAS	20.0	%	25.1
FSTP Brasil Ltda	25.0	%	21.5
Other			40.4
Investments in equity affiliates			$	272.5

Our income from equity affiliates included in each of our reporting segments was as follows:



	Year Ended December 31,
(In millions)	2018		2017		2016
Subsea	$	80.9	$	55.3	$	35.0
Onshore/Offshore	33.4		0.3		82.7
Income from equity affiliates	$	114.3	$	55.6	$	117.7

Summarized financial information^(b)-Summarized financial information for our equity method investments is presented below for 2016. Our major equity method investments are as follows:

Technip Odebrecht PLSV CV (“Technip Odebrecht”) - is an affiliated company in the form of a joint venture between Technip SA and Ocyan SA. Technip Odebrecht was formed in 2011 when awarded a contract to provide pipeline installation ships to state-controlled Petroleo Brasileiro SA (“Petrobras”) for their work in oil and gas fields offshore Brazil. We have accounted for our 50% investment using the equity method of accounting with results reported in our Subsea segment.

Dofcon Brasil AS (“Dofcon”) - is an affiliated company in the form of a joint venture between Technip SA and DOF Subsea and was founded in 2006. Dofcon provides Pipe-Laying Support Vessels (PLSVs) for work in oil and gas fields offshore Brazil. Dofcon is considered a VIE because it does not have sufficient equity to finance its activities without additional subordinated financial support from other parties. We are not the primary beneficiary of the VIE. As such, we have accounted for our 50% investment using the equity method of accounting with results reported in our Subsea segment.

Serimax Holdings SAS (“Serimax”) - is an affiliated company in the form of a joint venture between Technip SA and Vallourec SA and was founded in 2016. Serimax is headquartered in Paris, France and provides rigid pipes welding services for work in oil and gas fields around the world. We have accounted for our 20% investment using the equity method of accounting with results reported in our Subsea segment.

Magma Global Limited (“Magma Global”) - is an affiliated company in the form of a collaborative agreement signed in 2018 between Technip-Coflexip UK Holdings Limited and Magma Global to develop hybrid flexible pipe for use in offshore applications. As part of the collaboration, TechnipFMC holds a minority stake. We have accounted for our 25% investment using the equity method investment of accounting with results reported in our Subsea segment.

Yamgaz SNC (“Yamgaz”) - In 2015, Yamgaz was an affiliated company in the form of a joint venture between Technip, JGC Corporation (“JGC”), and Chiyoda International Corporation (“Chiyoda”). Yamgaz was formed in 2013 when it was awarded a contract to carry out the engineering, procurement, supply, construction and commissioning of an integrated facility for natural gas liquefaction based on the resources of the South Tambey Gas Condensate field located on the Yamal Peninsula, Russia. In the fourth quarter of 2016, we obtained voting control interests in legal onshore/offshore contract entities which own and account for the design, engineering and construction of the Yamal LNG plant. Prior to the amendments of the contractual terms that provided us with voting interest control, we accounted for our 50% investment using the equity method of accounting with results reported in our Onshore/Offshore segment. Subsequent to this transaction we recorded the results in our consolidated financial information.

The following table presents summarized financial information of the equity method investments:



(In millions)	2016 ^(a)
Year ended December 31
Revenues	$	6,782.9
Gross profit	461.0
Net income (loss)	(348.4		)

(a)

As discussed above, in the fourth quarter of 2016, we obtained the voting control interests of legal Onshore/Offshore entities that own and account for the design, engineering and construction of Yamal. As a result of the acquisition and consolidation, we recorded $3.5 billion in cash, $601.7 million in advances to suppliers, $71.1 million in intangibles, $3.8 billion in current liabilities, $191.2 million in noncurrent liabilities, and a $7.7 million gain.


(b)	As of December 31, 2018 and 2017, our equity method investments were no longer significant individually or in the aggregate. As such, summarized financial information for 2018 and 2017 is not presented.

NOTE 10. RELATED PARTY TRANSACTIONS

Receivables, payables, revenues and expenses which are included in our consolidated financial statements for all transactions with related parties, defined as entities related to our directors and main shareholders as well as the partners of our consolidated joint ventures, were as follows.

Trade receivables consisted of receivables due from following related parties:



	December 31,
(In millions)	2018		2017
TP JGC Coral France SNC	$	31.6	$	42.5
Technip Odebrecht PLSV CV	10.9		13.8
Anadarko Petroleum Company	4.9		22.3
Others	14.3		19.8
Total trade receivables	$	61.7	$	98.4

TP JGC Coral France SNC and Technip Odebrecht PLSV CV are equity method affiliates. A member of our Board of Directors serves on the Board of Directors of Anadarko Petroleum Company.

Trade payables consisted of payables due to following related parties:



	December 31,
(In millions)	2018		2017
Dofcon Navegacao	$	2.5	$	12.3
Chiyoda	70.0		48.3
JGC Corporation	69.5		52.4
IFP Energies nouvelles	2.4		—
Anadarko Petroleum Company	0.7		—
Magma Global Limited	0.6		—
Others	2.9		8.8
Total trade payables	$	148.6	$	121.8

Dofcon Navegacao and Magma Global Limited are equity affiliates. JGC Corporation and Chiyoda are joint venture partners on our Yamal project. A member of our Board of Directors is an executive officer of IFP Energies nouvelles.

Additionally, we have note receivable balance of $130.0 million and $140.9 million as of December 31, 2018 and 2017, respectively. The note receivables balance includes $119.9 million and $114.9 million with Dofcon Brasil AS at December 31, 2018 and 2017, respectively. Dofcon Brasil AS is a VIE and accounted for as an equity method affiliate. These are included in other noncurrent assets on our consolidated balance sheets.

Revenue consisted of amount from following related parties:



	Year Ended December 31,
(In millions)	2018		2017		2016
Anadarko Petroleum Company	$	124.8	$	111.3	$	—
TP JGC Coral France SNC	$	118.2	$	—	$	—
Yamgaz	—		—		196.7
Others	50.3		126.8		87.8
Total revenue	$	293.3	$	238.1	$	284.5

Expenses consisted of amount to following related parties:



	Year Ended December 31,
(In millions)	2018		2017		2016
Chiyoda	$	53.0	$	44.1	$	—
JGC Corporation	81.2		46.8		—
Heerema	—		—		71.3
IFP Energy nouvelles	4.4		—		—
Creowave OY	1.9		4.7		—
Arkema S.A.	2.6		—		—
Magma Global Limited	3.0		—		—
Others	8.6		45.8		34.2
Total expenses	$	154.7	$	141.4	$	105.5

NOTE 11. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	December 31,
(In millions)	2018			2017
Land and land improvements	$	103.5		$	105.2
Buildings	656.7			691.2
Vessels	1,893.3			2,246.0
Machinery and equipment	1,905.7			1,892.2
Office fixtures and furniture	300.0			350.4
Construction in process	179.0			136.7
Other	290.1			397.7
	5,328.3			5,819.4
Accumulated depreciation	(2,068.5		)	(1,947.9		)
Property, plant and equipment, net	$	3,259.8		$	3,871.5

Depreciation expense was $367.8 million, $370.2 million and $283.2 million in 2018, 2017 and 2016, respectively. The amount of interest cost capitalized was not material for the years presented.

During 2018, we determined the carrying amount of certain of our vessels exceeded their fair value and recorded an impairment. Refer to Note 17 to these consolidated financial statements for additional information regarding this impairment.

NOTE 12. GOODWILL AND INTANGIBLE ASSETS

Goodwill - We record goodwill as the excess of the purchase price over the fair value of the net assets acquired in acquisitions accounted for under the purchase method of accounting. We test goodwill for impairment annually, or more frequently if circumstances indicate possible impairment. We identify a potential impairment by comparing the fair value of the applicable reporting unit to its net book value, including goodwill. If the net book value exceeds the fair value of the reporting unit, we measure the impairment by comparing the carrying value of the reporting unit to its fair value.

We test our goodwill for impairment by comparing the fair value of each of our reporting units to their net carrying value as of October 31 of each year. Our impairment analysis is quantitative; however, it includes subjective estimates based on assumptions regarding future growth rates, interest rates and operating expenses.

The excess of fair value over carrying amount for our Surface Technologies and Onshore/Offshore reporting units ranged from approximately 56% to in excess of 200% of the respective carrying amounts.

During the year ended December 31, 2018, we recorded $1,383.0 million of goodwill impairment charges in our Subsea reporting unit. Refer to Note 17 to these consolidated financial statements for additional disclosure related to impairment of goodwill during the year ended December 31, 2018.

The following table presents the significant estimates used by management in determining the fair values of our reporting units at December 31, 2018:



	2018
Year of cash flows before terminal value	5
Discount rates	12.0% to 13.0%
EBITDA multiples	7.0 - 8.5x

For recently acquired reporting units, a quantitative impairment test may indicate a fair value that is substantially similar to the reporting unit’s carrying amount. Such similarities in value are generally an indication that management’s estimates of future cash flows associated with the recently acquired reporting unit remain relatively consistent with the assumptions that were used to derive its initial fair value.

As discussed above, when evaluating the 2018 quantitative impairment test results, management considered many factors in determining whether an impairment of goodwill for any reporting unit was reasonably likely to occur in future periods, including future market conditions and the economic environment. Circumstances such as market declines, unfavorable economic conditions, loss of a major customer or other factors could increase the risk of impairment of goodwill for this reporting unit in future periods.

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



(In millions)	Subsea			Onshore/Offshore			Surface Technologies		Total
December 31, 2015	$	2,977.4		$	809.1		$	—	$	3,786.5
Additions due to business combinations	—			—			—		—
Impairment	—			—			—		—
Translation	(46.3		)	(21.9		)	—		(68.2		)
December 31, 2016	2,931.1			787.2			—		3,718.3
Additions due to business combinations	2,532.6			1,635.5			997.8		5,165.9
Impairment	—			—			—		—
Translation	6.7			38.9			—		45.6
December 31, 2017	5,470.4			2,461.6			997.8		8,929.8
Additions due to business combinations	85.0			—			—		85.0
Impairment	(1,383.0		)	—			—		(1,383.0		)
Purchase accounting adjustments	—			—			19.7		19.7
Translation	(30.0		)	(13.9		)	—		(43.9		)
December 31, 2018	$	4,142.4		$	2,447.7		$	1,017.5	$	7,607.6

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



	December 31,
	2018				2017
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Acquired technology	$	246.7	$	49.3	$	240.0	$	25.0
Backlog	175.0		175.0		175.0		118.0
Customer relationships	285.0		57.4		285.0		29.0
Licenses, patents and trademarks	812.6		194.8		810.1		157.7
Software	232.1		159.1		237.9		145.5
Other	84.3		23.4		72.7		11.7
Total intangible assets	$	1,835.7	$	659.0	$	1,820.7	$	486.9

In connection with the Merger, we recorded identifiable intangible assets acquired. Refer to Note 2 to these consolidated financial statements for additional information regarding the Merger. All of our acquired identifiable intangible assets are subject to amortization and, where applicable, foreign currency translation adjustments.

We recorded $182.6 million, $244.5 million and $17.5 million in amortization expense related to intangible assets during the years ended December 31, 2018, 2017 and 2016, respectively. During the years 2019 through 2023, annual amortization expense is expected to be as follows: $126.4 million in 2019, $121.2 million in 2020, $116.5 million in 2021, $112.4 million in 2022, $107.5 million in 2023 and $592.7 million thereafter.

NOTE 13. DEBT

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)	2018		2017
Bank borrowings	44.2		48.9
Other	23.2		28.2
Total short-term debt and current portion of long-term debt	$	67.4	$	77.1

100

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



	December 31,
(In millions)	2018			2017
Revolving credit facility	$	—		$	—
Bilateral credit facilities	—			—
Commercial paper ^(a)	1,916.1			1,450.4
Synthetic bonds due 2021	490.9			502.4
3.45% Senior Notes due 2022	500.0			500.0
5.00% 2010 Private placement notes due 2020	229.0			239.9
3.40% 2012 Private placement notes due 2022	171.8			179.9
3.15% 2013 Private placement notes due 2023	148.9			155.9
3.15% 2013 Private placement notes due 2023	143.1			149.9
4.00% 2012 Private placement notes due 2027	85.9			89.9
4.00% 2012 Private placement notes due 2032	114.5			119.9
3.75% 2013 Private placement notes due 2033	114.5			119.9
Bank borrowings	265.2			332.5
Other	23.2			28.2
Unamortized issuing fees	(11.4		)	(13.8		)
Total debt	4,191.7			3,855.0
Less: current borrowings	67.4			77.1
Long-term debt	$	4,124.3		$	3,777.9


(a)	At December 31, 2018 and 2017, committed credit available under our revolving credit facility provided the ability to refinance our commercial paper obligations on a long-term basis.

Maturities of debt as of December 31, 2018, 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
Total debt	$	4,191.7	$	67.4	$	2,854.2	$	962.9	$	307.2

Revolving credit facility - On January 17, 2017, we acceded to a new $2.5 billion senior unsecured revolving credit facility agreement (“facility agreement”) between FMC Technologies, Inc., Technip Eurocash SNC (the “Borrowers”), and TechnipFMC plc (the “Additional Borrower”) with JPMorgan Chase Bank, National Association (“JPMorgan”), as agent and an arranger, SG Americas Securities LLC as an arranger, and the lenders party thereto.

The facility agreement provides for the establishment of a multicurrency, revolving credit facility, which includes a $1.5 billion letter of credit subfacility. Subject to certain conditions, the Borrowers may request the aggregate commitments under the facility agreement be increased by an additional $500.0 million. On November 26, 2018, we entered into an extension which extends the expiration date to January 2023.

Borrowings under the facility agreement bear interest at the following rates, plus an applicable margin, depending on currency:


•	U.S. dollar-denominated loans bear interest, at the Borrowers’ option, at a base rate or an adjusted rate linked to the London interbank offered rate (“Adjusted LIBOR”);


•	sterling-denominated loans bear interest at Adjusted LIBOR; and


•	euro-denominated loans bear interest at the Euro interbank offered rate (“EURIBOR”).

Depending on the credit rating of TechnipFMC, the applicable margin for revolving loans varies (i) in the case of Adjusted LIBOR and EURIBOR loans, from 0.820% to 1.300% and (ii) in the case of base rate loans, from 0.000% to 0.300%. The “base rate” is the highest of (a) the prime rate announced by JPMorgan, (b) the greater of the Federal Funds Rate and the Overnight Bank Funding Rate plus 0.5% or (c) one-month Adjusted LIBOR plus 1.0%.

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The facility agreement contains usual and customary covenants, representations and warranties and events of default for credit facilities of this type, including financial covenants requiring that our total capitalization ratio not exceed 60% at the end of any financial quarter. The facility agreement also contains covenants restricting our ability and our subsidiaries’ ability to incur additional liens and indebtedness, enter into asset sales or make certain investments.

As of December 31, 2018, we were in compliance with all restrictive covenants under our revolving credit facility.

Bilateral credit facilities - We have access to four bilateral credit facilities in the aggregate of €320.0 million. The bilateral credit facilities consist of:


•	two credit facilities of €80.0 million each expiring in May 2019;


•	a credit facility of €60.0 million expiring in June 2019; and


•	a credit facility of €100.0 million expiring in May 2021.

Each bilateral credit facility contains usual and customary covenants, representations and warranties and events of default for credit facilities of this type.

Commercial paper - Under our commercial paper program, we have the ability to access $1.5 billion and €1.0 billion of short-term financing through our commercial paper dealers, subject to the limit of unused capacity of our facility agreement. 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 as of December 31, 2018 and December 31, 2017. Commercial paper borrowings are issued at market interest rates. As of December 31, 2018, our commercial paper borrowings had a weighted average interest rate of 3.07% on the U.S. dollar denominated borrowings and (0.24)% on the Euro denominated borrowings.

Synthetic bonds - On January 25, 2016, we issued €375.0 million principal amount of 0.875% convertible bonds with a maturity date of January 25, 2021 and a redemption at par of the bonds which have not been converted. On March 3, 2016, we issued additional convertible bonds for a principal amount of €75.0 million issued on the same terms, fully fungible with and assimilated to the bonds issued on January 25, 2016. The issuance of these non-dilutive cash-settled convertible bonds (“Synthetic Bonds”), which are linked to our ordinary shares were backed simultaneously by the purchase of cash-settled equity call options in order to hedge our economic exposure to the potential exercise of the conversion rights embedded in the Synthetic Bonds. As the Synthetic Bonds will only be cash settled, they will not result in the issuance of new ordinary shares or the delivery of existing ordinary shares upon conversion. Interest on the Synthetic Bonds is payable semi-annually in arrears on January 25 and July 25 of each year, beginning July 26, 2016. Net proceeds from the Synthetic Bonds were used for general corporate purposes and to finance the purchase of the call options. The Synthetic Bonds are our unsecured obligations. The Synthetic Bonds will rank equally in right of payment with all of our existing and future unsubordinated debt.

The Synthetic Bonds issued on January 25, 2016 were issued at par. The Synthetic Bonds issued on March 3, 2016 were issued at a premium of 112.43802% resulting from an adjustment over the 3-day trading period following the issuance resulting in a share reference price of €48.8355.

A 40.0% conversion premium was applied to the share reference price of €40.7940. The share reference price was computed using the average of the daily volume weighted average price of our ordinary shares on the Euronext Paris market over the 10 consecutive trading days from January 21 to February 3, 2016. The initial conversion price of the bonds was then fixed at €57.1116.

The Synthetic Bonds each have a nominal value of €100.0 thousand with a conversion ratio of 3,359.7183 and a conversion price of €29.7644. Any bondholder may, at its sole option, request the conversion in cash of all or part of the bonds it owns, beginning November 15, 2020 to the 38th business day before the maturity date.

Senior Notes - On February 28, 2017, we commenced offers to exchange any and all outstanding notes issued by FMC Technologies for up to $800.0 million aggregate principal amount of new notes issued by TechnipFMC and cash. In conjunction with the offers to exchange, FMC Technologies solicited consents to adopt certain proposed amendments to each of the indentures governing the previously issued notes to eliminate certain covenants, restrictive provisions and events of defaults from such indentures.

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On March 29, 2017, we settled the offers to exchange and consent solicitations (the “Exchange Offers”) for (i) any and all 2.00% senior notes due October 1, 2017 (the “2017 FMC Notes”) issued by FMC Technologies for up to an aggregate principal amount of $300.0 million of new 2.00% senior notes due October 1, 2017 (the “2017 Senior Notes’) issued by TechnipFMC and cash, and (ii) any and all 3.45% senior notes due October 1, 2022 (the “2022 FMC Notes”) issued by FMC Technologies for up to an aggregate principal amount of $500.0 million in new 3.45% senior notes due October 1, 2022 (the “2022 Senior Notes”) issued by TechnipFMC with registration rights and cash. Pursuant to the Exchange Offers, we issued approximately $215.4 million in aggregate principal amount of 2017 Senior Notes and $459.8 million in aggregate principal amount of 2022 Senior Notes (collectively the “Senior Notes”). Interest on the 2017 Senior Notes is payable on October 1, 2017. Interest on the 2022 Senior Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2017.

On April 3, 2018, we commenced offers to exchange up to $459.8 million in aggregate principal amount of new 3.45% Senior Notes due 2022, Series B, which have been registered under the U.S. Securities Act of 1933, as amended (the “Securities Act”), for any and all of our outstanding restricted 3.45% Senior Notes due 2022, Series A (the “Outstanding Notes”), which we previously issued in a private transaction that was not subject to the registration requirements of the Securities Act (the “Initial Offering”). We refer to the Exchange Notes and the Outstanding Notes collectively as the “Notes”.

The terms of the Senior Notes are governed by the indenture, dated as of March 29, 2017 between TechnipFMC and U.S. Bank National Association, as trustee (the “Trustee”), as amended and supplemented by the First Supplemental Indenture between TechnipFMC and the Trustee (the “First Supplemental Indenture”) relating to the issuance of the 2017 Notes and the Second Supplemental Indenture between TechnipFMC and the Trustee (the “Second Supplemental Indenture”) relating to the issuance of the 2022 Notes.

At maturity, all outstanding amounts under the 2017 Senior Notes were repaid.

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 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.

Private Placement Notes - On July 27, 2010, we completed the private placement of €200.0 million aggregate principal amount of 5.0% notes due July 2020 (the “2020 Notes”). Interest on the 2020 Notes is payable annually in arrears on July 27 of each year, beginning July 27, 2011. Net proceeds of the 2020 Notes were used to partially finance the 2004-2011 bond issue, which was repaid at its maturity date on May 26, 2011. The 2020 Notes contain contains usual and customary covenants and events of default for notes of this type. In the event of a change of control resulting in a downgrade in the rating of the notes below BBB-, the 2020 Notes may be redeemed early by any bondholder, at its sole discretion. The 2020 Notes are our unsecured obligations. The 2020 Notes will rank equally in right of payment with all of our existing and future unsubordinated debt.

In June 2012, we completed the private placement of €325.0 million aggregate principal amount of notes. The notes were issued in three tranches with €150.0 million bearing interest at 3.40% and due June 2022 (the “Tranche A 2022 Notes”), €75.0 million bearing interest of 4.0% and due June 2027 (the “Tranche B 2027 Notes”) and €100.0 million bearing interest of 4.0% and due June 2032 (the “Tranche C 2032 Notes” and, collectively with the “Tranche A 2022 Notes and the “Tranche B 2027 Notes”, the “2012 Private Placement Notes”). Interest on the Tranche A 2022 Notes and the Tranche C 2032 Notes is payable annually in arrears on June 14 of each year beginning June 14, 2013. Interest on the Tranche B 2027 Notes is payable annually in arrears on June 15 of each year, beginning June 15, 2013. Net proceeds of the 2012 Private Placement Notes were used for general corporate purposes. The 2012 Private Placement Notes contain usual and customary covenants and events of default for notes of this type. In the event of a change of control resulting in a downgrade in the rating of the notes below BBB-, the 2012 Private Placement Notes may be redeemed early by any bondholder, at its sole discretion. The 2012 Private Placement Notes are our unsecured obligations. The 2012 Private Placement Notes will rank equally in right of payment with all of our existing and future unsubordinated debt.

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In October 2013, we completed the private placement of €355.0 million aggregate principal amount of senior notes. The notes were issued in three tranches with €100.0 million bearing interest at 3.75% and due October 2033 (the “Tranche A 2033 Notes”), €130.0 million bearing interest of 3.15% and due October 2023 (the “Tranche B 2023 Notes) and €125.0 million bearing interest of 3.15% and due October 2023 (the “Tranche C 2023 Notes” and, collectively with the “Tranche A 2033 Notes and the “Tranche B 2023 Notes”, the “2013 Private Placement Notes”). Interest on the Tranche A 2033 Notes is payable annually in arrears on October 7 each year, beginning October 7, 2014. Interest on the Tranche B 2023 Notes is payable annually in arrears on October 16 of each year beginning October 16, 2014. Interest on the Tranche C 2023 Notes is payable annually in arrears on October 18 of each year, beginning October 18, 2014. Net proceeds of the 2013 Private Placement Notes were used for general corporate purposes. The 2013 Private Placement Notes contain contains usual and customary covenants and events of default for notes of this type. In the event of a change of control resulting in a downgrade in the rating of the notes below BBB-, the 2013 Private Placement Notes may be redeemed early by any bondholder, at its sole discretion. The 2013 Private Placement Notes are our unsecured obligations. The 2013 Private Placement Notes will rank equally in right of payment with all of our existing and future unsubordinated debt.

Term loan - In December 2016, we entered into a £160.0 million term loan agreement to finance the Deep Explorer, a diving support vessel (“DSV”), maturing December 2028. Under the loan agreement, interest accrues at an annual rate of 2.813%. This loan agreement contains usual and customary covenants and events of default for loans of this type.

Foreign committed credit - We have committed credit lines at many of our international subsidiaries for immaterial amounts. We utilize these facilities for asset financing and to provide a more efficient daily source of liquidity. The effective interest rates depend upon the local national market.

NOTE 14. OTHER LIABILITIES

In the fourth quarter of 2016, we obtained voting control interests in legal onshore/offshore contract entities which own and account for the design, engineering and construction of the Yamal LNG plant. Prior to the amendments of the contractual terms that provided us with voting interest control, we accounted for these entities under the equity method of accounting based on our previously held interests in each of these entities. Since nearly all substantive processes to perform and execute the obligations of the underlying contract are conducted by TechnipFMC and the noncontrolling interest holders, we accounted for these entities as an acquisition upon our obtaining control and recognized a net gain of $7.7 million during 2016. As of December 31, 2016, total assets, liabilities and equity related to these entities were consolidated onto our balance sheet and our results of operations for the year ended December 31, 2018 and 2017 reflect the consolidated results of operations related to these entities. Refer to Note 9 for further information regarding the acquisition and consolidation of these entities.

A mandatorily redeemable financial liability of $312.0 million was recognized as of December 31, 2017 to account for the fair value of the non-controlling interests, for which $69.7 million was recorded as other current liabilities. During the year ended December 31, 2018 we revalued the liability to reflect current expectations about the obligation which resulted in the recognition of a loss of $322.3 million for the year ended December 31, 2018. Changes in the fair value of the financial liability are recorded as interest expense on the consolidated statements of income. Refer to Note 8 for further information regarding our other current liabilities. Refer to Note 22 for further information regarding the fair value measurement assumptions of the mandatorily redeemable financial liability and related changes in its fair value.

NOTE 15. STOCKHOLDERS’ EQUITY

Dividends declared and paid during the year ended December 31, 2018 were $238.1 million.

Dividends declared and paid during the year ended December 31, 2017 were $60.6 million.

Dividends declared and paid during the year ended December 31, 2016 based on the results of the year ended December 31, 2015 were €236.6 million. The dividends were paid in cash and shares in the amount of €100.8 million and €135.8 million, respectively.

As an English public limited company, we are required under U.K. law to have available “distributable reserves” to conduct share repurchases or pay dividends to shareholders. Distributable reserves are a statutory requirement and are not linked to a U.S. GAAP reported amount (e.g. retained earnings). The declaration and payment of dividends require the authorization of our Board of Directors, provided that such dividends on issued share capital

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may be paid only out of our “distributable reserves” on our statutory balance sheet. Therefore, we are not permitted to pay dividends out of share capital, which includes share premium.

The following is a summary of our capital stock activity for the years ended December 31, 2018, 2017 and 2016:



(Number of shares in millions)	Ordinary Shares Issued		Ordinary Shares Held in Employee Benefit Trust	Treasury Stock
December 31, 2015	119.0		—	0.8
Stock awards	0.2		—	(0.4	)
Treasury stock purchases	—		—	3.2
Dividend payment in shares	3.2		—	—
Shares acquired pursuant to liquidity contract	—		—	1.3
Shares sold pursuant to liquidity contract	—		—	(1.4	)
Cancellation of treasury shares	(3.2	)	—	(3.2	)
December 31, 2016	119.2		—	0.3
Net capital increases due to the merger of FMC Technologies and Technip	347.4		—	—
Stock awards	0.6		—	—
Treasury stock cancellation due to the merger of FMC Technologies and Technip	—		—	(0.3	)
Treasury stock purchases	—		—	2.1
Treasury stock cancellation	(2.1	)	—	(2.1	)
Net stock purchased for employee benefit trust	—		0.1	—
December 31, 2017	465.1		0.1	—
Net capital increase as per merger	—		—	—
Stock awards	0.2		—	—
Treasury stock purchases	—		—	14.8
Treasury stock cancellation	(14.8	)	—	(14.8	)
Net stock purchased for employee benefit trust	—		—	—
December 31, 2018	450.5		0.1	—

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

In April 2017, the Board of Directors authorized the repurchase of $500.0 million in ordinary shares under our share repurchase program. We implemented our share repurchase plan in September 2017. The Board of Directors authorized an extension of this program, adding $300.0 million in December 2018 for a total of $800.0 million in ordinary shares. We repurchased 14.8 million of ordinary shares for a total consideration of $442.6 million during the year ended December 31, 2018, under our authorized share repurchase program. The $500.0 million part of the program was completed on December 20, 2018. We intend to cancel repurchased shares and not hold them in treasury. Canceled treasury shares are accounted for using the constructive retirement method.

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Accumulated other comprehensive income (loss) - Accumulated other comprehensive income (loss) consisted of the following:



(In millions)	Foreign Currency Translation			Hedging			Defined Pension and Other Post-Retirement Benefits			Accumulated Other Comprehensive Loss attributable to TechnipFMC plc			Accumulated Other Comprehensive Loss attributable to Non-controlling interest
December 31, 2016	$	(927.1	)	$	(127.1	)	$	(47.4	)	$	(1,101.6	)	$	0.2
Other comprehensive income (loss) before reclassifications, net of tax	(87.5		)	53.7			43.2			9.4			0.4
Reclassification adjustment for net (gains) losses included in net income, net of tax	—			101.2			(12.7		)	88.5			—
Other comprehensive income (loss), net of tax	(87.5		)	154.9			30.5			97.9			0.4
December 31, 2017	(1,014.6		)	27.8			(16.9		)	(1,003.7		)	0.6
Other comprehensive income (loss) before reclassifications, net of tax	(178.7		)	(58.7		)	(74.5		)	(311.9		)	(4.6		)
Reclassification adjustment for net (gains) losses included in net income, net of tax	(41.1		)	(2.0		)	(1.0		)	(44.1		)	—
Other comprehensive income (loss), net of tax	(219.8		)	(60.7		)	(75.5		)	(356.0		)	(4.6		)
December 31, 2018	$	(1,234.4	)	$	(32.9	)	$	(92.4	)	$	(1,359.7	)	$	(4.0	)

Reclassifications out of accumulated other comprehensive income (loss) - Reclassifications out of accumulated other comprehensive income (loss) consisted of the following:



	Year Ended
(In millions)	December 31, 2018			December 31, 2017			December 31, 2016
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 on foreign currency translation	$	41.1		$	—		—			Other income (expense), net

Gains (losses) on hedging instruments
Foreign exchange contracts	$	(2.4	)	$	(39.3	)	$	—		Revenue
	3.4			5.3			—			Costs of sales
	(0.1		)	0.8			—			Selling, general and administrative expense
	1.0			(102.2		)	(165.7		)	Other (expense), net
	1.9			(135.4		)	(165.7		)	Income before income taxes
	(0.1		)	(34.2		)	(45.6		)	Provision (benefit) for income taxes
	$	2.0		$	(101.2	)	$	(120.1	)	Net income

Pension and other post-retirement benefits
Settlements and curtailments	$	3.0		$	25.3		$	10.7		(a)
Amortization of actuarial gain (loss)	(0.6		)	(2.5		)	(1.0		)	(a)
Amortization of prior service credit (cost)	(1.3		)	(1.0		)	(0.7		)	(a)
	1.1			21.8			9.0			Income before income taxes
	0.1			9.1			2.8			Provision (benefit) for income taxes
	$	1.0		$	12.7		$	6.2		Net income


(a)	These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 20 for additional details).

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NOTE 16. SHARE-BASED COMPENSATION

Incentive compensation and award plan - On January 11, 2017, we adopted the TechnipFMC plc Incentive Award Plan (the “Plan”). The Plan provides certain incentives and awards to officers, employees, non-employee directors and consultants of TechnipFMC and its subsidiaries. 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 may include share options, share appreciation rights, performance share units, restricted share units, restricted shares or other awards authorized under the Plan. All awards are subject to the Plan’s provisions, including all share-based grants previously issued by FMC Technologies and Technip prior to consummation of the Merger. Under the Plan, 24.1 million ordinary shares were authorized for awards. At December 31, 2018, 18.2 million ordinary shares were available for future grant.

The exercise price for options is determined by the Committee but cannot be less than the fair market value of our ordinary shares at the grant date. Restricted share and performance share unit grants generally vest after three years of service.

Under the Plan, our Board of Directors has the authority to grant non-employee directors share options, restricted shares, restricted share units and performance shares. Unless otherwise determined by our Board of Directors, awards to non-employee directors generally vest one year from the date of grant. Restricted share units are settled when a director ceases services to the Board of Directors. At December 31, 2018, outstanding awards to active and retired non-employee directors included 119.4 thousand share units.

The measurement of share-based compensation expense on restricted share awards is based on the market price and fair value at the grant date and the number of shares awarded. The fair value of performance shares is estimated using a combination of the closing stock price on the grant date and the Monte Carlo simulation model. We used the Cox Ross Rubinstein binomial model to measure the fair value of stock options granted prior to December 31, 2016 and Black-Scholes options pricing model to measure the fair value of stock options granted on or after January 1, 2017.

The share-based compensation expense for each award is recognized ratably over the applicable service period or the period beginning at the start of the service period and ending when an employee becomes eligible for retirement (currently age 62 under the plan), after taking into account estimated forfeitures.

We recognize compensation expense and the corresponding tax benefits for awards under the Plan. The compensation expense under the Plan is as follows:



	Year Ended December 31,
(In millions)	2018		2017		2016
Share-based compensation expense ⁽¹⁾	$	49.1	$	44.4	$	22.0
Income tax benefits related to share-based compensation expense	$	13.2	$	12.0	$	5.9

⁽¹⁾Expense recognized for the year ended 2016 relates to Technip’s historical incentive and compensation award plan.

As of December 31, 2018, the portion of share-based compensation expense related to outstanding awards to be recognized in future periods is as follows:



	December 31, 2018
Share-based compensation expense not yet recognized (in millions)	$	83.4
Weighted-average recognition period (in years)	1.7

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Restricted Share Units

We began issuing restricted share units 2017. A summary of the nonvested restricted share units activity is as follows:



(Shares in thousands)	Shares		Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2017	1,722.3		$	28.53
Granted	1,516.0		$	31.57
Vested	(165.4	)	$	28.94
Cancelled/forfeited	(95.5	)	$	27.85
Nonvested at December 31, 2018	2,977.4		$	30.10

The total grant date fair value of restricted stock units vested during years ended December 31, 2018 and 2017 was $4.8 million and nil, respectively.

Performance Shares

The Board of Directors has granted certain employees, senior executives and Directors or Officers restricted share units that vest subject to achieving satisfactory performances. For performance shares issued prior to December 31, 2016, performance is based on results in terms of health/safety/environment, operating income from recurring activities, and treasury generated from operating activities and total shareholder return (“TSR”). For performance share units issued on or after January 1, 2017, performance is based on results of return on invested capital and TSR.

For the performance share units which vest based on TSR, the fair value of performance shares is estimated using a combination of the closing stock price on the grant date and the Monte Carlo simulation model. The weighted-average fair value and the assumptions used to measure the fair value of performance share units subject to performance-adjusted vesting conditions in the Monte Carlo simulation model were as follows:



	Year Ended December 31,
	2018		2017		2016
Weighted-average fair value ^(a)	$41.97		$34.42		$22.47
Expected volatility ^(b)	34.00	%	34.87	%	31.30	%
Risk-free interest rate ^(c)	2.37	%	1.50	%	0.85	%
Expected performance period in years ^(d)	3.0		3.0		2.8

(a) The weighted-average fair value was based on performance share units granted during the period.

(b) Expected volatility is based on normalized historical volatility of our shares over a preceding period commensurate with the expected term of the option.

(c) From 2017, the risk-free rate for the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Prior to 2017, the risk free rate was based on the bond yields from the European Central Bank.

(d) For awards subject to service-based vesting, due to the lack of historical exercise and post-vesting termination patterns of the post-Merger employee base, the expected term was estimated using a simplified method for all awards granted in 2018 and 2017 and the expected term was estimated using historical exercise and post-vesting termination patterns for all awards granted in 2016.

A summary of the nonvested performance share unit activity is as follows:



(Shares in thousands)	Shares		Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2017	2,748.8		$	25.59
Granted	623.0		$	36.06
Vested	(203.6	)	$	34.55
Cancelled/forfeited	(124.4	)	$	28.45
Nonvested at December 31, 2018	3,043.8		$	27.02

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The total grant date fair value of performance share units vested during years ended December 31, 2018, 2017 and 2016 was $7.0 million, $33.3 million and $7.5 million, respectively.

Share Option Awards

The fair value of each option award is estimated as of the date of grant using the Black-Scholes options pricing model or the Cox Ross Rubinstein binomial model.

Share options awarded prior to 2017 were granted subject to performance criteria based upon certain targets, such as TSR, return on capital employed, and operating income from recurring activities. Subsequent share options granted are time based awards vesting over a three year period.

The weighted-average fair value and the assumptions used to measure fair value are as follows:



	Year Ended December 31,
	2018			2017			2016
Weighted-average fair value ^(a)	$	9.07		$	8.79		€	7.7
Expected volatility ^(b)	32.5		%	35.7		%	34.5		%
Risk-free interest rate ^(c)	2.7		%	2.1		%	—		%
Expected dividend yield ^(d)	2.0		%	2.0		%	2.0%-4.5%
Expected term in years ^(e)	6.5			6.5			4.2


(a)	The weighted-average fair value was based on stock options granted during the period.


(b)	Expected volatility is based on normalized historical volatility of our shares over a preceding period commensurate with the expected term of the option.


(c)	From 2017, the risk-free rate for the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Prior to 2017, the risk free rate was based on the bond yields from the European Central Bank.


(d)	Share options awarded prior to 2017 were valued using an expected dividend yield of between 2.0% and 4.5% while those awarded in 2017 and 2018 used 2.0%.


(e)	For awards subject to service-based vesting, due to the lack of historical exercise and post-vesting termination patterns of the post-Merger employee base, the expected term was estimated using a simplified method for all awards granted in 2018 and 2017 and the expected term was estimated using historical exercise and post-vesting termination patterns for all awards granted in 2016.

The following is a summary of option transactions during years ended December 31, 2018, 2017 and 2016:



(Shares in thousands)	Number of shares		Weighted average exercise price		Weighted average remaining life (in years)
Balance as of December 31, 2015	2,420.5		€	61.88	3.5
Granted	595.1		€	48.33
Exercised	(25.5	)	€	57.22
Cancelled	(801.3	)	€	52.43
Balance as of December 31, 2016	2,188.8		€	61.72	5.0
Adjustment due to FMC Technologies transaction ^(a)	2,188.8		$	—
Granted	798.4		$	29.29
Exercised	—		$	—
Cancelled	(292.2	)	$	47.60
Balance as of December 31, 2017	4,883.8		$	36.35	4.6
Granted	602.2		$	30.70
Exercised	—		$	—
Cancelled	(827.6	)	$	47.20
Balance as of December 31, 2018	4,658.4		$	33.68	4.8
Exercisable at December 31, 2018	1,114.9		$	52.37	1.3


(a)	The Weighted-Average Grant Date Fair Value for the increase in shares due to the merger remains at $0.00 in order to recalculate the new weighted average for the December 31, 2016 nonvested shares (see Note 2).

109

The aggregate intrinsic value of stock options outstanding and stock options exercisable as of December 31, 2018 was nil and nil, respectively.

Cash received from the option exercises was nil, nil and €1.5 million during years ended December 31, 2018, 2017 and 2016, respectively. The total intrinsic value of options exercised during the years ended December 31, 2018, 2017 and 2016 was nil, nil and nil, respectively. To exercise stock options, an employee may choose (1) to pay, either directly or by way of the group savings plan, the stock option strike price to obtain shares, or (2) to sell the shares immediately after having exercised the stock option (in this case, the employee does not pay the strike price but instead receives the intrinsic value of the stock options in cash).

The following summarizes significant ranges of outstanding and exercisable options at December 31, 2018:



	Options Outstanding				Options Exercisable
Exercise Price Range	Number of options (in thousands)	Weighted average remaining life (in years)	Weighted average exercise price		Number of options (in thousands)	Weighted average exercise price
$24.00-$33.00	3,543.5	5.9	$	27.80	—	$	—
$45.00-$51.00	570.0	0.4	$	48.12	570.0	$	48.12
$55.00-$57.00	544.9	2.2	$	56.82	544.9	$	56.82
Total	4,658.4	4.8	$	33.67	1,114.9	$	52.37

NOTE 17. IMPAIRMENT, RESTRUCTURING AND OTHER EXPENSE

Impairment, restructuring and other expense were as follows:



	Year Ended December 31,
(In millions)	2018			2017		2016
Impairment expense
Subsea	$	1,784.2		$	11.5	$	23.0
Onshore/Offshore	—			—		14.6
Surface Technologies	4.5			10.2		—
Corporate and other	3.9			12.6		0.6
Total impairment expense	1,792.6			34.3		38.2

Restructuring and other expense
Subsea	$	17.7		$	88.4	$	58.7
Onshore/Offshore	(3.4		)	27.0		214.4
Surface Technologies	9.3			9.0		—
Corporate and other	15.0			32.8		31.7
Total restructuring and other expense	38.6			157.2		304.8
Total impairment, restructuring and other expense	$	1,831.2		$	191.5	$	343.0

Asset impairments - We conduct impairment tests on long-lived assets whenever events or changes in circumstances indicate the carrying value 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 over the asset’s 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. Refer to Note 22 to these consolidated financial statements for a discussion of the method used to determine the fair value of these assets.

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 in our Subsea segment exceeded their fair value. During the year ended December 31, 2018, we recorded $1,784.2 million of impairment charges in our Subsea segment. These charges included impairment of goodwill and vessels of $1,383.0 million and $372.9 million, respectively.

During the year ended December 31, 2017, our impairment expense was primarily related to leasehold improvements, decommissioning vacant buildings and other long-lived assets.

During the year ended December 31, 2016, our impairment expense was primarily associated with the restructuring plan discussed below.

110

Restructuring and other - During 2018 and 2017 we initiated further cost cutting measures that have resulted in restructuring expense primarily related to termination of lease contracts.

In the year ended December 31, 2016, as part of our restructuring plan, we divested and deconsolidated our wholly owned subsidiaries Technip Germany Holding GmBH and Technip Germany GmBH.

In July 2015, 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, we initiated a company-wide reduction in workforce and facility consolidation (the “July 2015 Plan”) intended to reduce costs and better align our workforce with current and anticipated activity levels, which resulted in the continued recognition of severance costs relating to termination benefits and other restructuring charges. The initial plan included a workforce reduction of approximately 6,000 employees.

A significant part of the restructuring plan was focused on the Onshore/Offshore segment. In this segment, we reduced our presence in North America, Latin America, Asia and Europe. In the Subsea segment, we reduced our presence in the North Sea.

NOTE 18. COMMITMENTS AND CONTINGENT LIABILITIES

Commitments associated with leases - We lease office space, manufacturing facilities and various types of manufacturing and data processing equipment. Leases of real estate generally provide for payment of property taxes, insurance and repairs by us. Substantially all of our leases are classified as operating leases. Rent expense under operating leases amounted to $365.1 million, $369.2 million and $313.5 million in 2018, 2017 and 2016, 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, 2018, future minimum rental payments under noncancellable operating leases were:



(In millions)
2019	$	329.8
2020	286.1
2021	192.3
2022	123.8
2023	102.1
Thereafter	485.6
Total	1,519.7
Less income from sub-leases	25.6
Net minimum operating lease payments	$	1,494.1

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. The majority of these financial instruments expire within five years. Management does not expect any of these financial instruments to result in losses that, if incurred, would have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Guarantees consisted of the following:



(In millions)	December 31, 2018
Financial guarantees ^(a)	$	750.4
Performance guarantees ^(b)	4,047.6
Maximum potential undiscounted payments	$	4,798.0

111


(a)	Financial guarantees represent contracts that contingently require a guarantor to make payments to a guaranteed party based on changes in an underlying agreement that is related to an asset, a liability, or an equity security of the guaranteed party. These tend to be drawn down only if there is a failure to fulfill our financial obligations.


(b)	Performance guarantees represent contracts that contingently require a guarantor to make payments to a guaranteed party based on another entity's failure to perform under a nonfinancial obligating agreement. Events that trigger payment are performance related, such as failure to ship a product or provide a service.

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 or disputes in the ordinary course of our business. Management is unable to predict the ultimate outcome of these actions because of their inherent uncertainty. 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.

On March 28, 2016, FMC Technologies received an inquiry from the U.S. Department of Justice ("DOJ") related to the DOJ's investigation of whether certain services Unaoil S.A.M. provided to its clients, including FMC Technologies, violated the U.S. Foreign Corrupt Practices Act ("FCPA"). On March 29, 2016 Technip S.A. also received an inquiry from the DOJ related to Unaoil. We are cooperating with the DOJ's investigations and, with regard to FMC Technologies, a related investigation by the U.S. Securities and Exchange Commission.

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 recognized probable liquidated damages at December 31, 2018 and 2017, and that the ultimate resolution of such matters will not materially affect our consolidated financial position, results of operations, or cash flows.

112

NOTE 19. INCOME TAXES

Components of income (loss) before income taxes - U.S. and outside U.S. components of income (loss) before income taxes were as follows:



	Year Ended December 31,
(In millions)	2018			2017		2016
United States	$	(197.0	)	$	284.3	$	154.3
Outside United States	$	(1,291.1	)	$	395.4	$	397.1
Income (loss) before income taxes	$	(1,488.1	)	$	679.7	$	551.4

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



	Year Ended December 31,
(In millions)	2018		2017		2016
Current
United States	$	52.1	$	30.2	$	54.1
Outside United States	321.8		373.7		298.3
Total current	373.9		403.9		352.4
Deferred
United States	19.5		71.4		(7.2		)
Outside United States	29.3		70.2		(164.9		)
Total deferred	48.8		141.6		(172.1		)
Provision for income taxes	$	422.7	$	545.5	$	180.3

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



	December 31,
(In millions)	2018			2017
Deferred tax assets attributable to
Accrued expenses	$	128.0		$	155.2
Capital Loss	21.2			—
Non-deductible interest	89.3			85.9
Foreign tax credit carryforwards	105.9			34.9
Net operating loss carryforwards	382.8			390.7
Inventories	3.2			13.4
Research and development credit	6.5			7.5
Foreign exchange	32.5			—
Provisions for pensions and other long-term employee benefits	72.4			86.4
Contingencies related to contracts	83.7			111.3
Other contingencies	28.7			33.5
Fair value losses/gains	—			12.4
Margin recognition on construction contracts	34.4			—
Other	15.2			11.1
Deferred tax assets	1,003.8			942.3
Valuation allowance	(683.4		)	(430.0		)
Deferred tax assets, net of valuation allowance	320.4			512.3

Deferred tax liabilities attributable to
Revenue in excess of billings on contracts accounted for under the percentage of completion method	9.2			41.2
U.S. tax on foreign subsidiaries’ undistributed earnings not indefinitely reinvested	9.4			4.9
Foreign exchange	—			21.5
Property, plant and equipment, intangibles and other assets	278.6			403.3
Margin recognition on construction contracts	—			6.4
Deferred tax liabilities	297.2			477.3
Net deferred tax assets/(liabilities)	$	23.2		$	35.0

At December 31, 2018 and 2017, 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, 2018, deferred tax assets include tax benefits 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 non-deductible 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, 2018, deferred tax assets included U.S. foreign tax credit carryforwards of $105.9 million, which, if not utilized, will begin to expire in 2023. 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 our U.S. earnings over the forecast period will not result in sufficient U.S. taxable income to fully realize these deferred tax assets; therefore, we have established a valuation allowance against the related deferred tax assets. In its analysis, management has considered the effect of deemed dividends and other expected adjustments to U.S. earnings that are required in determining U.S. taxable income. Non-U.S. earnings subject to U.S. tax, including deemed dividends for U.S. tax purposes, were $307.6 million in 2018, $1.3 billion in 2017 and nil in 2016.

Net operating loss carryforwards. As of December 31, 2018, deferred tax assets included tax benefits related to net operating loss carryforwards. If not utilized, these net operating loss carryforwards will begin to expire in 2019. 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.

114

The majority of the net operating loss carryforwards are in Brazil ($275.0 million), Saudi Arabia ($271.0 million), Mexico ($185.5 million), Norway ($128.8 million), U.K. ($186.5 million), and Canada ($78.5 million). Except in Canada and Mexico, all of these tax loss carryforwards extend indefinitely.

Unrecognized tax benefits - The following table presents a summary of changes in our unrecognized tax benefits:



(In millions)	Federal, State and Foreign Tax
Balance as of December 31, 2016	$	16.6
Reductions for tax positions related to prior years	(13.6		)
Additions for tax positions related to current year	39.5
Reductions for tax positions due to settlements	(0.2		)
Additions for tax positions related to purchase accounting	48.1
Balance as of December 31, 2017	$	90.4
Reductions for tax positions related to prior years	(11.5		)
Additions for tax positions related to current year	21.1
Reductions for tax positions due to settlements	(9.0		)
Balance as of December 31, 2018	$	91.0

The amounts reported above for uncertain tax positions excludes interest and penalties of $2.8 million, $5.9 million, and nil at December 31, 2018, 2017, and 2016, respectively. Interest and penalties relating to these uncertain tax positions are included in tax expense in our Consolidated Financial Statements. It is reasonably possible that within twelve months, $1.3 million of liabilities for unrecognized tax benefits will be settled. This amount is reflected in income taxes payable, the remaining balance of the unrecognized tax benefits are recorded in other long term liabilities.

We operate in numerous jurisdictions around the world and could be subject to multiple tax audits at any given time. Most notably, the following tax years and thereafter remain subject to examination: 2008 for Norway, 2016 for Nigeria, 2013 for Brazil, 2017 for France, and 2015 for the United States.

As a result of the Merger, TechnipFMC plc is a public limited company incorporated under the laws of England and Wales. Therefore, our earnings are subject to the United Kingdom statutory rate of 19.0% beginning on the effective date of the Merger. Previously these earnings were subject to the French statutory rate of 34.4%. Our consolidated effective income tax rate information has been presented accordingly.

Effective income tax rate reconciliation - The effective income tax rate was different from the statutory federal income tax rate due to the following:



	Year Ended December 31,
	2018		2017		2016
Statutory income tax rate	19.0	%	19.3	%	34.4	%
Net difference resulting from
Foreign earnings subject to different tax rates	(9.7	)%	18.2	%	(18.5	)%
Net change in unrecognized tax benefits	(0.7	)%	4.3	%	3.0	%
Adjustments on prior year taxes	(0.7	)%	(4.4	)%	2.4	%
Change in valuation allowance	(14.4	)%	19.3	%	13.1	%
Deferred tax asset/liability revaluation for tax rate change	(1.7	)%	1.4	%	(0.8	)%
U.S. transition tax	(0.8	)%	17.1	%	—	%
Impairments	(16.5	)%	—	%	—	%
Non-deductible legal provision	(3.8	)%	—	%	—	%
Other	0.9	%	5.1	%	(0.9	)%
Effective income tax rate	(28.4	)%	80.3	%	32.7	%

115

U.S. Tax Cuts and Jobs Act (TCJA) and Other Jurisdictional Tax Reform. Included in the 2017 provision for income taxes are taxes related to the deemed repatriation to the United States of foreign earnings. The Tax Cuts and Jobs Act (TCJA), signed into U.S. law on December 22, 2017, made significant changes to the U.S. federal income taxation of non-U.S. corporate subsidiaries that are controlled by one or more U.S. shareholders. As part of these changes, the TCJA required a onetime deemed repatriation of all accumulated non-U.S. earnings.

The TCJA generally requires that, for the last taxable year of a non-U.S. corporation beginning before January 1, 2018, all U.S. shareholders of such a corporation that is at least 10-percent U.S.-owned must include in income their pro rata share of the corporation’s accumulated post-1986 deferred foreign income that was not previously subject to U.S. tax. Accordingly, the Company recorded income tax expense of approximately $148.7 million in 2017 associated with the deemed repatriation of approximately $2.6 billion of non-U.S. earnings that were not previously subject to U.S. tax. The company recorded additional income tax expense of $11.8 million in 2018 associated with the deemed repatriation of approximately $307 million of non-U.S. earnings that were not previously subject to U.S. tax. The company has recorded no current tax payable associated with the deemed repatriation.

Also included in the 2017 provision for income taxes is the result of the revaluation of deferred tax attributes as a result of changes in corporate tax rates as part of jurisdictional tax reform. The tax expense from the revaluation of U.S. deferred tax attributes is $18.9 million. The tax benefit from the revaluation of deferred tax attributes in other foreign jurisdictions is $9.7 million. For 2018, the tax expense from jurisdictional corporate tax rate reform is $25.6 million.

As a result of the deemed repatriation, U.S. income tax has been provided on all undistributed earnings of non-U.S. subsidiaries of the Company’s U.S. affiliates as of December 31, 2017. The cumulative balance of these undistributed earnings was approximately $2.9 billion as of December 31, 2017.

As of December 31, 2018, we have completed our analysis of the financial statement impact of TCJA and have recorded all amounts associated with our 2017 final and 2018 anticipated compliance filings.

As of the date of the Merger, the cumulative balance of legacy FMC Technologies foreign earnings with respect to which no provision for U.S. income taxes has been recorded was $2.3 billion. Although the parent company of TechnipFMC has since changed jurisdictions, the undistributed foreign earnings previously reported were still liable for U.S. income taxes. In light of 2017’s tax reform, the entirety of the previously untaxed foreign earnings have been taxed via the deemed repatriation accounted for and included in the transition tax which eliminates the company’s liability on such earnings.

Income tax holidays. We benefit from income tax holidays in Singapore and Malaysia which will expire after 2018 for Singapore and 2020 for Malaysia. For the year ended December 31, 2018, these tax holidays reduced our provision for income taxes by $0.1 million, or $0.00 per share on a diluted basis.

NOTE 20. 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.

On December 31, 2017, we amended the retirement plans (the “Plans”) to freeze benefit accruals for all participants of the Plans as of December 31, 2017. After that date, participants in the Plans will no longer accrue any further benefits and participants’ benefits under the Plans will be determined based on credited service and eligible earnings as of December 31, 2017.

Foreign-based employees are eligible to participate in TechnipFMC-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. The most significant of these plans are in the Netherlands, France, Norway and the United Kingdom.

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.

116

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.

117

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, 2018 and 2017, were as follows:



	Pensions												Other Post-retirement Benefits
	2018						2017						2018			2017
(In millions)	U.S.			Int’l			U.S.			Int’l
Accumulated benefit obligation	$	598.1		$	664.3		$	659.8		$	769.9
Projected benefit obligation at January 1	$	659.8		$	898.1		$	—		$	399.6		$	10.0		$	0.9
Service cost	0.2			21.2			10.3			21.0			—			—
Interest cost	23.8			20.9			26.7			19.6			0.4			0.3
Actuarial (gain) loss	(47.9		)	(40.0		)	56.2			(13.5		)	(0.2		)	0.8
Amendments	0.3			2.7			0.2			—			0.1			—
Curtailments	—			(4.0		)	(67.9		)	(2.8		)	—			—
Settlements	(5.3		)	(89.0		)	—			(13.5		)	(0.1		)	—
Foreign currency exchange rate changes	—			(25.7		)	—			68.9			—			—
Plan participants’ contributions	—			1.2			—			1.4			—			—
Benefits paid	(32.8		)	(31.7		)	(27.5		)	(27.6		)	(0.5		)	(0.6		)
Acquisition/Business Combination/Divestiture	—			—			661.9			432.3			—			7.7
Other	—			(0.3		)	(0.1		)	12.7			(0.2		)	0.9
Projected benefit obligation at December 31	598.1			753.4			659.8			898.1			9.5			10.0
Fair value of plan assets at January 1	576.4			699.2			—			229.7			—			—
Actual return on plan assets	(70.7		)	(16.0		)	60.4			63.3			—			—
Company contributions	—			18.5			—			19.1			—			—
Foreign currency exchange rate changes	—			(20.9		)	—			50.4			—			—
Settlements	—			(87.6		)	—			(7.0		)	—			—
Plan participants’ contributions	—			1.2			—			1.4			—			—
Benefits paid	(28.3		)	(23.3		)	(24.8		)	(21.5		)	—			—
Acquisition/Business Combination/Divestiture	—			—			540.8			361.4			—			—
Other	—			(0.5		)	—			2.4			—			—
Fair value of plan assets at December 31	477.4			570.6			576.4			699.2			—			—
Funded status of the plans (liability) at December 31	$	(120.7	)	$	(182.8	)	$	(83.4	)	$	(198.9	)	$	(9.5	)	$	(10.0	)



	Pensions												Other Post-retirement Benefits
	2018						2017						2018			2017
(In millions)	U.S.			Int’l			U.S.			Int’l
Current portion of accrued pension and other post-retirement benefits	$	(5.5	)	$	(7.9	)	$	(5.4	)	$	(4.1	)	$	(0.7	)	$	(0.7	)
Accrued pension and other post-retirement benefits, net of current portion	(115.2		)	(174.9		)	(78.0		)	(194.8		)	(8.8		)	(9.3		)
Funded status recognized in the consolidated balance sheets at December 31	$	(120.7	)	$	(182.8	)	$	(83.4	)	$	(198.9	)	$	(9.5	)	$	(10.0	)

118

The following table summarizes the pre-tax amounts in accumulated other comprehensive (income) loss at December 31, 2018 and 2017 that have not been recognized as components of net periodic benefit cost:



	Pensions								Other Post-retirement Benefits
	2018				2017				2018		2017
(In millions)	U.S.		Int’l		U.S.		Int’l
Pre-tax amounts recognized in accumulated other comprehensive (income) loss
Unrecognized actuarial (gain) loss	$	73.2	$	43.7	$	0.1	$	21.2	$	0.6	$	0.8
Unrecognized prior service (credit) cost	—		7.0		0.2		5.5		—		—
Accumulated other comprehensive (income) loss at December 31	$	73.2	$	50.7	$	0.3	$	26.7	$	0.6	$	0.8

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, 2018 and 2017:



	Pensions								Other Post-retirement Benefits
	2018				2017				2018		2017
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded projected benefit obligation
Aggregate projected benefit obligation	$	598.1	$	621.1	$	659.8	$	744.3	$	9.5	$	9.9
Aggregate fair value of plan assets	$	477.4	$	439.8	$	576.4	$	558.0	$	—	$	—



	Pensions								Other Post-retirement Benefits
	2018				2017				2018		2017
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded accumulated benefit obligation
Aggregate accumulated benefit obligation	$	598.1	$	269.2	$	659.8	$	212.5	$	—	$	—
Aggregate fair value of plan assets	$	477.4	$	126.6	$	576.4	$	82.2	$	—	$	—

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The following table summarizes the components of net periodic benefit cost (income) for the years ended December 31, 2018, 2017 and 2016:



	Pensions																	Other Post-retirement Benefits
	2018						2017						2016					2018		2017		2016
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.		Int’l
Components of net periodic benefit cost (income)
Service cost	$	0.2		$	21.2		$	10.3		$	21.0		$	—	$	11.7		$	—	$	—	$	—
Interest cost	23.8			20.9			26.7			19.6			—		10.9			0.4		0.3		—
Expected return on plan assets	(50.1		)	(41.2		)	(45.5		)	(36.3		)	—		(8.2		)	—		—		—
Settlement cost	0.4			0.4			—			1.5			—		—			—		—		—
Curtailment benefit	—			(3.8		)	(26.8		)	—			—		(10.7		)	—		—		—
Amortization of net actuarial loss (gain)	—			0.6			—			2.5			—		1.0			—		—		—
Amortization of prior service cost (credit)	—			1.3			—			1.0			—		0.7			—		—		—
Net periodic benefit cost (income)	$	(25.7	)	$	(0.6	)	$	(35.3	)	$	9.3		$	—	$	5.4		$	0.4	$	0.3	$	—

The following table summarizes changes in plan assets and benefit obligations recognized in other comprehensive income (loss) for the years ended December 31, 2018, 2017 and 2016:



	Pensions																	Other Post-retirement Benefits
	2018						2017						2016					2018			2017			2016
(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	$	(73.5	)	$	(15.3	)	$	26.7		$	43.3		$	—	$	(10.5	)	$	—		$	(0.8	)	$	—
Prior service (cost) credit arising during period	0.2			(2.7		)	(0.2		)	0.1			—		0.1			—			—			—
Settlements and curtailments	0.4			(3.4		)	(26.8		)	1.5			—		(10.7		)	—			—			—
Amortization of net actuarial loss (gain)	—			0.6			—			2.5			—		1.0			—			—			—
Amortization of prior service cost (credit)	—			1.3			—			1.0			—		0.7			—			—			—
Other	—			1.4			—			(5.1		)	—		17.6			(0.1		)	—			—
Total recognized in other comprehensive income (loss)	$	(72.9	)	$	(18.1	)	$	(0.3	)	$	43.3		$	—	$	(1.8	)	$	(0.1	)	$	(0.8	)	$	—

Included in accumulated other comprehensive income (loss) at December 31, 2018, 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)	$	1.8	$	0.9	$	—
Prior service cost (credit)	$	—	$	1.2	$	—

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



	Pensions								Other Post-retirement Benefits
	2018				2017				2018		2017
	U.S.		Int’l		U.S.		Int’l
Discount rate	4.40	%	2.54	%	3.70	%	2.42	%	5.04	%	4.33	%
Rate of compensation increase	N/A		2.24	%	N/A		2.37	%	4.00	%	4.00	%

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



	Pensions											Other Post-retirement Benefits
	2018				2017				2016			2018		2017		2016
	U.S.		Int’l		U.S.		Int’l		U.S.	Int’l
Discount rate	3.70	%	2.39	%	4.30	%	2.37	%	N/A	2.80	%	4.33	%	4.05	%	2.20	%
Rate of compensation increase	N/A		2.39	%	4.00	%	2.39	%	N/A	2.30	%	4.00	%	4.00	%	3.00	%
Expected rate of return on plan assets	8.57	%	4.90	%	9.00	%	6.24	%	N/A	2.80	%	N/A		N/A		N/A

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, 99% of our total pension plan assets represent the U.S. qualified plan, the U.K. plan and the Netherlands 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, 2018 and 2017.


•	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.

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Our pension plan assets measured at fair value on a recurring basis are as follows at December 31, 2018 and 2017. Refer to “Fair value measurements” in Note 1 to these consolidated financial statements for a description of the levels.



(In millions)	U.S.								International
December 31, 2018	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Cash and cash equivalents	$	46.8	$	46.8	$	—	$	—	$	11.1	$	11.1	$	—	$	—
Equity securities
U.S. companies	109.4		109.4		—		—		92.2		92.2		—		—
International companies	8.5		8.5		—		—		186.8		186.8		—		—
Registered investment companies ^(a)	32.6		—		—		—		44.4		—		—		—
Common/collective trusts ^(a)	11.7		—		—		—		10.0		—		—		—
Insurance contracts	—		—		—		—		125.0		—		125.0		—
Hedge funds ^(a)	176.5		—		—		—		99.1		—		—		—
Limited partnerships ^(a)	89.7		—		—		—		—		—		—		—
Real estate and other investments	2.2		2.2		—		—		1.2		1.2		—		—
Total assets	$	477.4	$	166.9	$	—	$	—	$	569.8	$	291.3	$	125.0	$	—

December 31, 2017
Cash and cash equivalents	$	41.2	$	41.2	$	—	$	—	$	4.8	$	4.8	$	—	$	—
Equity securities
U.S. companies	131.7		131.7		—		—		106.9		106.9		—		—
International companies	33.7		33.7		—		—		216.7		216.7		—		—
Registered investment companies ^(a)	33.6		—		—		—		72.6		—		—		—
Common/collective trusts ^(a)	31.2		—		—		—		13.0		—		—		—
Insurance contracts	—		—		—		—		208.2		—		208.2		—
Hedge funds ^(a)	194.3		—		—		—		74.7		—		—		—
Limited partnerships^(a)	109.7		—		—		—		—		—		—		—
Real estate and other investments	0.8		0.8		—		—		1.5		1.5		—		—
Total assets	$	576.2	$	207.4	$	—	$	—	$	698.4	$	329.9	$	208.2	$	—


(a)	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 $2.7 million to our international pension plans, representing primarily the Netherlands qualified pension plans and U.K. qualified pension plans. We do not expect to make any contributions to our U.S. Qualified Pension Plan and our U.S. Non-Qualified Defined Benefit Pension Plan in 2019. All of the contributions are expected to be in the form of cash. In 2018 and 2017, we contributed $18.5 million and $19.1 million to all pension plans, respectively.

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Estimated future benefit payments - The following table summarizes expected benefit payments from our various pension and post-retirement benefit plans through 2028. Actual benefit payments may differ from expected benefit payments.



	Pensions				Other Post-retirement Benefits
(In millions)	U.S.		International
2019	$	34.9	$	28.3	$	0.7
2020	$	35.2	$	30.4	$	0.7
2021	$	35.7	$	31.8	$	0.7
2022	$	35.1	$	32.0	$	0.6
2023	$	33.7	$	33.8	$	0.6
2024-2028	$	175.8	$	189.3	$	2.7

Savings plans - The TechnipFMC Retirement Savings 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. Both plans relate to FMC Technologies, Inc.

Participants in the Non-Qualified Plan earn a return based on hypothetical investments in the same options as our 401(k) plan, including TehnipFMC plc 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, 2018 and 2017, our liability for the Non-Qualified Plan was $22.8 million and $29.4 million, respectively, and was recorded in other non-current liabilities. We hedge the financial impact of changes in the participants’ hypothetical investments by purchasing the investments that the participants have chosen. With the exception of TechnipFMC plc 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, 2018 and 2017, we had investments for the Non-Qualified Plan totaling $21.4 million and $25.1 million at fair market value, respectively. As of December 31, 2018 and 2017, TechnipFMC stock held in trust of $2.4 million and $4.8 million at its cost basis, respectively. Refer to Note 22 to these consolidated financial statements for fair value disclosure of the Non-Qualified Plan investments.

We recognized expense of $31.8 million and $20.3 million for matching contributions to these plans in 2018 and 2017, respectively. Additionally, we recognized expense of $14.3 million and $12.5 million for non-elective contributions in 2018 and 2017, respectively.

NOTE 21. 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.

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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, 2018, we held the following material net positions:



	Net Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Euro	725.9		831.1
Norwegian krone	2,264.7		260.6
Brazilian real	752.3		194.2
Australian dollar	183.2		129.3
Malaysian ringgit	397.0		96.1
Singapore dollar	108.2		79.4
Japanese yen	8,118.0		73.9
British pound	52.4		67.0
Canadian dollar	(247.0	)	(181.0	)
U.S. dollar	(1,051.8	)	(1,051.8	)

Foreign exchange rate instruments embedded in purchase and sale contracts – The purpose of these instruments is to match offsetting currency payments and receipts for particular projects, or comply with government restrictions on the currency used to purchase goods in certain countries. At December 31, 2018, our portfolio of these instruments included the following material net positions:



	Net Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Norwegian krone	(104.3	)	(12.0	)
U.S. dollar	13.1		13.1

Fair value amounts for all outstanding derivative instruments have been determined using available market information and commonly accepted valuation methodologies. Refer to Note 22 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.

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



	December 31, 2018				December 31, 2017
(In millions)	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Foreign exchange contracts
Current - Derivative financial instruments	$	83.8	$	127.7	$	65.6	$	51.0
Long-term - Derivative financial instruments	9.0		35.6		28.0		1.7
Total derivatives designated as hedging instruments	92.8		163.3		93.6		52.7
Derivatives not designated as hedging instruments
Foreign exchange contracts
Current - Derivative financial instruments	11.9		10.7		12.7		18.0
Long-term - Derivative financial instruments	0.1		0.1		4.7		4.2
Total derivatives not designated as hedging instruments	12.0		10.8		17.4		22.2
Long-term - Derivative financial instruments - Synthetic Bonds - Call Option Premium	9.2		—		62.2		—
Long-term - Derivative financial instruments - Synthetic Bonds - Embedded Derivatives	—		9.2		—		62.2
Total derivatives	$	114.0	$	183.3	$	173.2	$	137.1

We recognized a loss of $2.5 million, a gain of $25.3 million and a loss of $10.3 million on cash flow hedges for the years ended December 31, 2018, 2017 and 2016, 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 income (loss) of $(33.0) million and $28.5 million at December 31, 2018 and 2017, respectively. We expect to transfer an approximately $11.7 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 2023.

The following table presents the location of gains (losses) on the consolidated statements of income related to derivative instruments designated as fair value hedges.



Location of Fair Value Hedge Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
	Year Ended December 31,
(In millions)	2018			2017		2016
Other income (expense), net	$	(18.1	)	$	44.9	$	32.8

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)	2018			2017		2016
Foreign exchange contracts	$	(75.4	)	$	72.1	$	(86.1	)



Location of Cash Flow Hedge Gain (Loss) Reclassified from Accumulated OCI into Income	Gain (Loss) Reclassified From Accumulated OCI into Income (Effective Portion)
	Year Ended December 31,
(In millions)	2018			2017			2016
Foreign exchange contracts
Revenue	$	(2.4	)	$	(39.3	)	$	—
Cost of sales	3.4			5.3			—
Selling, general and administrative expense	(0.1		)	0.8			—
Other (expense), net	1.0			(102.2		)	(165.7		)
Total	$	1.9		$	(135.4	)	$	(165.7	)

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Location of Cash Flow Hedge Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	Year Ended December 31,
(In millions)	2018			2017			2016
Foreign exchange contracts
Revenue	$	(2.2	)	$	9.5		$	—
Cost of sales	(4.8		)	(9.0		)	—
Selling, general and administrative expense	—			0.1			—
Other income (expense), net	(12.3		)	23.0			(13.2		)
Total	$	(19.3	)	$	23.6		$	(13.2	)

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)	2018			2017			2016
Foreign exchange contracts
Revenue	$	(1.7	)	$	0.9		$	—
Cost of sales	0.2			(0.3		)	—
Other income, net	(11.4		)	43.0			0.1
Total	$	(12.9	)	$	43.6		$	0.1

Balance Sheet Offsetting - We execute derivative contracts 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, 2018 and 2017, we had no collateralized derivative contracts. The following tables present both gross information and net information of recognized derivative instruments:



	December 31, 2018							December 31, 2017
(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	$	114.0	$	(105.9	)	$	8.1	$	173.2	$	(114.4	)	$	58.8
Derivative liabilities	$	183.3	$	(105.9	)	$	77.4	$	137.1	$	(114.4	)	$	22.7

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NOTE 22. FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements

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



	December 31, 2018								December 31, 2017
(In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Assets
Investments
Nonqualified Plan:
Equity securities^(a)	$	40.4	$	40.4	$	—	$	—	$	63.7	$	63.7	$	—	$	—
Money market fund	1.6		—		1.6		—		2.4		—		2.4		—
Stable value fund^(b)	0.5		—		—		—		0.6		—		—		—
Derivative financial instruments
Synthetic bonds - call option premium	9.2		—		9.2		—		62.2		—		62.2		—
Foreign exchange contracts	104.8		—		104.8		—		111.0		—		111.0		—
Asset held for sale	9.6		—		—		9.6		50.2		—		—		50.2
Total assets	$	166.1	$	40.4	$	115.6	$	9.6	$	290.1	$	63.7	$	175.6	$	50.2
Liabilities
Redeemable financial liability	$	408.5	$	—	$	—	$	408.5	$	312.0	$	—	$	—	$	312.0
Derivative financial instruments
Synthetic bonds - embedded derivatives	9.2		—		9.2		—		62.2		—		62.2		—
Foreign exchange contracts	174.1		—		174.1		—		74.9		—		74.9		—
Liabilities held for sale	16.2		—		—		16.2		13.7		—		—		13.7
Total liabilities	$	608.0	$	—	$	183.3	$	424.7	$	462.8	$	—	$	137.1	$	325.7


(a)	Includes fixed income and other investments measured at fair value.


(b)	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.

Equity securities - The fair value measurement of our equity securities is based on quoted prices that we have the ability to access in public markets.

Stable value fund and Money market fund - Stable value fund and money market fund are valued at the net asset value of the shares held at the end of the quarter, which is based on the fair value of the underlying investments using information reported by our investment advisor at quarter-end.

Assets and liabilities held for sale - The fair value of our assets and liabilities held for sale was determined using a market approach that took into consideration the expected sales price.

Mandatorily redeemable financial liability - In the fourth quarter of 2016, we obtained voting control interests in legal Onshore/Offshore contract entities which own and account for the design, engineering and construction of the Yamal LNG plant. As part of this transaction, we recognized the fair value of the mandatorily redeemable financial liability using a discounted cash flow model. The key assumptions used in applying the income approach are the selected discount rates and the expected dividends to be distributed in the future to the noncontrolling interest holders. Expected dividends to be distributed are based on the noncontrolling interests’ share of the expected profitability of the underlying contract, the selected discount rate and the overall timing of completion of the project.

A mandatorily redeemable financial liability of $312.0 million was recognized as of December 31, 2017 to account for the fair value of the non-controlling interests. During the twelve months ended December 31, 2018 and 2017, we revalued the liability to reflect current expectations about the obligation, which resulted in the recognition of a loss of $322.3 million and $293.7 million, respectively.

A decrease of one percentage point in the discount rate would have increased the liability by $5.4 million as of December 31, 2018. The fair value measurement is based upon significant unobservable inputs not observable in the market and is consequently classified as a Level 3 fair value measurement.

127

Change in the fair value of our Level 3 mandatorily redeemable financial liability is recorded as interest expense on the consolidated statements of income and is presented below:



	Year Ended December 31,
(In millions)	2018			2017
Balance at beginning of period	$	312.0		$	174.8
Less: Gains (losses) recognized in net interest expense	(322.3		)	(293.7		)
Less: Settlements	225.8			156.5
Balance at end of period	$	408.5		$	312.0

Redeemable noncontrolling interest - In the first quarter of 2018, we acquired a 51% share in Island Offshore. The noncontrolling interest is recorded as mezzanine equity at fair value. The fair value measurement is based upon significant unobservable inputs not observable in the market and is consequently classified as a Level 3 fair value measurement. As of December 31, 2018, the fair value of our redeemable noncontrolling interest was $38.5 million. Refer to Note 2 to these consolidated financial statements for additional disclosure related to the acquisition.

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

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

Refer to Note 21 to these consolidated financial statements for additional disclosure related to derivative financial instruments.

Nonrecurring Fair Value Measurements

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, when the recoverable amount of the assets has been determined to be less than the book value of the assets. The fair value measurements of our long-lived, non-financial assets measured 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 changes in actual or estimated cash flows may result in changes to the fair value of long-lived non-financial assets. Refer to Note 17 for additional disclosure related to these asset impairments.

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Other fair value disclosures

Fair value of debt - The fair value of our Synthetic Bonds, Senior Notes and private placement notes are as follows:



	December 31, 2018				December 31, 2017
(In millions)	Carrying Amount ^(a)		Fair Value ^(b)		Carrying Amount ^(a)		Fair Value ^(b)
Synthetic bonds due 2021	$	490.9	$	532.4	$	502.4	$	647.4
3.45% Senior Notes due 2022	500.0		489.7		500.0		497.7
5.00% Notes due 2020	229.0		244.0		239.9		265.2
3.40% Notes due 2022	171.8		186.9		179.9		199.4
3.15% Notes due 2023	148.9		161.3		155.9		167.6
3.15% Notes due 2023	143.1		153.3		149.9		161.4
4.00% Notes due 2027	85.9		95.8		89.9		99.9
4.00% Notes due 2032	114.5		120.2		119.9		142.9
3.75% Notes due 2033	114.5		126.1		119.9		126.7


(a)	Carrying amounts include unamortized debt discounts and premiums and unamortized debt issuance costs of $11.4 million and $13.8 million as of 2018 and 2017, respectively.


(b)	Fair values are based on Level 2 quoted market rates.

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

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

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NOTE 23. QUARTERLY INFORMATION (UNAUDITED)



	2018									2017
(In millions, except per share data)	4th Qtr.			3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.			3rd Qtr.		2nd Qtr.		1st Qtr.
Revenue	$	3,323.0		$	3,143.8	$	2,960.9	$	3,125.2	$	3,683.0		$	4,140.9	$	3,845.0	$	3,388.0
Cost of sales	2,767.7			2,558.5		2,422.2		2,524.6		2,914.1			3,468.2		3,162.0		2,980.3
Net income (loss)	(2,246.5		)	134.2		110.1		91.4		(127.5		)	117.9		159.0		(15.2		)
Net income (loss) attributable to TechnipFMC plc	$	(2,259.3	)	$	136.9	$	105.7	$	95.1	$	(153.9	)	$	121.0	$	164.9	$	(18.7	)
Basic earnings (loss) per share⁽¹⁾	$	(5.00	)	$	0.30	$	0.23	$	0.20	$	(0.33	)	$	0.26	$	0.35	$	(0.04	)
Diluted earnings (loss) per share⁽¹⁾	$	(5.00	)	$	0.30	$	0.23	$	0.20	$	(0.33	)	$	0.26	$	0.35	$	(0.04	)


⁽¹⁾	Basic and diluted earnings (loss) per share are computed independently for each of the quarters presented. Therefore, the sum of quarterly basic and diluted per share information may not equal annual basic and diluted earnings (loss) per share.

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, 2018, and under the direction of our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act. Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded as of December 31, 2018, that our disclosure controls and procedures were not effective because of the material weaknesses in our internal control over financial reporting described below.

In response to the identification of the material weaknesses described below, the Company performed additional analysis and other post-closing procedures. Based upon the work performed, management believes that the Company’s consolidated financial statements for the periods covered by and included in this Annual Report on Form 10-K fairly present in all material respects the Company’s financial position, results of operations, and cash flows, in conformity with U.S. generally accepted accounting principles.

Remediation Activities of Previously Disclosed Material Weaknesses

As of December 31, 2017, our management concluded that we had not maintained effective internal control over financial reporting in the following areas:

(i) foreign exchange adjustments;

(ii) information technology general controls; and

(iii) period-end financial reporting.

The material weaknesses related to foreign exchange adjustments and information technology general controls were remediated as of December 31, 2018, as noted below. In addition, we implemented remediation activities in 2018 related to the period-end financial reporting material weakness as described below, but our management has concluded that this material weakness is not yet remediated as of December 31, 2018.

Foreign Exchange Adjustments - Remediated as of December 31, 2018

We previously reported that we did not maintain effective controls related to the calculation of temporary gains and losses from natural hedges on certain of our projects and related foreign exchange adjustments, and this control deficiency resulted in the restatement of our interim condensed consolidated financial statements as of, and for, the three-month period ended March 31, 2017. Accordingly, our management determined that this control deficiency constituted a material weakness.

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Management took the following corrective actions to address this material weakness:


•	Implemented controls designed to ensure the accurate remeasurement of gains and losses due to foreign currency impact for the purpose of external reporting; and


•	Revised the internal system for recording and tracking foreign currency gains and losses and for recording asset/liability project positions to ensure that proper remeasurement procedures are performed.

As a result of these remediation activities and based on testing of the new and modified controls for operating effectiveness, our management concluded that we remediated the material weakness related to foreign exchange adjustments as of December 31, 2018 and believes the Company’s consolidated financial statements for the periods covered by and included in this Annual Report on Form 10-K fairly present in all material respects the Company’s financial position, results of operations, and cash flows, in conformity with U.S. generally accepted accounting principles.

Information Technology General Controls - Remediated as of December 31, 2018

We previously reported that we did not design and maintain effective controls over certain information technology (IT) general controls for information systems that are relevant to the preparation of our consolidated financial statements. Specifically, we did not design and maintain: (i) user access controls to ensure appropriate segregation of duties that adequately restrict user and privileged access to certain financial applications, programs, and data to appropriate Company personnel, including direct access to data, and (ii) program change management controls due to privileged access.

These IT deficiencies did not result in a material misstatement of the financial statements; however, the deficiencies, when aggregated, could have impacted maintaining effective segregation of duties, as well as the effectiveness of IT-dependent controls (such as automated controls that address the risk of material misstatement to one or more assertions, along with the IT controls and underlying data that support the effectiveness of system-generated data and reports), that could have resulted in misstatements potentially impacting financial statement accounts and disclosures that would not be prevented or detected. Accordingly, our management determined that these deficiencies, in the aggregate, constituted a material weakness.

Management took the following corrective actions to address this material weakness:


•	Improved the control activities and procedures associated with user and privilege access to certain systems;


•	Improved the control activities related to proper segregation of duties related to the affected IT systems;


•	Implemented additional business process controls or improving existing business process controls, as needed, to address the risks related to the financial reports and data generated from the affected IT systems; and


•	Implemented policies, procedures, and training for control owners regarding internal control processes to mitigate identified risks and maintaining adequate documentation to evidence effective design and operation of such processes.

Period-End Financial Reporting - Unremediated as of December 31, 2018

We previously reported that in certain regions and locations, we did not design and maintain effective controls over the period-end financial reporting process. We had ineffective controls over the documentation, authorization, and review of journal entries and account reconciliations in certain regions and locations.

These deficiencies did not result in a material misstatement of the financial statements; however, the deficiencies, when aggregated, could have resulted in material misstatements of the consolidated financial statements and disclosures that would not be prevented or detected. Accordingly, our management determined that these deficiencies, in the aggregate, constituted a material weakness.

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Management took the following corrective actions to address this material weakness:


•	Implemented specific policies and procedures with detailed instructions in order to adequately communicate the requirements around processes and controls;


•	Implemented controls over manual journal entries and account reconciliations, including improving the timeliness and effectiveness of our review and approval procedures;


•	Communicated the requirements of journal entry and account reconciliation controls to the global accounting and finance organization as part of our global accounting and finance organization training and communication;


•	Expanded our corporate finance leadership team by adding individuals with the commensurate knowledge, experience, and training to properly support our financial reporting and accounting functions; and


•	Improved the control activities related to account reconciliation and journal entry processes by issuing guidance regarding adequate retention of evidence of control activities.

We have implemented the above-described remediation activities in 2018. Based on testing of the new and modified controls in 2018 for operating effectiveness, our management determined that additional remediation activities, as described below, and further testing of new and modified controls were needed for 2019. Our management concluded that we have not yet remediated the material weakness related to period-end financial reporting as of December 31, 2018.

Management’s Annual Report on Internal Control over Financial Reporting

Overview

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act.

Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2018 based on the framework in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As a result of this evaluation, management identified material weaknesses in our internal control, as further described below. As a result of these material weaknesses, management has concluded that our internal control over financial reporting was not effective as of December 31, 2018.

We concluded that we had not maintained effective internal control over financial reporting in the following areas that are discussed more fully below: (i) period-end financial reporting and (ii) accounting for income taxes. These deficiencies did not result in a material misstatement of the financial statements for the year ended December 31, 2018.

The effectiveness of our internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein.

Description of Material Weaknesses

Period-End Financial Reporting

In certain locations, we did not design and maintain effective controls over the period-end financial reporting process. We have ineffective controls over the documentation, authorization, and review of adjustments to and reconciliations of financial information.

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that would not be prevented or detected. Accordingly, our management has determined these deficiencies, in the aggregate, constitute a material weakness.

Accounting for Income Taxes

We did not design and maintain effective controls over the completeness, accuracy, and presentation of our accounting for income taxes, including the income tax provision and related income tax assets and liabilities.

These deficiencies did not result in a material misstatement of the financial statements; however, the deficiencies, when aggregated, could result in a material misstatement of the consolidated financial statements and disclosures that would not be prevented or detected. Accordingly, our management has determined these deficiencies, in the aggregate, constitute a material weakness.

Remediation Activities

Overview

Management has implemented, and continues to design and implement, certain remediation measures to address the above-described material weaknesses and enhance our system of internal control over financial reporting. Management will not make a final determination that we have completed our remediation of these material weaknesses until we have completed designing and testing of our newly implemented internal controls. Management believes the remediation measures described below will remediate the identified deficiencies and strengthen our internal control over financial reporting. As management continues to evaluate and work to enhance our internal control over financial reporting, it may be determined that additional measures must be taken to address deficiencies or it may be determined that we need to modify or otherwise adjust the remediation measures described below.

Period-End Financial Reporting

Management continues to take corrective actions in 2019 to remediate this material weakness, including:


•	Providing additional training and continuous guidance to finance team members on the requirements around control processes;

•Continuously improving the timeliness and effectiveness of our review and approval procedures; and


•	Further improving the control activities related to the review of adjustments to and reconciliations of financial information by issuing guidance regarding documentation and adequate retention of evidence of control activities.

Accounting for Income Taxes

Management is taking corrective actions to address this material weakness by:


•	Reinforcing the proper application of the Company’s global taxation tool, implemented in 2018, by issuing detailed instructions and application descriptions;

•Providing additional training to finance team members on the adequate use of the global taxation tool;

•Improving the timeliness and effectiveness of our review and approval procedures; and


•	Improving the control activities related to our accounting for income taxes by issuing guidance regarding adequate documentation and retention of evidence of control activities.

Changes in Internal Control over Financial Reporting

Other than as described above, there were no changes in our internal control over financial reporting during the three months ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION

Within the second quarter 2018, management decided to wind down all business in Iran, with the exception of seeking to collect outstanding receivables for work previously completed in Iran. Since the second quarter 2018, the Company has not and will not accept any new work in Iran.

Pursuant to section 13(r) of the Exchange Act, two of our non-U.S. subsidiaries had contracts with entities in Iran. Pursuant to these contracts, which were terminated in the first and second quarter 2018, we prepared a feasibility study related to improvements to an olefins plant in Iran and also provided engineering and design services for the construction of an ethylene plant in Iran. We have not received any revenue under either of these contracts for the fiscal year ended December 31, 2018. The expected revenue related to services performed prior to contract termination for the olefins plant and the ethylene plant is 260,000 Euros and 4,000,000 Euros, respectively, which is less than 0.1% of our revenues for the fiscal year ended December 31, 2018. We also had a non-binding arrangement with an engineering, procurement, and construction company in Iran for the purpose of jointly bidding and negotiating for work on two projects in Iran, which we terminated in third quarter 2018. No projects were pursued under the non-binding agreement and no revenue was generated.

We had submitted bids to or had discussions with companies in Iran, including some that may be owned or controlled by the Government of Iran, regarding potential future projects in Iran. In third quarter 2018, we withdrew all pending bids in Iran and will not accept a contract award related to such a project.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item regarding our directors and corporate governance is incorporated by reference to the section of TechnipFMC’s definitive Proxy Statement for its 2019 Annual General Meeting of Shareholders entitled “Corporate Governance and Board of Directors.” See Part I, Item 1 “Executive Officers of the Registrant” of this Annual Report on Form 10-K for information regarding our executive officers. The information required by this item regarding compliance by our directors and executive officers with Section 16(a) of the Securities and Exchange Act of 1934, as amended, is incorporated by reference to the section of TechnipFMC’s definitive Proxy Statement for its 2019 Annual General Meeting of Shareholders entitled “Section 16(a) Beneficial Ownership Reporting Compliance.”

We have adopted a Code of Business Conduct, which is applicable to our principal executive officer and other senior financial officers, including our principal financial officer, principal accounting officer or controller, and persons performing similar functions. The Code of Business Conduct may be found on our website at www.technipfmc.com under “About us—Governance” and is available in print to shareholders without charge by submitting a request to 11740 Katy Freeway, Energy Tower 3, Houston, Texas 77079, Attention: Corporate Secretary. We intend to satisfy the disclosure requirements under the Securities and Exchange Act of 1934, as amended, regarding an amendment to or waiver from a provision of our Code of Business Conduct by posting such information on our website.



Name			Principal Occupation
Thierry Pilenko*			Executive Chairman of TechnipFMC
Douglas J. Pferdehirt*			Chief Executive Officer of TechnipFMC
Arnaud Caudoux			Deputy Chief Executive Officer of Banque publique d'investissement, a French state-owned investment bank
Pascal Colombani			President of TII Strategies SASU, a consulting and investment company
Marie-Ange Debon			Senior Executive Vice President of the Suez Group, a global water and waste company, managing France, Italy, and Central and Eastern Europe operations of the Suez Group
Eleazar de Carvalho Filho			Founding Partner of Virtus BR Partners Assessoria Corporativa Ltda. and Founding Partner of Sinfonia Consultoria Financeira e Participações Ltda., financial advisory and consulting firms
Claire S. Farley			Vice Chairman in the Energy & Infrastructure business of KKR & Co. L.P., a global investment firm
Didier Houssin			Chairman and Chief Executive Officer of IFP Énergies nouvelles, a research and training company in the fields of energy, transport, and the environment
Peter Mellbye			Former Executive Vice President, Development & Production, International, of Statoil ASA, an international oil and gas company
John O’Leary			Chief Executive Officer of Strand Energy, a Dubai-based company specializing in business development in the oil and gas industry
Richard A. Pattarozzi			Former Vice President of Shell Oil Company, a producer of oil, gas, and petrochemicals
Kay G. Priestly			Former Chief Executive Officer of Turquoise Hill Resources Ltd., an international mining company
Joseph Rinaldi			Managing Partner of Fennecourt Partners, LLC, an investment management and consulting firm
James M. Ringler			Non-executive Chairman of the Board of Teradata Corporation, a provider of database software, data warehousing and analytics

* As previously disclosed, Mr. Pilenko is retiring from the Board of Directors effective May 1, 2019, and Mr. Pferdehirt will assume the role of Chairman of the Board of Directors and serve as Chairman and Chief Executive Officer of TechnipFMC effective May 1, 2019.

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 Discussion and Analysis” of our Proxy Statement for the 2019 Annual General Meeting of Shareholders.

135

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER 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 our Outstanding Ordinary Shares” of our Proxy Statement for the 2019 Annual General Meeting of Shareholders.

As of December 31, 2018, our securities authorized for issuance under equity compensation plans were as follows:



(shares in thousands)	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	4,658.4	$	33.68	26,304.6
Equity compensation plans not approved by security holders	—	—		—
Total	4,658.4	$	33.68	26,304.6

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 2019 Annual General Meeting of Shareholders.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by this item is incorporated herein by reference from the sections entitled “Proposal 6 — Ratification of U.S. Auditor” of our Proxy Statement for the 2019 Annual General Meeting of Shareholders.

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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 TechnipFMC plc and subsidiaries are filed as part of this Annual Report on Form 10-K under Part II, Item 8:

Reports of Independent Registered Public Accounting Firm on Consolidated Financial Statements

Consolidated Statements of Income for the Years Ended December 31, 2018, 2017 and 2016

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017, and 2016

Consolidated Balance Sheets as of December 31, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2018, 2017 and 2016

Notes to Consolidated Financial Statements


2.	Financial Statement Schedule:

See “Schedule II - Valuation and Qualifying Accounts” 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.

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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, 2016
Allowance for doubtful accounts	$	48.2	$	58.4	$	—		$	(21.0	)	$	85.6
Valuation allowance for deferred tax assets	$	133.8	$	38.9	$	—		$	—		$	172.7
Year Ended December 31, 2017
Allowance for doubtful accounts	$	85.6	$	15.5	$	19.8		$	(3.5	)	$	117.4
Valuation allowance for deferred tax assets	$	172.7	$	258.7	$	4.4		$	(5.8	)	$	430.0
Year Ended December 31, 2018
Allowance for doubtful accounts	$	117.4	$	54.7	$	0.3		$	(52.8	)	$	119.6
Valuation allowance for deferred tax assets	$	430.0	$	213.8	$	(21.3	)	$	60.9		$	683.4


(a)	“Additions charged to other accounts” includes translation adjustments.


(b)	“Deductions and adjustments” includes write-offs, net of recoveries, increases in allowances offset by increases to deferred tax assets, and reductions in the allowances credited to expense.

See accompanying Report of Independent Registered Public Accounting Firm.

138

ITEM 16. SUMMARY

None.

139

INDEX OF EXHIBITS



Exhibit No.		Exhibit Description
2.1		Business Combination Agreement, dated as of June 14, 2016, by and among FMC Technologies, Inc., TechnipFMC plc (f/k/a FMC Technologies SIS Limited) and Technip S.A. (incorporated by reference from Annex A-1 to the Registration Statement on Form S-4, as amended, filed on October 21, 2016) (File No. 333-213067)
2.1.a		Amendment No. 1 to Business Combination Agreement, dated as of December 14, 2016, by and among FMC Technologies, Inc., TechnipFMC plc (f/k/a TechnipFMC Limited) and Technip S.A. (incorporated by reference from Exhibit 2.1 to the Current Report on Form 8-K filed on December 14, 2016) (File No. 333-213067)
2.3		Joinder Agreement, dated as of December 14, 2016, by and among FMC Technologies, Inc., TechnipFMC plc (f/k/a TechnipFMC Limited), Technip S.A., TechnipFMC Holdings Limited, TechnipFMC US Holdings LLC and TechnipFMC US Merger Sub LLC (incorporated by reference from Exhibit 2.2 to the Current Report on Form 8-K filed on December 14, 2016) (File No. 333-213067)
3.1		Articles of Association of TechnipFMC plc (incorporated by reference from Exhibit 3.1 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
4.1		Indenture, dated March 29, 2017, between TechnipFMC plc and U.S. Bank National Association, as trustee (incorporated by reference from Exhibit 4.1 to the Current Report on Form 8-K filed on March 30, 2017) (File No. 001-37983)
4.1.a		Second Supplemental Indenture, dated March 29, 2017, between TechnipFMC plc and U.S. Bank National Association, as trustee (including the form of 3.45% Senior Notes due 2022) (incorporated by reference from Exhibit 4.3 to the Current Report on Form 8-K filed on March 30, 2017) (File No. 001-37983)
10.1*		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 of FMC Technologies, Inc. filed on March 1, 2010) (File No. 001-16489)
10.1.a*		First Amendment of FMC Technologies, Inc. Non-Qualified Savings and Investment Plan, dated October 29, 2009 (incorporated by reference from Exhibit 10.9 to the Quarterly Report on Form 10-Q of FMC Technologies, Inc. filed on November 3, 2009) (File No. 001-16489)
10.1.b*		Second Amendment of FMC Technologies, Inc. Non-Qualified Savings and Investment Plan, dated December 18, 2015 (incorporated by reference from Exhibit 10.14.b to the Annual Report on Form 10-K of FMC Technologies, Inc. filed on February 24, 2016) (File No. 001-16489)
10.2*		Amended and Restated TechnipFMC plc Incentive Award Plan
10.3*		Form of Restricted Stock Unit Agreement pursuant to the TechnipFMC plc Incentive Award Plan (Employee) (incorporated by reference from Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on August 4, 2017) (File No. 001-37983)
10.4*		Form of Restricted Stock Unit Agreement pursuant to the TechnipFMC plc Incentive Award Plan (Non-Employee Director) (incorporated by reference from Exhibit 10.2 to the Quarterly Report on Form 10-Q filed on August 4, 2017) (File No. 001-37983)
10.5*		Form of Performance Stock Unit Agreement pursuant to the TechnipFMC plc Incentive Award Plan (Employee) (incorporated by reference from Exhibit 10.3 to the Quarterly Report on Form 10-Q filed on August 4, 2017) (File No. 001-37983)
10.6*		Performance Stock Unit Agreement pursuant to the TechnipFMC plc Incentive Award Plan, dated as of August 9, 2017, between TechnipFMC plc and Thierry Pilenko (incorporated by reference from Exhibit 10.4 to the Quarterly Report on Form 10-Q filed on November 9, 2017) (File No. 001-37983)
10.7*		Form of Nonqualified Stock Option Agreement pursuant to the TechnipFMC plc Incentive Award Plan (Employee) (incorporated by reference from Exhibit 10.4 to the Quarterly Report on Form 10-Q filed on August 4, 2017) (File No. 001-37983)
10.8*		2011 Technip Incentive Reward Plan (Stock Option Plan Rules) June 17, 2011 allocation (incorporated by reference from Exhibit 99.2 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.9*		2012 Technip Incentive and Reward Plan (Stock Option Plan Rules) June 15, 2011 allocation (incorporated by reference from Exhibit 99.3 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.10*		2012 Technip Incentive and Reward Plan (Stock Option Plan Rules) December 14, 2011 allocation (incorporated by reference from Exhibit 10.10 to the Annual Report on Form 10-K filed on April 2, 2018) (File No. 001-37983)
10.11*		2013 Technip Incentive and Reward Plan (Rules of the Performance Shares Plan) June 14, 2013 allocation (incorporated by reference from Exhibit 99.4 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.12*		2013 Technip Incentive and Reward Plan (Stock Option Plan Rules) June 14, 2013 allocation (incorporated by reference from Exhibit 99.5 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.13*		2013 Technip Incentive and Reward Plan (Rules of the Performance Shares Plan) January 10, 2014 allocation (incorporated by reference from Exhibit 99.6 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.14*		2013 Technip Incentive and Reward Plan (Stock Option Plan Rules) January 10, 2014 allocation (incorporated by reference from Exhibit 99.7 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.15*		2014 Technip Incentive and Reward Plan (Rules of the Performance Shares Plan) December 10, 2014 allocation (incorporated by reference from Exhibit 99.8 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.16*		2015 Technip Incentive and Reward Plan (Stock Option Plan Rules) September 7, 2015 allocation (incorporated by reference from Exhibit 99.9 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.17*		2016 Technip Incentive and Reward Plan (Rules of the Performance Shares Plan) July 1, 2016 allocation (incorporated by reference from Exhibit 99.10 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.18*		2016 Technip Incentive and Reward Plan (Stock Option Plan Rules) July 1, 2016 allocation (incorporated by reference from Exhibit 99.11 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.19*		2016 Technip Incentive and Reward Plan (Rules of the Performance Shares Plan) December 6, 2016 allocation (incorporated by reference from Exhibit 99.12 to the Registration Statement on Form S-8 of TechnipFMC plc, filed on February 27, 2017) (File No. 333-216289)
10.20*		Form of TechnipFMC plc Executive Severance Agreement (incorporated by reference from Exhibit 10.5 to the Quarterly Report on Form 10-Q filed on August 4, 2017) (File No. 001-37983)
10.21*		Service Agreement between TechnipFMC plc and Thierry Pilenko dated January 16, 2017 (incorporated by reference from Exhibit 10.21 to the Annual Report on Form 10-K filed on April 2, 2018) (File No. 001-37983)
10.22*		Letter Agreement between TechnipFMC plc and Thierry Pilenko dated September 20, 2017 (incorporated by reference from Exhibit 10.22 to the Annual Report on Form 10-K filed on April 2, 2018) (File No. 001-37983)
10.24		Form of Executive Director Appointment Letter (incorporated by reference from Exhibit 10.2 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
10.25		Form of Non-Executive Director Appointment Letter (incorporated by reference from Exhibit 10.3 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
10.26		Form of Director Deed of Indemnity (Directors) (incorporated by reference from Exhibit 10.2 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
10.27		Form of Deed of Indemnity (Executive Officers) (incorporated by reference from Exhibit 10.3 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
10.28		Form of Director Deed of Indemnity (Executive Directors) (incorporated by reference from Exhibit 10.4 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
10.29		US$2,500,000,000 Facility Agreement, dated January 12, 2017, by and among FMC Technologies, Inc., Technip Eurocash SNC and TechnipFMC plc, as borrowers; JPMorgan Chase Bank, N.A., as agent; SG Americas Securities, LLC as syndication agent; and the other lenders party thereto (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
10.30		Form of Commercial Paper Dealer Agreement, by and among FMC Technologies, Inc., as Issuer, TechnipFMC plc, as Guarantor, and the Dealer party thereto (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on September 20, 2017) (File No. 001-37983)
21.1		List of Significant Subsidiaries
23.1		Consent of PricewaterhouseCoopers LLP
23.2		Consent of PricewaterhouseCoopers Audit
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 pursuant to 18 U.S.C. 1350
32.2**		Certification of Chief Financial Officer pursuant to 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

140

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.



	TechnipFMC plc (Registrant)

	By:	/S/ KRISZTINA DOROGHAZI
		Krisztina Doroghazi Senior Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer and a Duly Authorized Officer)

Date: March 11, 2019

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 dates indicated.



Date		Signature

March 11, 2019		/S/ DOUGLAS J. PFERDEHIRT
		Douglas J. Pferdehirt Chief Executive Officer (Principal Executive Officer)

March 11, 2019		/S/ MARYANN T. MANNEN
		Maryann T. Mannen Executive Vice President and Chief Financial Officer (Principal Financial Officer)

March 11, 2019		/S/ THIERRY PILENKO
		Thierry Pilenko Executive Chairman

March 11, 2019		/S/ ARNAUD CAUDOUX
		Arnaud Caudox, Director

March 11, 2019		/S/ PASCAL COLOMBANI
		Pascal Colombani, Director

March 11, 2019		/S/ MARIE-ANGE DEBON
		Marie-Ange Debon, Director

March 11, 2019		/S/ ELEAZAR DE CARVALHO FILHO
		Eleazar De Carvalho Filho, Director

March 11, 2019		/S/ CLAIRE S. FARLEY
		Claire S. Farley, Director

March 11, 2019		/S/ DIDIER HOUSSIN
		Didier Houssin, Director

March 11, 2019		/S/ PETER MELLBYE
		Peter Mellbye, Director

March 11, 2019		/S/ JOHN O’LEARY
		John O’Leary, Director

March 11, 2019		/S/ RICHARD A. PATTAROZZI
		Richard A. Pattarozzi, Director

March 11, 2019		/S/ KAY G. PRIESTLY
		Kay G. Priestly, Director

March 11, 2019		/S/ JOSEPH RINALDI
		Joseph Rinaldi, Director

March 11, 2019		/S/ JAMES M. RINGLER
		James M. Ringler, Director

141