TechnipFMC plc - Annual Report: 2017 (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, 2017



¨	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 ¨ NO ý

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§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. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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	o	Accelerated filer	o
Non-accelerated filer (Do not check if a smaller reporting company)	ý	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 30, 2017, by the closing price on such day of $27.20 as reported on the New York Stock Exchange, was $10,268,441,348.

The number of shares of the registrant’s ordinary shares outstanding as of March 27, 2018 was 462,497,601.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement relating to its 2018 annual meeting of stockholders are incorporated by reference into Part III of this Annual Report on Form 10-K where indicated. The 2018 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
Item 1A. Risk Factors	17
Item 1B. Unresolved Staff Comments	27
Item 2. Properties	28
Item 3. Legal Proceedings	30
Item 4. Mine Safety Disclosures	30

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6. Selected Financial Data	33
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	52
Item 8. Financial Statements and Supplementary Data	53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	106
Item 9A. Controls and Procedures	106
Item 9B. Other Information	108

PART III

Item 10. Corporate Governance and Board of Directors	109
Item 11. Executive Compensation	109
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	109
Item 13. Certain Relationships and Related Transactions, and Director Independence	109
Item 14. Principal Accounting Fees and Services	109

PART IV

Item 15. Exhibits, Financial Statement Schedules	110
Item 16. Summary	110
Signatures	114

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 leader in the subsea, onshore/offshore, and surface industries, with market-leading positions in oil and gas projects, technologies, systems, and services. We offer a portfolio of solutions for the production and transformation of oil and gas. These solutions range from discreet products and services to fully integrated solutions, with a clear focus to deliver greater efficiency across project lifecycles from concept to project delivery and beyond.

We operate across three business segments: Subsea, Onshore/Offshore, and Surface Technologies. We have further operational headquarters in Paris, France and Houston, Texas, United States.

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. We have also used these capabilities to develop a new subsea commercial model that is transforming the way the Company interacts with its customers and creates value with them.

Adaptation drives TechnipFMC’s solutions and environmental awareness allows us to be proactive. 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 from renewables to shale, expanding the range of our services, managing our assets efficiently, and ultimately being well-prepared to drive and benefit from the burgeoning recovery in our industry.

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 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 an 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 onshore or on floating vessels, through refining and product facilities.

The Company continued to innovate and introduce new technologies across our portfolio of products and services. TechnipFMC also delivered strong financial performance in 2017, 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 have manufacturing facilities located near the world’s principal offshore oil and gas producing basins. We operate flexible pipe manufacturing plants, umbilical production units, reeled rigid pipe shore-based facilities, plus a fleet of specialized vessels for pipeline installation, subsea construction, diving support and heavy lift.

We have created an industry leader in front end engineering and design (“FEED”), subsea production systems (“SPS”), flexible pipe, and subsea umbilicals, risers, and flowlines (“SURF”). Our strong commercial focus has enabled the successful market introduction of an integrated Subsea business model, which spans a project’s early phase design through the life-of-field. Our integrated business model is unlocking incremental opportunities and materially expanding the deepwater opportunity set.

Through integrated FEED studies, iFEED^TM (“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.

Further, we are driving even greater value through our ability to integrate the SPS and SURF scopes and more efficiently execute the installation campaign, known as integrated engineering, procurement, construction, and installation, iEPCI™ (“iEPCI”). Our first-mover advantage and ability to convert iFEED studies into iEPCI contracts, often as a direct award, also creates a unique proprietary 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, where we can provide the greatest benefit to project economics.

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.

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 supplier 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 delivery and reliability, while reducing total product cost and lead time to delivery.

Principal Products and Services

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

Our subsea production systems and products include drilling systems, subsea trees, chokes and flow modules, manifold pipeline systems, control and data management systems, well access systems, 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 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 engineering, project management, procurement, manufacturing, assembly and testing capabilities.

Flexible Pipe and Umbilical Supply. We perform the engineering and manufacturing of flexible pipes, relying on our engineering centers across various regions and our manufacturing units. In Brazil, the flexible pipes are delivered alongside the dock of the manufacturing unit and are loaded onto a vessel operated by the client. In other markets, TechnipFMC vessels typically install the flexible pipes.

We use 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. The Company relies upon 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.

Vessels. We operate a fleet consisting of 18 vessels, with two additional vessels under construction. Of the 18 vessels currently in operation, we have sole ownership of nine vessels, ownership of six vessels within joint ventures, and operate three vessels under long-term charter. The fleet has been reduced significantly since 2013, when it consisted of 36 vessels, including nine under construction at the time.

We wholly own five pipelay support vessels and jointly owns eight subsea construction vessels, including two under construction. All of the jointly owned vessels have a 50/50 ownership structure and operate exclusively in the Brazilian market. These vessels are 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 three 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 completion, (iii) asset management services for test, maintenance, refurbishment and upgrades of subsea equipment and tooling, (iv) field performance services based on product data and field data to optimize the performance of the subsea production systems, (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 Vehicles (“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 infrastructure, 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, 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, multi-phase flow meters, digital infrastructure, integrity monitoring, control functionality and automation features needed for subsea systems. Robotics capabilities are now being applied in the space of controlling manifold valves during production. This is a convergence of our technologies in order to provide a better systems for our customers.

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 key contracts.

Dependence on Key Customers

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

We actively pursue alliances with 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 more than 10% or more of our 2017 consolidated revenue.

Competition

Our Subsea segment competes across: subsea products, subsea projects and subsea services. For subsea products, we typically compete with companies that supply subsea systems, pipes, umbilicals, and smaller companies that are focused on a specific application, technology or geographical niche in which TechnipFMC operates. Competitors include OneSubsea (a Schlumberger company) (“OneSubsea”), Baker Hughes, a GE Company (“Baker Hughes”), Aker Solutions ASA, Dril-Quip, Inc., National Oilwell Varco and Oceaneering International, Inc. For Subsea EPCI, competitors include Subsea 7 S.A., Saipem S.p.A. (“Saipem”) and McDermott International Inc.

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 projects inbound for the industry. Operators continue to take needed actions to improve their subsea project economics and suppliers in turn continue to take the necessary steps to further reduce project break-even levels by offering cost-effective approaches for project developments. The risk of project sanctioning delays continues to be high 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 operators’ portfolios.

Strategy

Our strategy includes the following priorities:


•	early involvement in the conceptual design and integrated front-end engineering, or iFEED of subsea development projects to create value through technology and integration of scopes (integrated engineering, procurement, construction, and installation, or iEPCI ) by simplifying field architecture accelerating 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;


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


•	leverage of supplier relationships to capitalize on 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 a low crude oil price environment, we have adjusted our workforce and manufacturing capacity to align our operations with the anticipated decreases in activity due to delayed 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 will help mitigate the anticipated decline in operating margins in 2018.

In November 2017, we announced the launch of a completely new suite of products called Subsea 2.0. 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 operators making final investment decisions on several major developments. The Company’s full year Subsea orders of $5.1 billion in 2017 increased 16 percent from the prior year. In the fourth quarter, we received a major iEPCI award for the VNG Norge Fenja project in Norway. Our integrated business model is positively impacting project economics and expanding the deepwater opportunity set.

In 2018, we expect to see another increase in subsea market activity, driven by major projects, as well as a blend of small-to-mid size projects and service opportunities. In addition, we identify the following longer-term trends in the subsea market:


•	Smaller projects and direct awards represent a growing portion of our order mix. In 2017, these awards represented just over half of total inbound orders; the remainder being publicly announced projects as well as subsea service activities. Subsea tiebacks are often part of this mix; these shorter cycle brownfield expansions provide operators with faster paybacks and higher returns.


•	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 the ability to offer fully integrated solutions.


•	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 weaker 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. This includes growing customer acceptance of integrated business models to help achieve the cost-reduction goals and accelerate time to first oil and gas.

Product Development

We continue to expand our Subsea technologies portfolio of 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 deliver improved reliability and operations over the life of the field.

Technology development progressed on Subsea 2.0, the next generation of subsea equipment, utilizing designs that will be significantly smaller, lighter and simpler than current designs. These new products incorporate a modular product architecture and component level standardization to enable a flexible configure-to-order approach. The products are expected to deliver breakthrough in the way that subsea products are manufactured, assembled, installed and maintained over the life of the field. Several major elements of the portfolio were launched to the market during the year. 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 and beyond.

In addition to the investments made 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 are also advancing subsea robotic productivity through the development of more efficient ROV systems that are easier to operate and maintain.

Onshore/Offshore

The Onshore/Offshore segment offers a full range of services spanning the entire value chain to our customers, 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 a floating liquefied natural gas (“FLNG”) facilities.

Principal Products and Services

Development of Onshore Fields. We design and build different types of facilities for the development of onshore oil and gas fields, 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 relating 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 to support our clients’ capital projects from concept to delivery, including from the wellhead to LNG producing plant, 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. We have delivered 75 million metric tons per annum (“Mtpa”) since 2000, and currently have 24 Mtpa under construction. 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, onshore and offshore plants, and plants in remote locations. We have experience in the complete range of services for LNG receiving terminals from conceptual design studies to EPC. Following the world’s six largest LNG trains in Qatar, Yemen LNG, and a series of mid-scale LNG plants in China, together with our JV partners, we are delivering the Yamal LNG plant (“Yamal”) in the Russian Arctic..

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 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 oxides and sulfur oxides emissions, waste-water treatment, and waste management.

We have extensive experience in the development and inclusion of cryogenic NGL recovery processes in large gas treatment plants. We have unique expertise in efficiently extracting ethane and propane hydrocarbons due to our Cryomax® technology, which reduces the investment cost per ton of produced ethane or propane as compared to conventional expander plants. When used with LNG, Cryomax® technology allows the efficient production of ethane and propane as components of mixed refrigerant processes, even when processing very lean gas.

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%.

Petrochemicals and Fertilizers. We are a world leader 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 lumpsum 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: large conventional platforms with pile steel jackets whose topsides are installed offshore either by heavy life vessel or floatover; small, conventional platforms installed by small crane vessel; steel gravity-based structure platforms, generally with floatover topsides; and 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 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; and


•	Tension-Leg Platform (“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.

Floating liquefied natural gas. We pioneered the FLNG industry and are working closely with our clients to engineer three of the industry’s first FLNG contracts: the Shell Prelude FLNG facility and the ENI Coral South FLNG project. We are the only contractor to integrate all the core activities required to deliver an FLNG project: LNG process, offshore facilities, loading systems, and subsea infrastructure.

FLNG is an innovative alternative to traditional onshore LNG plants, and is suitable for remote and stranded gas fields that were deemed uneconomical previously. 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.

Capital Intensity

Our Onshore/Offshore business is executing turnkey contracts, performing engineering, procurement, construction, and project management for an entire or part of a facility. We can execute EPC contracts alone or in consortium with other companies.

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, individually represented more than 10% of 2017 consolidated revenue.

Competition

In the Onshore market, we face a large number of competitors, including U.S. companies (Bechtel, CB&I, Fluor, Jacobs and KBR), Japanese companies (Chiyoda Corporation, JGC Corporation and Toyo Engineering Corporation), European companies (Petrofac Ltd., Saipem, Tecnicas Reunidas, S.A., Maine Tecnimont Group and John Wood Group Plc) and Korean companies (GS Caltex Corporation, Hyundai Oilbank, Samsung Engineering Co., Ltd, SK Energy Co., Ltd., and Daelim Industrial 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 S.p.A., KBR, Inc., McDermott International Inc., China Offshore Oil Engineering Co. Ltd and JGC Corporation.

Seasonality

Our Onshore business is not sensitive to any 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 connected to other markets (for example, petrochemicals and fertilizers that are linked to world growth). This market is mostly present in developing countries with rapidly growing energy demand (in particular, in Asia) and countries with abundant oil and gas reserves that have decided to expand downstream (in particular, in the Middle East and Russia). The Onshore market remains relatively small in Western Europe, 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 impacted by changes in oil prices. Offshore fields in the Gulf of Mexico, the Middle East and the North Sea in Europe 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 investment from some of our clients. In the long-term, gas is expected to be a major element of the energy mix, requiring new investments in the upstream industry. FLNG opportunities exist in the medium term, particularly in Australia and East Africa.

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. Meanwhile, 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 as the fuel source continues to take a share of global energy demand. The trend is structural, driven by market preference for cleaner energy sources and the need to satisfy growing domestic demand in markets such as in the Middle East. To meet this demand, we believe that large gas projects will need to be sanctioned in the near to intermediate term.

As Onshore market activity levels remain stable, it provides our business with the opportunity to remain actively engaged in and pursue front-end engineering studies, which provide the platform for early engagement with clients and can significantly reduce the risk of 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 opportunity set could generate additional inbound orders in the coming years.

Product Development

We are positioned as a premier provider of project execution strategy 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) intensification and diversification of our proprietary technology offering.

Our Offshore R&D efforts are focused on improving the economics of FLNG through innovations in design and constructibility. 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 continued 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, skill and technology expertise covering a range of product lines, such as designed modular hydrogen plants; modular process plant and equipment using proprietary process technology and partnering with leading technology partners worldwide; fired heaters, reformers, ethylene furnaces: components and assemblies; and proprietary special application burners.

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. Surface Technologies designs, manufactures and supplies 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 frac systems and services, and production, separation and flow processing systems systems for exploration and production companies in the oil and gas industry, as well as measurement systems and loading arms solutions for the energy customers. We manufacture most of our products in several facilities located worldwide.

Principal Products and Services

Integrated Surface Drilling, Completion, and Production Systems. We provide a full range of drilling, completion and production wellhead systems for both standard and custom-engineered applications. Surface wellhead production systems, or

trees, are used to control and regulate the flow of crude oil and natural gas from the well. Our surface wellhead products and systems are used worldwide on both onshore and offshore applications and can be used in difficult climates, including arctic cold or desert high temperatures. Our product technologies include conventional wellheads, unihead drill-thru wellheads designed for faster surface installations, drilling time optimization time saving conventional wellheads designed to reduce overall rig time, and other technologies, including sealing technology, thermal equipment, and valves and actuators.

We support our customers through comprehensive surface wellhead system service packages that provide strategic solutions to ensure optimal equipment performance and reliability. 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 upgrades, interventions, decommissioning/abandonment, and maintenance, storage and preservations.

As part of our surface integrated services business, we provide an integrated shale offering, which includes manifolds, trees and flowback equipment for timely and cost-effective well completion. We also provide flowback services for the recovery of solids, fluids, and hydrocarbons from oil and natural gas wells after the stimulation of the well, and well optimization services for exploration companies in the oil and gas industry.

Pressure Control. We design and manufacture flowline products, under the Weco®/Chiksan® trademarks, articulating frac arm manifold trailers, well service pumps, compact valves and reciprocating pumps used in well completion and stimulation activities by major oilfield service companies, such as Halliburton Company, Schlumberger, Baker Hughes, a GE Company and Weatherford International plc. Our flowline products are used in equipment that pumps fluid into a well during the well construction and stimulation processes. Our well service pump product line includes triplex and quintuplex pumps utilized in a variety of applications, including fracturing, acidizing and matrix stimulation, and are capable of delivering flow rates up to 35 barrels per minute at pressures up to 20,000 psi. The performance of this business typically rises and falls with variations in the active rig count throughout the world and pressure pumping activity and intensity in the Americas.

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 risk 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 transfer loading solutions using Chiksan® loading arms and Chiksan® swivel joint 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 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 amount of rental equipment related to pressure operations.

Dependence on Key Customers

No single Surface Technologies customer accounted for 10% or more of our 2017 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 and product quality. Surface Technologies competes with other companies that supply surface production equipment and pressure control products. Some of our major competitors in Surface Technologies include Cameron International Corporation (a Schlumberger company), Weir Oil & Gas (a division of The Weir Group PLC), Baker Hughes, a GE Company, Forum Energy Technologies, Inc. and Gardner Denver, Inc.

Seasonality

In Western Canada, the level of activity in the oilfield services industry is influenced by seasonal weather patterns. During the spring months, wet weather and the spring thaw make the ground unstable and less capable of supporting heavy equipment and

machinery. As a result, municipalities and provincial transportation departments enforce road bans that restrict the movement of heavy equipment during the spring months, which reduces activity levels. There is greater demand for oilfield services, specifically completion services, provided by our Canadian surface integrated services business in the winter season when freezing permits the movement and operation of heavy equipment. Activities tend to increase in the fall and peak in the winter months of November through March.

Market Environment

While the North American rig count and market activity have steadily improved over the last year, the recovery has been constrained to certain oil and gas producing basins that can generate acceptable returns. The market recovery began in late 2016 in North America and continued through 2017. This increased activity has resulted in stronger demand for the Company’s products and services, particularly pressure control equipment. Activity outside of North America remains generally stable but continues 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 its customers in the drilling, completion, production, midstream and transportation sectors. We intend to grow and expand by focusing on improving customer economics and providing superior service.

Recent and Future Developments

We continue to operate in a challenging environment because of lower global activity and competitive pricing. North America rig count and operating activity have been steadily improving through 2017. The market has also benefited from increased service intensity related to hydraulic fracturing activity. As a result of these market dynamics, we have experienced stronger demand for pressure control equipment. Combined with our cost rationalization initiatives, we are capturing the economic benefits of the higher activity levels. In North America, we believe that we will see further market improvements, primarily driven by increased unconventional activity.

Outside of North America, we expect global activity levels to improve in 2018. In our business, we believe that the Middle East, Asia Pacific, and Europe are best poised for growth.While our international surface business experienced competitive pricing pressure throughout 2017, pricing has stabilized, with limited improvement in a few select international markets. We expect this pricing environment to continue throughout 2018.

Product Development

In 2017, 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. We also launched a fully automated and digitized Flow Testing Advanced Automated Package (AAP) leveraging the Company’s superior de-sanding technology and digital platform, which allows for remote monitoring and real-time data capture via the cloud.

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 business will be integrated into the our Surface Technologies segment and will include the transfer of key personnel from Plexus, with their specialized know-how, to ensure continuity and ongoing customer support. The business will continue to operate from the existing location in Dyce, Aberdeen, United Kingdom.

In December 2017, we opened a fully capable 18,000 square meter Surface international facility in Abu Dhabi’s Industrial City 2, as part of our continued investment in the United Arab Emirates to reinforce our leading position in delivering local solutions that extend asset life and improve returns for Abu Dhabi National Oil Company (“ADNOC”) and other customers. The launch of this facility positions us to respond to the expected increase in ADNOC activity in 2018 and beyond.

The new plant is part of a program to strengthen our capabilities in the Surface international business, but also provides a solid platform for us to grow our integrated offerings into the Middle East, including multiple product lines and aftermarket services that are key to the strategy. The new facility will offer a broader range of capabilities in-country, supporting our full portfolio with our high technology equipment in the drilling, completion, production, and pressure control sectors. The facility includes a

fully-developed training center, high-pressure hydraulic and gas testing capabilities, state of the art cladding, and machining technology and one-stop-shop for customer equipment storage, preservation, preparation, and make-up for mobilization to the field.

OTHER BUSINESS INFORMATION RELEVANT TO OUR BUSINESS SEGMENTS

Sources and Availability of Raw Materials

Our business segments purchases carbon steel, stainless steel, aluminum and steel castings and forgings from the global market place. We typically do not use single source suppliers for the majority of our raw material purchases; however, certain geographic areas of its 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 and product improvements. We have over 6,000 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, 2017, 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 22 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—SEC 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.

As of April 2, 2018, the executive officers of TechnipFMC, together with the offices held by them, their business experience and their ages, are as follows:



Name	Age	Current Position and Business Experience (Start Date)
Thierry Pilenko	60	Executive Chairman (2017) Chairman and Chief Executive Officer of Technip (2007)
Douglas J. Pferdehirt	54	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. Mannen	55	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. Ralston	51	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 (2012)
Bradley D. Beitler	64	Executive Vice President—Technology and R&D (2017) Vice President—Technology of FMC Technologies (2009)
Samik Mukherjee	48	Executive Vice President—Corporate Development, Strategy, Digital and IT (2017) Senior Vice President—Paris Operating Center of Technip (2016) Senior Vice President—Subsea Strategy and Business Development of Technip (2015) Managing Director and Country Head—India of Technip (2012)
Arnaud Piéton	44	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. Alabaster	57	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 Glickman	49	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)
Hallvard Hasselknippe	58	President—Subsea (2017) President and Chief Operating Officer—Subsea of Technip (2014) Chief Operating Officer—Subsea Asia-Pacific Region of Technip (2010)
Nello Uccelletti	64	President—Onshore/Offshore (2017) President—Onshore/Offshore of Technip (2014) Senior Vice President—Onshore/Offshore of Technip (2008)

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.

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 March 31, 2017 and December 31, 2017 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 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, 2017. In addition, as a result of these material weaknesses, our chief executive officer and chief financial officer have concluded that, as of December 31, 2017, 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 further 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 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 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 in 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.

Unanticipated changes relating to competitive factors in our industry, including ongoing industry consolidation, may impact our results of operations.

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;


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


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


•	technological advances affecting energy consumption;


•	potential acceleration of the development of alternative fuels;


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


•	natural disasters.

The oil and gas industry has historically experienced periodic downturns, which have been characterized by diminished demand for oilfield services and downward pressure on the prices we charge. The current downturn in the oil and gas industry, which began in 2014, has resulted in a 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 implement 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 or 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 or 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 develop technology independently 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 to 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 equipment malfunctions, equipment misuse, personal injuries and natural disasters, the occurrence of which may result in uncontrollable flows of gas or well fluids, fires and explosions. Although we have obtained insurance against many of these risks, our insurance may not be adequate to cover our liabilities. Further, the insurance may not generally be available in the future or, if available, premiums may not be commercially justifiable. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, such potential liabilities could have a material adverse effect on our business, results of operations, financial condition or cash flows.

We may lose money on fixed-price contracts.

As customary for the types of businesses that we operate, 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;


•	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 or subcontractors 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. 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 plants 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 seek to continuously upgrade and develop our asset base. 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;


•	issues regarding the design and engineering; 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 our future sales, profitability, and our relationships with our customers.

Many of the contracts we enter into with our customers require long manufacturing lead times due to complex technical and logistical requirements. These contracts may contain clauses related to liquidated damages or financial incentives regarding on-time delivery, and a failure by us to deliver in accordance with customer expectations could subject us to liquidated damages or loss of financial incentives, reduce our margins on these contracts or result in damage to existing customer relationships. The ability to meet customer delivery schedules for this backlog is dependent on a number of factors, including, but not limited to, access to the raw materials required for production, an adequately trained and capable workforce, subcontractor performance, project engineering expertise and execution, sufficient manufacturing plant capacity and appropriate planning and scheduling of manufacturing resources. Failure to deliver backlog in accordance with expectations could negatively impact our financial performance, particularly in light of the current industry environment where customers may seek to improve their returns or cash flows.

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 heavily depend on certain suppliers for raw materials or semi-finished goods.

Any difficulty faced by us in hiring 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 would be potentially obligated to assume our defaulting partner’s obligations. Based on these potential issues, we could be required to compensate our customers.

Any delay on the part of subcontractors, suppliers, or joint venture partners in the completion of work, any failure on the part of a subcontractor, supplier or joint venture partner to meet its obligations, or any other event attributable to a subcontractor, supplier or joint venture partner that is beyond our control or not foreseeable by us could lead to delays in the overall progress of the project and/or generate significant extra costs. Even if we were entitled to make a claim for these extra costs against the defaulting supplier, subcontractor or joint venture partner, we could 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 an inability to retain and motivate additional highly-skilled employees required for the operation and expansion of our business could hinder our ability to successfully conduct research activities and develop marketable products and services.

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

Our 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 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 will be exposed to a risk of violating anti-corruption laws and sanctions regulations. Some of the international locations in which we will 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.

While we believe we have a strong compliance program, including procedures to minimize and detect fraud in a timely manner, and continue efforts to improve our systems of internal controls, we can provide no assurance that the 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, and, as a result, we could be subject 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. We are required to invest financial and managerial resources to comply with environmental laws and regulations and believe that we will continue to be required to do so in the future. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, or the issuance of orders enjoining our operations. These laws and regulations, as well as the adoption of new legal requirements or other laws and regulations affecting exploration and development of drilling for crude oil and natural gas, could adversely affect our business and operating results by increasing our costs, limiting the demand for our products and services or restricting our operations.

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 such as North Africa, West Africa, the Middle East, and the Commonwealth of Independent States, could have an adverse effect on the demand for our 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 or price controls;


•	sanctions, such as restrictions by the United States against countries deemed to sponsor 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. While we would pursue alternative arrangements to preserve the listing and maintain trading, any such disruption could have a material adverse effect on the trading price of our shares.

The results of the United Kingdom’s referendum on 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, USA; 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 terms of any withdrawal are subject to a negotiation period that could last at least two years after the government of the United Kingdom formally initiated its withdrawal process in the first quarter of 2017. Nevertheless, 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 as well as for the governments of other E.U. member states to consider withdrawal.

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 decrease foreign direct investment in the United Kingdom. For example, withdrawal from the European Union could, depending on the negotiated terms of 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 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 among 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.

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 if, to the extent that, the distribution does not reduce the amount of those assets to less that that aggregate.

Following the Merger, we capitalized our reserves arising out of the Merger by the allotment and issuance by TechnipFMC of a bonus share, which was paid up using such reserves, such that the amount of such reserves so applied, less the nominal value of the bonus share, applied as share premium and accrued to our share premium account. We implemented a court-approved reduction of our capital by way of a cancellation of the bonus share and share premium account in the amount of $10,177,554,182, which 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.

We may not be able to pay dividends or repurchase shares of our ordinary shares in accordance with our announced intent or at all.

The Board of Directors’ determinations regarding dividends and share repurchases will depend on a variety of 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 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, 2017, after giving effect to the Merger, our total debt is $3.9 billion. We also have the capacity under our $2.5 billion credit facility and 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 failure 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.

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

The terms of our financing are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. Factors that may impact our credit ratings include debt levels, capital structure, planned asset purchases or sales, near- and long-term production growth opportunities, market position, liquidity, asset quality, cost structure, product mix, customer and geographic diversification and commodity price levels. A downgrade in our credit ratings, particularly to non-investment grade levels, could limit our ability to access the debt capital markets, refinance our existing debt or cause us to refinance or issue debt with less favorable terms and conditions. Moreover, our revolving credit agreement includes an increase in interest rates if the ratings for our debt are downgraded, which could have an adverse effect on our results of operations. An increase in the level of our indebtedness and related interest costs may increase our vulnerability to adverse general economic and industry conditions and may affect our ability to obtain additional financing.

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 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 devote significant 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 to realize the anticipated benefits of the Merger could cause an interruption of our operations and could seriously harm our results of operations. In addition, the overall integration of Technip and FMC Technologies may result in material unanticipated problems, expenses, liabilities, competitive responses, loss of client relationships and diversion of management’s attention, and may cause our stock prices 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, which may prove to be incompatible;


•	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 will be 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 or 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.

We may incur significant Merger-related costs.

We have incurred and expect to incur many non-recurring direct and indirect costs associated with the Merger. In addition to the cost and expenses associated with the consummation of the Merger, there are also processes, policies, procedures, operations, technologies and systems that must be integrated in connection with the Merger and the integration of Technip and FMC Technologies. While both Technip and FMC Technologies 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. There may also be significant additional unanticipated costs relating to the Merger that we may not recoup. These costs and expenses could reduce the realization of efficiencies and strategic benefits we expect to achieve from the Merger. Although we expect that these benefits will offset the transaction expenses and implementation costs over time, this net benefit may not be achieved in the near term or at all.

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. Despite our implementation of security measures, our systems are vulnerable to damages from computer viruses, natural disasters, failures in hardware or software, power fluctuations, increasingly sophisticated cyber security threats such as unauthorized access to data and systems, loss or destruction of data (including confidential customer information), phishing, cyber attacks, human error and other similar disruptions. Additionally, we rely on third parties to support the operation of our IT hardware and software infrastructure, and in certain instances, utilize web-based applications.

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, or 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.

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 is generally considered a U.S. “domestic” corporation (or U.S. tax resident) if it is organized in the United States, and a corporation is generally considered a “foreign” corporation (or non-U.S. tax resident) if it is not a U.S. domestic corporation. Because we are an entity incorporated in England and Wales, we would generally be classified as a foreign corporation (or 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 U.S. domestic corporation for U.S. federal income tax purposes.

Unless we have satisfied the substantial business activities exception, as defined for purposes of Section 7874 and described in more detail below (the “Substantial Business Activities Exception”), we will be treated as a U.S. domestic corporation (that is, as a U.S. tax resident) for U.S. federal income tax purposes under Section 7874 if the percentage (by vote or value) of our shares considered to be held by former holders of shares of common stock of FMC Technologies (the “FMCTI Shares”) after the Merger by reason of holding FMCTI Shares for purposes of Section 7874 (the “Section 7874 Percentage”) is (i) 60% or more (if, as expected, the Third Country Rule (defined below) applies) or (ii) 80% or more (if the Third Country Rule does not apply). In order for us to satisfy the Substantial Business Exception, at least 25% of the employees (by headcount and compensation), real and tangible assets and gross income of our expanded affiliated group must be based, located and derived, respectively, in the United Kingdom. We do not expect to satisfy the Substantial Business Activities Exception. In addition, the IRS and the U.S. Treasury have issued a rule that generally provides that if (i) there is an acquisition of a domestic company by a foreign company in which the Section 7874 Percentage is at least 60%, and (ii) in a related acquisition, such foreign acquiring company acquires another foreign corporation and the foreign acquiring company is not subject to tax as a resident in the foreign country in which the acquired foreign corporation was subject to tax as a resident prior to the transactions, then the foreign acquiring company will be treated as a U.S. domestic company for U.S. federal income tax purposes (the “Third Country Rule”). Because we are a tax resident in the United Kingdom and not a tax resident in France as Technip was, we

expect that we would be treated as a U.S. domestic corporation for U.S. federal income tax purposes under the Third Country Rule if the Section 7874 Percentage were at least 60%.

In addition, if the Section 7874 Percentage is calculated to be at least 60%, Section 7874 and the rules related thereto may impose an excise tax under Section 4985 of the Code (the “Section 4985 Excise Tax”) on the gain recognized by certain “disqualified individuals” (including officers and directors of a U.S. company) on certain stock-based compensation held thereby at a rate equal to 15%, even if the Third Country Rule were to apply such that we were treated as a U.S. domestic corporation for U.S. federal income tax purposes. We may, if we determine that it is appropriate, provide disqualified individuals with a payment with respect to the excise tax, so that, on a net after-tax basis, they would be in the same position as if no such excise tax had been applied.

We believe that the Section 7874 Percentage was less than 60% such that the Third Country Rule is not expected to apply to us and the Section 4985 Excise Tax is not expected to apply to any such “disqualified individuals.” However, the calculation of the Section 7874 Percentage is complex and is subject to detailed U.S. Treasury regulations (the application of which is uncertain in various respects and would be impacted by changes in such U.S. Treasury regulations). In addition, there can be no assurance that there will not be a change in law, including with retroactive effect, which might cause us to be treated as a U.S. domestic corporation for U.S. federal income tax purposes. Accordingly, we cannot assure you that the IRS will agree with our position and/or would not successfully challenge our status as a foreign corporation.

U.S. tax laws and/or IRS 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 and U.S. Treasury regulations promulgated thereunder may adversely affect our ability to engage in certain future acquisitions of U.S. businesses in exchange for our equity or to otherwise restructure the non-U.S. members of our group, which 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 states that these rules are the subject of continuing study and may be 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 tax laws of numerous jurisdictions, and challenges to the interpretations 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 Organization for Economic Co-operation and Development, 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. One example beyond that of the Tax Cuts and Jobs Act (“TCJA”) is in the area of “base erosion and profit shifting” where payments are made between affiliates from a jurisdiction with high tax rates to a jurisdiction with lower tax rates. Thus, the tax laws in the United States, the United Kingdom and other countries in which we and our affiliates do business could change on a retroactive basis and any such changes could adversely affect us. Furthermore, the interpretation and application of domestic or international tax laws made by us and by our subsidiaries could differ from that of the relevant governmental authority, which could result in administrative or judicial procedures, actions or sanctions, which could be material.

We may not qualify for benefits under the 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 the tax treaties between the United Kingdom and other countries, notably the United States. However, our ability to qualify for such benefits will depend on whether we are treated as a U.K. tax resident and upon the requirements contained in each treaty and the applicable domestic laws, as the case may be, on the facts and circumstances surrounding our operations and management, and on the relevant interpretation of the

tax authorities and courts. The failure by us or our subsidiaries to qualify for benefits under the tax treaties entered into between the United Kingdom and other countries could result in adverse tax consequences to us and could result in certain tax consequences of owning and disposing of our shares.

We intend to operate 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 England and Wales. English law currently provides that we will be regarded as being 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 due to the French tax authorities having deemed that certain strategic decisions of TechnipFMC have been taken at the level of our French permanent establishment rather than in the United Kingdom. Any such claim would need to be settled between the French and the U.K. tax authorities pursuant to the mutual assistance procedure provided for by the tax treaty dated June 19, 2008 concluded between France and the United Kingdom, and there is no assurance that these authorities would reach an agreement that we will remain exclusively a U.K. tax resident, 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 different tax consequences of owning and disposing of our shares.

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, 2017:



Location		Segment
Africa
Accra, Ghana		Subsea
Danda, 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
Hyderadbad, India		Surface
Jakarta, Indonesia		Subsea, Onshore/Offshore, Surface
Kuala Lumpur, Malaysia		Subsea, Onshore/Offshore
Labuan, Malaysia		Subsea
New Delhi, India		Onshore/Offshore
Noida, India		Onshore/Offshore
Nusajaya, Malaysia		Subsea, Surface
Singapore		Surface
Australia
Henderson, Australia		Subsea
Perth, Australia		Subsea, Onshore/Offshore
Europe
Aberdeen (Scotland), 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, Scotland		Subsea, Surface
Ellerbeck, Germany		Surface
Evanton (Scotland), 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
Orkanger, Norway		Subsea
Oslo, Norway		Subsea
Paris, France		Subsea, Onshore/Offshore
Pori (Mäntyluoto), Finland		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
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
Maracaibo, Venezuela		Surface
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 interestor operated as of December 31, 2017:



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 ⁽¹⁾	HCV	Construction/installation systems
Skandi Africa ⁽¹⁾	HCV	Construction/installation systems
North Sea Giant ⁽¹⁾	HCV	Construction/installation systems
Deep Arctic	DSV/HCV	Diver support systems
Wellservicer ⁽³⁾	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 ⁽²⁾	PLSV	Flexible pipelay/umbilical systems
Skandi Recife ⁽²⁾	PLSV	Flexible pipelay/umbilical systems

_______________________


⁽¹⁾	Vessels under long term charter.


⁽²⁾	Vessel under construction.


⁽³⁾	Vessels held for sale.

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. TechncipFMC, 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 officers and a former employee of the Company. The suit alleges 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. The Company is vigorously contesting the litigation and cannot predict its duration or outcome.

In addition to the above-referenced matter, 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. The share prices shown in the table below prior to the Merger reflect FMC Technologies common stock prices under the FTI symbol on the NYSE.



	2017								2016
	4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.		4th Qtr.		3rd Qtr.		2nd Qtr.		1st Qtr.
Share closing price:
High	$	31.48	$	28.89	$	33.64	$	36.73	$	36.31	$	29.67	$	30.49	$	29.22
Low	$	24.96	$	25.17	$	26.49	$	31.22	$	29.88	$	24.20	$	24.42	$	22.77



Closing share price at December 29, 2017	$	31.31
Closing share price at March 27, 2018	$	29.00
Number of ordinary share stockholders of record at March 27, 2018	697

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 of December 31, 2017, 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⁽¹⁾
Equity compensation plans approved by security holders	4,883.8	$	36.35	30,284.5
Equity compensation plans not approved by security holders	—	—		—
Total	4,883.8	$	36.35	30,284.5

______________________________

⁽¹⁾

The table includes our ordinary shares available for future issuance under the TechnipFMC plc Incentive Award Plan as well as plans approved prior to, and still active on the date of, the Merger. This number includes 3,170.5 thousand shares available for issuance for non-vested share awards that vest after December 31, 2017 under the TechnipFMC plc Incentive Award Plan, and 6,184.5 thousand shares issued under plans approved prior to the merger that vest after December 31, 2017.

We had no unregistered sales of equity securities during the year ended December 31, 2017.

The following table summarizes repurchases of our ordinary shares during the three months ended December 31, 2017.



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, 2017 – October 31, 2017	732,500	$	26.53	732,100	17,642,911
November 1, 2017 – November 30, 2017	668,100	$	27.79	667,740	16,975,171
December 1, 2017 – December 31, 2017	583,580	$	29.10	583,000	16,392,171
Total	1,984,180			1,982,840	16,392,171

______________________________

^(a)

Represents 1,982,840 ordinary shares purchased and canceled and 1,340 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 6,680 registered ordinary shares held in this trust, as directed by the beneficiaries during the three months ended December 31, 2017.


^(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.

ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth selected financial data of the Company for each of the three years in the period ended December 31, 2017. 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. Financial data for 2013 and 2014 is only available in International Financial Reporting Standards (“IFRS”), has not previously been required to be presented by the host country regulator, and cannot be provided in GAAP without unreasonable effort or expense.



(In millions, except per share data) Years Ended December 31	2017⁽¹⁾		2016		2015
Statement of income data:
Total revenue	$	15,056.9	$	9,199.6	$	11,471.9
Total costs and expenses	$	14,091.7	$	8,743.6	$	11,198.3
Net income	$	134.2	$	371.1	$	14.0
Net income attributable to TechnipFMC plc	$	113.3	$	393.3	$	14.4

Earnings per share from continuing operations attributable to TechnipFMC plc:
Basic earnings per share	$	0.24	$	3.29	$	0.13
Diluted earnings per share	$	0.24	$	3.16	$	0.13



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



(In millions) Years Ended December 31	2017⁽¹⁾		2016		2015
Other financial information:
Capital expenditures	$	255.7	$	312.9	$	325.5
Cash flows provided by operating activities	$	210.7	$	493.8	$	700.3
Net (debt) cash ⁽²⁾	$	2,882.4	$	3,716.4	$	370.4
Order backlog ⁽³⁾	$	12,982.8	$	15,002.0	$	18,475.5

______________________________

⁽¹⁾

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.

⁽²⁾

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


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

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

Executive Overview

We 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 22 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, 2017, 2016 and 2015 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 primarily affected by trends in deepwater oil and natural gas production. Our Onshore/Offshore segment is affected by commodity prices, population growth and demand for natural gas. Our Subsea and Onshore/Offshore segments benefit through the construction of petrochemical and fertilizer plants, and requirements for new liquefied natural gas facilities, respectively. Our Surface Technologies segment is primarily affected by trends in land-based and shallow water oil and natural gas production, including trends in shale production. We have developed close working relationships with our customers. Our 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 2017, 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—The price of crude oil recovered in 2017 when compared to the prior year, and the price has been steadily increased throughout the last six months of the year. Nonetheless, the oil and gas industry continues to experience the overall impacts of the steep decline in crude oil prices that were experienced in prior years and there are some lingering uncertainties in the crude oil price outlook. Despite OPEC’s implementation of a cap on crude oil production in 2017, ongoing uncertainty in the crude oil price outlook remains due to concerns about the effectiveness and duration of both concurrent OPEC and non-OPEC production cuts, the impact of additional production capacity entering the market due to expanding U.S. shale production, the associated impact on worldwide production, and continued high inventory levels. The sustainability of the 2017 crude oil price recovery and business activity levels is dependent on a number of variables, but many analysts continue to believe the market corrections necessary to address the worldwide oversupply of crude oil are in place and are contributing to sustainable industry improvement. As long-term demand continues to rise and production continues to naturally decline, we believe commodity prices should demonstrate an ongoing ability for continued improvement, increasing both our cash flows and the confidence of our customers to increase their investments in new sources of oil and natural gas production. We

witnessed such improvements as we exited 2017 as customers globally were proceeding with final investment decisions at an improved pace over 2015 and 2016.

Subsea—The impact of the low crude oil price environment over the last two years led many of our customers to reduce their capital spending plans or defer new deep-water projects. We began to reduce our workforce and adjust manufacturing capacity to align our operations with the anticipated decreases in activity in 2016 due to delayed Subsea project inbound orders, and to mitigate the impact to operating margins. We continued such actions in 2017 and we have been realizing the benefits from these restructuring actions by attaining more cost-effective manufacturing. We expect to continue to take additional actions in 2018 as Company activity continues to slow in the near-term, but we are mindful that increased market activity levels are likely to be experienced in 2018 as a result of the improved industry economic environment, which will likely lead to increased order activity going forward. The operational improvements and cost reductions made in 2016, combined with additional actions taken in 2017, have protected operating margins in 2017, while still providing us with the capability to respond to the market recovery that we believe has commenced. We also recognize the need to continue to invest in our people to ensure that we preserve the core competencies and capabilities that delivered strong results in 2017 and will be necessary for continued success during the market recovery. Our customers are continuing to take aggressive actions to improve their project economics and to capitalize upon the improved commodity price environment and we are monitoring customer activity in the context of these improved oil and gas prices. There continues to be risk of project sanctioning delays in the current environment, however, as described above, project economics have improved considerably, and consequently, many offshore discoveries could be developed economically at today’s crude oil prices. Accordingly, we continue to work closely with our customers and believe that with our unique business model we can further reduce their project break-even levels by offering cost-effective approaches to their project developments, including customer acceptance of integrated business models to help achieve the cost-reduction goals and accelerate achievement of first oil. In the long term, we continue to believe that deepwater development will remain a significant part of our customers’ portfolios. However, further delays in project sanctions in the near term would unfortunately lead us to take further aggressive actions to ensure our cost base is aligned with the evolving market outlook.

Onshore/Offshore—The Offshore market faces many of the same constraints as the Subsea business due to lingering industry challenges to improve project economics. Meanwhile, Onshore market activity continues to provide a tangible set of opportunities, and in particular for natural gas projects as natural gas continues to take a larger share of global energy demand. Activity in LNG is fueled by the potential for sustained modest natural gas prices, representing an important opportunity set for our business. We remain confident that the industry will make further LNG investments in the near to intermediate term. We also see opportunities for refining and petrochemical projects. As Onshore market activity levels remain stable, it provides our business with the opportunity to remain actively engaged in and pursue front-end engineering studies that provide the platform for early engagement with clients, which can significantly de-risk project execution. Market opportunities for downstream front-end engineering studies and full EPC projects are most prevalent in the Middle East, Africa and Asia markets in LNG, refining and petrochemicals.

Surface Technologies—While North America rig count and operating activity have steadily improved since the fall of 2016, the recovery has been somewhat constrained to certain oil and gas producing basins that have the ability to generate acceptable returns. The market recovery began in late 2016 in North America and continued throughout 2017. To our benefit, we have experienced sustained stronger demand for pressure control equipment driven by this increased activity. The pace of improvement is likely to slow in 2018 with expectations of more moderate rig count growth compared to 2017. However, our restructuring actions that were taken in 2016 and 2017 have reduced costs and allowing us to capture the economic benefits of the higher activity levels. Activity in our international surface business has been strengthening, but continues to experience some impact of competitive pricing pressure that began in 2016. Pricing has stabilized and in some geographies improved, but we have not yet witnessed a material recovery. We expect this competitive pricing environment to continue and to have some negative impact on operating margins into the first half of 2018, with the benefit of improved pricing beginning to materialize in the second half of 2018.

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 years ended December 31, 2016 and 2015 represent Technip only.

CONSOLIDATED RESULTS OF OPERATIONS



	Year Ended December 31,												Change
(In millions, except percentages)	2017			2016 Pro Forma**			2016			2015			2017 vs. 2016 Pro Forma				2016 vs. 2015
Revenue	$	15,056.9		$	19,068.8		$	9,199.6		$	11,471.9		$	(4,011.9	)	(21)%	$	(2,272.3	)	(20)%
Costs and expenses:
Cost of sales	12,524.6			16,382.5			7,630.0			9,975.1			(3,857.9		)	(24)	(2,345.1		)	(24)
Selling, general and administrative expense	1,060.9			1,229.9			572.6			689.6			(169.0		)	(14)	(117.0		)	(17)
Research and development expense	212.9			219.5			105.4			95.5			(6.6		)	(3)	9.9			10
Impairment, restructuring and other expense	191.5			443.6			343.0			438.1			(252.1		)	(57)	(95.1		)	(22)
Merger transaction and integration costs	101.8			137.8			92.6			—			(36.0		)	(26)	92.6			*
Total costs and expenses	14,091.7			18,413.3			8,743.6			11,198.3			(4,321.6		)	(23)	(2,454.7		)	(22)
Other income (expense), net	(25.9		)	12.1			6.5			(102.9		)	(38.0		)	(314)	109.4			106
Income from equity affiliates	55.6			10.9			117.7			51.0			44.7			410	66.7			131
Net interest expense	(315.2		)	(29.1		)	(28.8		)	(71.2		)	(286.1		)	(983)	42.4			60
Income before income taxes	679.7			649.4			551.4			150.5			30.3			5	400.9			266
Provision for income taxes	545.5			284.7			180.3			136.5			260.8			92	43.8			32
Income from continuing operations	134.2			364.7			371.1			14.0			(230.5		)	(63)	357.1			*
Income (loss) from discontinued operations, net of income taxes	—			(10.1		)	—			—			10.1			100	—			—
Net income	134.2			354.6			371.1			14.0			(220.4		)	(62)	357.1			*
Less: net income (loss) attributable to noncontrolling interests	(20.9		)	23.6			22.2			0.4			(44.5		)	(189)	21.8			*
Net income attributable to TechnipFMC plc	$	113.3		$	378.2		$	393.3		$	14.4		$	(264.9	)	(70)%	378.9			*

_______________________



*	Not meaningful
**	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.

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 21 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.

2016 Compared With 2015

Revenue

Revenues decreased $2,272.3 million compared to the prior-year period, primarily resulting from the Onshore/Offshore segment, which contributed $1,602.2 million to the overall decrease. Onshore/Offshore activities sharply decreased across all geographical areas, specifically Asia Pacific, the Americas and the Middle East. The Subsea segment decreased by $670.1 million, mainly due to decreased activities in the North Sea, which was not fully offset by increased activities in other geographic regions.

Gross profit

Gross profit (revenue less cost of sales) increased as a percentage of sales to 17.1% in 2016, from 13.0% in the prior-year. The improvement in gross profit was primarily due to a more favorable project mix year-over-year. The components of cost of sales with the largest year-over-year decrease were purchase and construction subcontracting costs for projects and payroll costs.

Selling, general and administrative expense

Selling, general and administrative expense decreased by $117.0 million year-over-year due to the reduction of total employee headcount and the cessation of non-essential activities.

Impairment, restructuring and other expense

Impairment, restructuring and other expense decreased by $95.1 million year-over-year. Beginning in 2015, we implemented restructuring plans across our businesses to reduce costs and better align our workforce with anticipated activity levels, which included asset impairments, lease overhangs, appropriate amounts for disputes with some clients, closure costs of subsidiaries and additional amounts on ongoing projects. A significant portion of the restructuring plan was implemented in 2015, giving rise to the decrease in restructuring expense year-over-year.

Merger transaction and integration costs

We incurred merger transaction and integration costs of $92.6 million primarily during the fourth quarter of 2016 due to 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.

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 2016, we incurred $123.3 million of additional net foreign exchange gains compared to 2015. The increase was partially offset by net losses from the disposal of assets.

Net interest expense

The decrease in net interest expense was primarily due to an increase in interest income as well as a slight reduction in other borrowings and bank overdrafts during 2016.

Provision for income taxes

Our income tax provisions for 2016 and 2015 reflected effective tax rates of 32.7% and 90.6%, respectively. The year-over-year decrease in the effective tax rate was primarily due to decreases in our valuation allowance due to lower losses generated in 2016 for which no tax benefit is expected to be realized and a favorable change in the actual country mix of earnings.

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 22 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 %)	2017 ⁽¹⁾			2016 Pro Forma			2016			2015			2017 vs. 2016 Pro Forma					2016 vs. 2015
Revenue	$	5,877.4		$	9,150.5		$	5,850.5		$	6,520.6		$	(3,273.1	)	(36)%		$	(670.1	)	(10)%
Operating profit	$	460.5		$	982.6		$	732.0		$	866.9		$	(522.1	)	(53)%		$	(134.9	)	(16)%

Operating profit as a percent of revenue	7.8		%	10.7		%	12.5		%	13.3		%				(2.9	) pts.				(0.8	) pts.

_______________________


⁽¹⁾	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.

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.

2016 Compared With 2015

Subsea revenue decreased $670.1 million year-over-year primarily due to decelerating activity in the North Sea after completion of some key projects such as Bøyla and Snøhvit in Norway. In the Middle East, increased activity was driven by Rashid C in Dubai, United Arab Emirates, while in Asia Pacific activity was driven by the ramp-up of Jangkrik in Indonesia. Meanwhile, Subsea revenues increased in Brazil, primarily due to high-technology supply contracts for the Lula Alto and Iracema Sul pre-salt fields, whereas activity remained stable in the Americas.

Subsea operating profit as a percentage of revenue decreased year-over-year primarily a result of a reduced group fleet activity in the North Sea during 2016, despite more offshore operations in West Africa, Asia Pacific and the Middle East during that same period. Meanwhile, manufacturing plants operated at a slightly lower level of activity during 2016 compared to 2015.

Onshore/Offshore



	Year Ended December 31,												Favorable/(Unfavorable)
(In millions, except %)	2017			2016 Pro Forma			2016			2015			2017 vs. 2016 Pro Forma					2016 vs. 2015
Revenue	$	7,904.5		$	8,690.0		$	3,349.1		$	4,951.3		$	(785.5	)	(9)%		$	(1,602.2	)	(32)%
Operating profit (loss)	$	810.9		$	184.5		$	34.1		$	(313.3	)	$	626.4		340%		$	347.4		111%

Operating profit (loss) as a percent of revenue	10.3		%	2.1		%	1.0		%	(6.3		)%				8.2	pts.				7.3	pts.

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.

2016 Compared With 2015

Onshore/Offshore revenue decreased $1.6 billion year-over-year. The decrease was sharp across most of the geographic areas primarily as a result of some key projects nearing completion, such as SK 316 and Malikai in Malaysia and Ethylene XXI in Mexico. Elsewhere, revenues were driven by the Juniper project in Trinidad and the Duslo ammoniac plant in Slovakia.

Operating profit in the year ended 2016 compared to the year ended 2015 was favorably impacted by a decrease of $113.2 million related to impairment, restructuring and other severance charges.

Onshore/Offshore operating profit as a percentage of revenue increased year-over-year primarily due to considerable progress on Yamal as well as cost-saving measures across the segment.

Surface Technologies⁽²⁾



	Year Ended December 31,						Favorable/(Unfavorable)
(In millions, except %)	2017 ⁽¹⁾			2016 Pro Forma			2017 vs. 2016 Pro Forma
Revenue	$	1,274.6		$	1,252.2		$	22.4	2%
Operating profit (loss)	$	82.7		$	(122.0	)	$	204.7	168%

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

_______________________


⁽¹⁾	Due to the Merger, there were 11.5 months included in the year ended 2017 for legacy FMC Technologies, compared with twelve months in 2016. Refer to Note 2 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.


⁽²⁾	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 and 2015 do not include Surface Technologies.

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 %)	2017			2016 Pro Forma			2016			2015			2017 vs. 2016 Pro Forma			2016 vs. 2015
Corporate expense	$	(359.2	)	$	(366.6	)	$	(185.9	)	$	(331.9	)	$	7.4	2%	$	146.0	44%

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.

2016 Compared With 2015

Corporate expense decreased by $146.0 million year-over-year primarily due to cost-saving measures instituted at the corporate level.

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)	2017		2016
Subsea	$	5,143.6	$	2,384.9
Onshore/Offshore	3,812.9		3,689.0
Surface Technologies	1,239.8		—
Total inbound orders	$	10,196.3	$	6,073.9

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



	Order Backlog December 31,
(In millions)	2017		2016
Subsea	$	6,203.9	$	4,909.0
Onshore/Offshore	6,369.1		10,093.0
Surface Technologies	409.8		—
Total order backlog	$	12,982.8	$	15,002.0

Subsea. Order backlog for Subsea at December 31, 2017, increased by $1.3 billion from December 31, 2016 primarily due to the Merger. Subsea backlog of $6.2 billion at December 31, 2017, was composed of various subsea projects, including Petrobras’ pipelay support vessel and pre-salt tree awards; the Eni S.pA. Coral project; Total’s Kaombo; VNG’s Fenja; the Mellitah Oil & Gas B.V. Bahr Essalam project; the Woodside Energy Ltd. Greater Enfield project; Statoil’s Peregrino Phase II; BP’s Shah Deniz; and Shell’s Appomattox.

Onshore/Offshore. Onshore/Offshore order backlog at December 31, 2017, decreased by $3.7 billion compared to December 31, 2016. Onshore/Offshore backlog of $6.4 billion was composed of various projects, including Yamal; Emirates National Oil Company’s Jebel Ali refinery expansion; Total’s Martin Linge; JSC Sibur Holding’s Zapsib-2; Eni’s Ghana onshore receiving gas terminal; the ADNOC Offshore (previously ADMA-OPCO) Umm Lulu Phase 2 project; and Shell’s Prelude FLNG.

Liquidity and Capital Resources

Most of our cash is managed centrally and flowed through centralized bank accounts controlled and maintained by TechnipFMC domestically and in foreign jurisdictions to best meet the liquidity needs of our global operations. The majority of cash held by subsidiaries of our U.S. domiciled companies could be repatriated to the United States. Under current U.S. law, as amended by the Tax Cuts and Jobs Act (TCJA), signed into law on December 22, 2017, any such 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 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, 2017			December 31, 2016
Cash and cash equivalents	$	6,737.4		$	6,269.3
Short-term debt and current portion of long-term debt	(77.1		)	(683.6		)
Long-term debt, less current portion	(3,777.9		)	(1,869.3		)
Net cash	$	2,882.4		$	3,716.4

The gross change in the debt and cash components of our net (debt) cash position was primarily due to 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 Flows

Cash flows for each of the years in the three-year period ended December 31, 2017, were as follows:



	Year Ended December 31,
(In millions)	2017			2016			2015
Cash provided by operating activities	$	210.7		$	493.8		$	700.3
Cash provided (required) by investing activities	1,250.0			3,110.5			(335.1		)
Cash required by financing activities	(1,054.8		)	(534.6		)	(127.2		)
Effect of exchange rate changes on cash and cash equivalents	62.2			21.6			(320.6		)
Increase (decrease) in cash and cash equivalents	$	468.1		$	3,091.3		$	(82.6	)

Operating cash flows—During 2017, we generated $210.7 million in cash flows from operating activities, which was a $283.1 million decrease compared to 2016. Our cash flows from operating activities in 2016 were $206.5 million lower than 2015. The decrease in cash provided by operating activities in 2017 was due to the change in accounts payables and advance payments and billings in excess of costs slightly offset by the change in trade receivables, net and costs in excess of billings. The year-over-year decrease in 2016 was due to the change in trade receivables, net and costs in excess of billings. Our working capital balances can vary significantly depending on the payment and delivery terms on key contracts in our portfolio of projects.

Investing cash flows—Investing activities provided $1.3 billion in 2017 primarily due to 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 $3.1 billion, primarily reflecting cash acquired through an acquisition. Refer to Note 8 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.

Our cash requirements for investing activities in 2015 were $335.1 million, primarily reflecting capital expenditures.

Financing cash flows—Financing activities used $1.1 billion 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.

Financing activities used $534.6 million in 2016. The increase of $407.4 million in cash required for financing activities from 2015 was driven by the increase in net repayments of $59.1 million long-term debt as well as $186.8 million of treasury share purchases during 2016.

Debt and Liquidity

Total borrowings at December 31, 2017 and 2016, comprised the following:



(In millions)	December 31, 2017			December 31, 2016
Revolving credit facility	$	—		$	—
Bilateral credit facilities	—			—
Commercial paper	1,450.4			210.8
Synthetic bonds due 2021	502.4			431.8
Convertible bonds due 2017	—			524.5
3.45% Senior Notes due 2022	500.0			—
5.00% Notes due 2020	239.9			210.8
3.40% Notes due 2022	179.9			158.1
3.15% Notes due 2023	155.9			137.0
3.15% Notes due 2023	149.9			131.8
4.00% Notes due 2027	89.9			79.1
4.00% Notes due 2032	119.9			105.4
3.75% Notes due 2033	119.9			105.4
Bank borrowings	332.5			452.1
Other	28.2			20.3
Unamortized debt issuance costs and discounts	(13.8		)	(14.2		)
Total borrowings	$	3,855.0		$	2,552.9

The following is a summary of our revolving credit facility at December 31, 2017:



(In millions) Description	Amount		Debt Outstanding		Commercial Paper Outstanding (a)		Letters of Credit		Unused Capacity		Maturity
Five-year revolving credit facility	$	2,500.0	$	—	$	1,450.4	$	—	$	1,049.6	January 2022

______________________________


^(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 $1,450.4 million of commercial paper issued under our facility at December 31, 2017. 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, 2017.

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, 2017, 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 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 21 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 $1,049.6 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. However, management believes, based on our current financial condition, existing backlog levels and current expectations for future market conditions, that we will continue to meet our short- and long-term liquidity needs with a combination of cash on hand, cash generated from operations and access to capital markets. While we will continue to reach payment milestones on our projects, we expect our consolidated operating cash flow in 2018 to decrease as a result of the negative impact of the decline in commodity prices and the corresponding impact the industry downturn has had on our overall business in terms of the number of new projects awarded and the payment terms and conditions of such project awards during 2016 and 2017. Consequently, any payment deferrals or discounts on pricing granted to clients in prior years may adversely affect our results of operations and cash flows in 2018 and beyond.

We project spending approximately $300 million in 2018 for capital expenditures, largely on expenditures in our subsea service business. However, projected capital expenditures for 2018 does 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 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 executed over the remainder of 2017 and will be completed in 2018. Also, on October 25, 2017, it was announced that our Board of Directors authorized and declared an initial quarterly cash dividend of $0.13 per ordinary share.

During 2018, we expect to make contributions of approximately $19.9 million to our pension plans. 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. Additionally, we expect to make payments of approximately $5.3 million to our U.S. Non-Qualified Defined Benefit Pension Plan during 2018.

Contractual Obligations

The following is a summary of our contractual obligations at December 31, 2017:



	Payments Due by Period
(In millions) Contractual obligations	Total payments		Less than 1 year		1-3 years		3 -5 years		After 5 years
Debt ^(a)	$	3,855.0	$	77.1	$	1,972.9	$	1,179.0	$	626.0
Interest on debt ^(a)	409.4		62.6		125.2		96.5		125.1
Operating leases ^(b)	1,783.6		347.2		556.4		302.9		577.1
Purchase obligations ^(c)	5,263.4		4,140.2		912.8		11.7		198.7
Pension and other post-retirement benefits ^(d)	25.2		25.2		—		—		—
Unrecognized tax benefits ^(e)	96.3		96.3		—		—		—
Other contractual obligations ^(f)	$	312.0	$	69.7	$	151.6	$	70.0	$	20.7
Total contractual obligations	$	11,744.9	$	4,818.3	$	3,718.9	$	1,660.1	$	1,547.6

______________________________


^(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 2017, we paid $50.3 million for interest charges, net of interest capitalized.

^(b)

In 2014 we entered into construction and operating lease agreements to finance the construction of manufacturing and office facilities located in Houston, TX. In January 2016, construction of the facilities was completed and the operating lease commenced. Upon expiration of the lease term in September 2021, we have the option to renew the lease, purchase the facilities or re-market the facilities on behalf of the lessor, including certain guarantees of residual value under the re-marketing option.

^(c)

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


^(d)	We expect to contribute approximately $19.9 million to our international pension plans during 2018. Required contributions for future years depend on factors that cannot be determined at this time. Additionally, we expect to contribute $5.3 million to our U.S. Non-Qualified Defined Benefit Pension Plan in 2018.


^(e)	It is reasonably possible that $96.3 million of liabilities for unrecognized tax benefits will be settled during 2018, and this amount is reflected in income taxes payable in our consolidated balance sheet as of December 31, 2017. 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, 2017 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, 2017:



	Amount of Commitment Expiration per Period
(In millions) Other off-balance sheet arrangements	Total amount		Less than 1 year		1-3 years		3-5 years		After 5 years
Letters of credit and bank guarantees ^(a)	$	4,566.4	$	2,174.4	$	2,164.4	$	185.1	$	42.5
Surety bonds ^(a)	37.2		29.7		7.5		—		—
Total other off-balance sheet arrangements	$	4,603.6	$	2,204.1	$	2,171.9	$	185.1	$	42.5

______________________________

^(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.

Percentage of Completion Method of Accounting

We recognize revenue on construction-type projects using the percentage of completion method of accounting whereby revenue is recognized as work progresses on each contract. There are several acceptable methods under GAAP of measuring progress toward completion. Most frequently, we use the ratio of costs incurred to date to total estimated contract costs at completion to measure progress toward completion. We also use alternative methods including physical progress or others depending on the type of project.

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

Revenue recognized using the percentage of completion method of accounting was approximately 79.0%, 84.9% and 83.9% of total revenue recognized for the years ended December 31, 2017, 2016 and 2015, respectively. A significant portion of our total revenue recognized under the percentage of completion method of accounting 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.

Total estimated contract cost affects both the revenue recognized in a period as well as the reported profit or loss on a project. The determination of profit or loss on a contract requires consideration of contract revenue, change orders and claims, less costs incurred to date and estimated costs to complete. Profits are recognized based on the estimated project profit multiplied by the percentage complete. Adjustments to estimates of contract revenue, total contract cost, or extent of progress toward completion are often required as work progresses under the contract and as experience is gained, even though the scope of work required under the contract may not change. The nature of accounting for contracts under the percentage of completion method of accounting is such that refinements of the estimating process for changing conditions and new developments are continuous and characteristic of the process. Consequently, the amount of revenue recognized using the percentage of completion method of accounting is sensitive to changes in our estimates of total contract costs. For each contract in progress at December 31, 2017, a 1% increase or decrease in the estimated margin earned on each contract would have increased or decreased total revenue and pre-tax income by $194.6 million for the year ended December 31, 2017.

The total estimated contract cost in the percentage of completion method of accounting is a critical accounting estimate because it can materially affect revenue and profit and requires us to make judgments about matters that are uncertain. There are many factors, including, but not limited to, the ability to properly execute the engineering and design phases consistent with our customers’ expectations, the availability and costs of labor and material resources, productivity and weather, that can affect the accuracy of our cost estimates, and ultimately, our future profitability. Changes in these factors may result in revisions to costs and income, and their effects are recognized in the period in which the revisions are determined. These factors are routinely evaluated on a project by project basis throughout the project term, and the impact of corresponding revisions in management’s estimates of contract value, contract cost and contract profit are recorded as necessary in the period in which the revisions are determined.

Our operating profit for the year ended December 31, 2017 was positively impacted by approximately $378.4 million, as a result of changes in contract estimates related to projects that were in progress at December 31, 2016. During the year ended December 31, 2017, we recognized favorable changes in our estimates which had an impact on our margin in the amounts of $325 million and $53.4 million in our Onshore/Offshore and Subsea segment’s, 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, 2017, we believe that it is not more likely than not that we will generate future taxable income in certain jurisdictions in which we have cumulative net operating losses and, therefore, we have provided a valuation allowance against the related deferred tax assets.

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

We are currently evaluating provisions of United States and French tax reform enacted in December 2017. In the fourth quarter of 2017, we recorded a provision to income taxes for our preliminary assessment of the impact of tax reform. As we do not have all the necessary information to analyze all income tax effects of tax reform, this is a provisional amount which we believe represents a reasonable estimate of the accounting implications of this tax reform. We will continue to evaluate tax reform and adjust the provisional amounts as additional information is obtained. The ultimate impact of tax reform may differ from our provisional amounts due to changes in our interpretations and assumptions, as well as additional regulatory guidance that may be issued. We expect to complete our detailed analysis no later than the fourth quarter of 2018. For further information, see Note 17 to the consolidated financial statements.

Accounting for Pension and Other Post-retirement Benefit Plans

Our pension and other post-retirement (health care and life insurance) obligations are described in Note 18 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

The determination of the projected benefit obligations of our pension and other post-retirement benefit plans are important to the recorded amounts of such obligations on our consolidated balance sheet and to the amount of pension expense in our consolidated statements of income. In order to measure the obligations and expense associated with our pension benefits, management must make a variety of estimates, including discount rates used to value certain liabilities, expected return on plan assets set aside to fund these costs, rate of compensation increase, employee turnover rates, retirement rates, mortality rates and other factors. We update these estimates on an annual basis or more frequently upon the occurrence of significant events. These accounting estimates bear the risk of change due to the uncertainty and difficulty in estimating these measures. Different estimates used by management could result in our recognition of different amounts of expense over different periods of time.

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

The discount rate affects the interest cost component of net periodic pension cost and the calculation of the projected benefit obligation. The discount rate is based on rates at which the pension benefit obligation could be effectively settled on a present value basis. Discount rates are derived by identifying a theoretical settlement portfolio of long-term, high quality (“AA” rated) corporate bonds at our determination date that is sufficient to provide for the projected pension benefit payments. A single discount rate is determined that results in a discounted value of the pension benefit payments that equate to the market value of the selected bonds. The resulting discount rate is reflective of both the current interest rate environment and the pension’s distinct liability characteristics. Significant changes in the discount rate, such as those caused by changes in the yield curve, the

mix of bonds available in the market, the duration of selected bonds and the timing of expected benefit payments, may result in volatility in our pension expense and pension liabilities.

The expected long-term rate of return on plan assets is a component of net periodic pension cost. Our estimate of the expected long-term rate of return on plan assets is primarily based on the historical performance of plan assets, current market conditions, our asset allocation and long-term growth expectations. The difference between the expected return and the actual return on plan assets is amortized over the expected remaining service life of employees, resulting in a lag time between the market’s performance and its impact on plan results.

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



(In millions, except basis points)	Increase (Decrease) in 2017 Pension Expense Before Income Taxes			Increase (Decrease) in Projected Benefit Obligation at December 31, 2017
25 basis point decrease in discount rate	$	(0.1	)	$	62.9
25 basis point increase in discount rate	$	—		$	(59.0	)
25 basis point decrease in expected long-term rate of return on plan assets	$	3.1		$	—
25 basis point increase in expected long-term rate of return on plan assets	$	(3.1	)	$	—

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.

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.

Inventory Valuation

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

In order to quantify excess or obsolete inventory, we begin by preparing a candidate listing of the components of inventory that have a quantity on hand in excess of usage within the most recent two-year period. The list is reviewed with sales, engineering, production and materials management personnel to determine whether the list of potential excess or obsolete inventory items is accurate. As part of this evaluation, management considers whether there has been a change in the market for finished goods, whether there will be future demand for on-hand inventory items and whether there are components of inventory that incorporate obsolete technology. Finally, an assessment is made of our historical usage of inventory previously written off as excess or obsolete, and a further adjustment to the estimate is made based on this historical experience. As a result, our estimate of excess or obsolete inventory is sensitive to changes in assumptions about future usage of inventory. Factors that could materially impact our estimate include changes in crude oil prices and its effect on the longevity of the current industry downturn, which would impact the demand for our products and services, as well as changes in the pattern of demand for the products that we offer. We believe our inventory valuation reserve is adequate to properly value potential excess and obsolete inventory as of December 31, 2017, however, any significant changes to the factors mentioned above could lead our estimate to

change. Refer to Note 6 to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K for additional information related to inventory valuation adjustments recorded during 2017.

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).

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. The risk-adjusted discount rate applied to our future cash flows under the income approach was 10.8%. The excess of fair value over carrying amount for our reporting units ranged from approximately 15% to in excess of 200% of the respective carrying amounts.

Refer to Note 11 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 2017.

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 and have also contacted the Brazilian authorities and are cooperating with their investigation concerning the projects in Brazil.

Certain of the government investigations have identified issues relating to potential non-compliance with applicable laws and regulations, including the FCPA and Brazilian law, related to these historic matters. U.S. authorities have a broad range of civil and criminal sanctions under the FCPA and other 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 of tens or hundreds of millions of dollars, deferred prosecution agreements, guilty pleas, and other sanctions, including the requirement that the relevant corporation retain a monitor to oversee its compliance with the FCPA. Brazilian authorities also have a range of sanctions available to them and have recently imposed substantial fines on corporations for anti-corruption violations. 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, 2017 and December 31, 2016, 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, 2017, would have changed our revenue and income before income taxes attributable to TechnipFMC by approximately $903.4 million and $47.6 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 result in an additional loss of $25.6 million in the net fair value of cash flow hedges reflected in our consolidated balance sheet at December 31, 2017.

Interest Rate Risk

At December 31, 2017, we had commercial paper of approximately $1.5 billion with a weighted average interest rate of 0.56%. Using sensitivity analysis to measure the impact of a 10% adverse movement in the interest rate, or nine basis points, would result in an increase to interest expense of $20.7 million.

We assess effectiveness of forward foreign currency contracts designated as cash flow hedges based on changes in fair value attributable to changes in spot rates. We exclude the impact attributable to changes in the difference between the spot rate and the forward rate for the assessment of hedge effectiveness and recognize the change in fair value of this component immediately in earnings. Considering that the difference between the spot rate and the forward rate is proportional to the differences in the interest rates of the countries of the currencies being traded, we have exposure in the unrealized valuation of our forward foreign currency contracts to relative changes in interest rates between countries in our results of operations. To the extent any one interest rate increases by 10% across all tenors and other countries’ interest rates remain fixed, and assuming no change in discount rates, we would expect to recognize a decrease of $0.3 million in unrealized earnings in the period of change. Based on our portfolio as of December 31, 2017, 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 Shareholders of

TechnipFMC plc

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of TechnipFMC plc and its subsidiaries (“the Company”), as of December 31, 2017, and the related consolidated statement of income, comprehensive income, cash flows, and changes in stockholders’ equity for the year ended December 31, 2017, including the related notes and financial statement schedule listed in the index appearing under the Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of their operations and their cash flows for the year in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements 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 of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits 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. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

April 2, 2018

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

TechnipFMC plc

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, cash flows and changes in stockholders’ equity present fairly, in all material respects, the financial position of TechnipFMC plc and its subsidiaries as of December 31, 2016 and the results of their operations and their cash flows for each of the two years in the period 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 listed in the index appearing under the Item 15(a)(2) 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 audits. We conducted our audits 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 audits provide 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 December 31,
(In millions, except per share data)	2017			2016			2015
Revenue:
Service revenue	$	12,210.5		$	9,128.7		$	11,323.1
Product revenue	2,651.8			70.9			148.8
Lease and other revenue	194.6			—			—
Total revenue	15,056.9			9,199.6			11,471.9
Costs and expenses:
Cost of service revenue	9,984.0			7,585.7			9,863.0
Cost of product revenue	2,403.4			44.3			112.1
Cost of lease and other revenue	137.2			—			—
Selling, general and administrative expense	1,060.9			572.6			689.6
Research and development expense	212.9			105.4			95.5
Impairment, restructuring and other expense (Note 5)	191.5			343.0			438.1
Merger transaction and integration costs (Note 2)	101.8			92.6			—
Total costs and expenses	14,091.7			8,743.6			11,198.3
Other income (expense), net	(25.9		)	6.5			(102.9		)
Income from equity affiliates (Note 8)	55.6			117.7			51.0
Income before interest income, interest expense and income taxes	994.9			580.2			221.7
Interest income	140.8			85.3			77.7
Interest expense	(456.0		)	(114.1		)	(148.9		)
Income before income taxes	679.7			551.4			150.5
Provision for income taxes (Note 17)	545.5			180.3			136.5
Net income	134.2			371.1			14.0
Net (income) loss attributable to noncontrolling interests	(20.9		)	22.2			0.4
Net income attributable to TechnipFMC plc	$	113.3		$	393.3		$	14.4

Earnings per share attributable to TechnipFMC plc (Note 4):
Basic	$	0.24		$	3.29		$	0.13
Diluted	$	0.24		$	3.16		$	0.13
Weighted average shares outstanding (Note 4):
Basic	466.7			119.4			114.9
Diluted	468.3			125.1			127.3

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

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended December 31,
(In millions)	2017			2016			2015
Net income	$	134.2		$	371.1		$	14.0
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments ⁽¹⁾	(87.2		)	(71.4		)	(394.9		)
Net gains (losses) on hedging instruments:
Net gains (losses) arising during the period	53.8			(64.8		)	(70.5		)
Reclassification adjustment for net gains included in net income	101.2			120.1			67.8
Net gains (losses) on hedging instruments ⁽²⁾	155.0			55.3			(2.7		)
Pension and other post-retirement benefits:
Net gains arising during the period	43.2			7.0			18.6
Prior service cost arising during the period	—			—			0.2
Reclassification adjustment for settlement losses included in net income	(15.2		)	(7.4		)	—
Reclassification adjustment for amortization of prior service cost included in net income	0.7			0.5			0.5
Reclassification adjustment for amortization of net actuarial loss included in net income	1.8			0.7			2.6
Net pension and other post-retirement benefits ⁽³⁾	30.5			0.8			21.9
Other comprehensive income (loss), net of tax	98.3			(15.3		)	(375.7		)
Comprehensive income (loss)	232.5			355.8			(361.7		)
Comprehensive (income) loss attributable to noncontrolling interest	(21.3		)	20.9			3.0
Comprehensive income (loss) attributable to TechnipFMC plc	$	211.2		$	376.7		$	(358.7	)

______________________


⁽¹⁾	Net of income tax (expense) benefit of $(11.5), nil and nil for the years ended December 31, 2017, 2016 and 2015, respectively.


⁽²⁾	Net of income tax (expense) benefit of $(52.5), $(24.3) and $(4.7) for the years ended December 31, 2017, 2016 and 2015, respectively.


⁽³⁾	Net of income tax (expense) benefit of $(11.7), $1.0 and $(9.3) for the years ended December 31, 2017, 2016 and 2015, respectively.

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

TECHNIPFMC PLC AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

	December 31,
(In millions, except par value data)	2017			2016
Assets
Cash and cash equivalents	$	6,737.4		$	6,269.3
Trade receivables, net of allowances of $117.4 in 2017 and $85.6 in 2016	1,484.4			1,469.5
Costs and estimated earnings in excess of billings on uncompleted contracts	1,755.5			1,040.8
Inventories, net (Note 6)	987.0			334.7
Derivative financial instruments (Note 20)	78.3			47.2
Income taxes receivable	337.0			265.0
Advances paid to suppliers	391.3			711.5
Other current assets (Note 7)	1,206.2			799.2
Total current assets	12,977.1			10,937.2
Investments in equity affiliates (Note 8)	272.5			235.4
Property, plant and equipment, net (Note 10)	3,871.5			2,620.1
Goodwill (Note 11)	8,929.8			3,718.3
Intangible assets, net (Note 11)	1,333.8			173.7
Deferred income taxes (Note 17)	454.7			553.6
Derivative financial instruments (Note 20)	94.9			190.8
Other assets	329.4			250.2
Total assets	$	28,263.7		$	18,679.3
Liabilities and equity
Short-term debt and current portion of long-term debt (Note 13)	$	77.1		$	683.6
Accounts payable, trade	3,958.7			3,837.7
Billings in excess of costs and estimated earnings on uncompleted contracts	3,314.2			4,141.8
Accrued payroll	402.2			307.7
Derivative financial instruments (Note 20)	69.0			183.0
Income taxes payable	320.3			317.5
Other current liabilities (Note 12)	1,687.9			1,417.6
Total current liabilities	9,829.4			10,888.9
Long-term debt, less current portion (Note 13)	3,777.9			1,869.3
Accrued pension and other post-retirement benefits, less current portion (Note 18)	282.0			160.8
Derivative financial instruments (Note 20)	68.1			227.7
Deferred income taxes (Note 17)	419.7			130.5
Other liabilities	477.2			358.0
Commitments and contingent liabilities (Note 15)
Stockholders’ equity (Note 16):
Ordinary shares, $1.00 and €0.7625 par values in 2017 and 2016, respectively; 525.0 and 119.2 shares authorized in 2017 and 2016, respectively; 465.1 and 119.2 shares issued in 2017 and 2016, respectively; 2.1 and 3.2 shares canceled in 2017 and 2016, respectively; 465.1 and 118.9 shares outstanding in 2017 and 2016, respectively	465.1			114.7
Ordinary shares held in employee benefit trust, at cost; 0.1 shares in 2017	(4.8		)	—
Treasury stock, at cost; 0.0 shares and 0.3 shares in 2017 and 2016, respectively	—			(44.5		)
Capital in excess of par value of ordinary shares	10,483.3			2,683.1
Retained earnings	3,448.0			3,404.1
Accumulated other comprehensive loss	(1,003.7		)	(1,101.6		)
Total TechnipFMC plc stockholders’ equity	13,387.9			5,055.8
Noncontrolling interests	21.5			(11.7		)
Total equity	13,409.4			5,044.1
Total liabilities and equity	$	28,263.7		$	18,679.3

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)	2017			2016			2015
Cash provided (required) by operating activities:
Net income	$	134.2		$	371.1		$	14.0
Adjustments to reconcile net income to cash provided (required) by operating activities:
Depreciation	370.2			283.2			315.3
Amortization	244.5			17.5			23.4
Employee benefit plan and share-based compensation costs	18.7			27.4			57.2
Deferred income tax provision (benefit), net	141.6			(172.1		)	(64.1		)
Unrealized loss (gain) on derivative instruments and foreign exchange	(73.5		)	(123.2		)	(30.2		)
Impairments (Note 5)	34.3			38.2			45.2
Income from equity affiliates, net of dividends received	(37.9		)	(48.1		)	(26.3		)
Other	4.7			161.8			140.1
Changes in operating assets and liabilities, net of effects of acquisitions:
Trade receivables, net and costs in excess of billings	286.8			(268.7		)	232.7
Inventories, net	130.9			172.7			(128.3		)
Accounts payable, trade	(525.8		)	115.5			125.6
Billings in excess of costs	(1,111.4		)	(498.3		)	(408.2		)
Income taxes payable (receivable), net	(152.2		)	71.7			8.8
Other assets and liabilities, net	745.6			345.1			395.1
Cash provided (required) by operating activities	210.7			493.8			700.3
Cash provided (required) by investing activities:
Capital expenditures	(255.7		)	(312.9		)	(325.5		)
Cash acquired in merger of FMC Technologies, Inc. and Technip S.A. (Note 2)	1,479.2			—			—
Cash acquired upon consolidation of investee	—			3,480.7			—
Cash divested from deconsolidation	—			(89.1		)	—
Proceeds from sale of assets	14.4			39.2			27.1
Other	12.1			(7.4		)	(36.7		)
Cash provided (required) by investing activities	1,250.0			3,110.5			(335.1		)
Cash provided (required) by financing activities:
Net increase (decrease) in short-term debt	(106.4		)	8.6			12.0
Net increase (decrease) in commercial paper	234.9			—			48.8
Proceeds from issuance of long-term debt	25.7			644.5			31.5
Repayments of long-term debt	(888.0		)	(891.2		)	(219.1		)
Purchase of treasury stock	(58.5		)	(186.8		)	—
Dividends paid	(60.6		)	(111.5		)	(98.7		)
Payments related to taxes withheld on share-based compensation	(46.6		)	—			—
Settlements of mandatorily redeemable financial liability	(156.5		)	—			—
Other	1.2			1.8			98.3
Cash provided (required) by financing activities	(1,054.8		)	(534.6		)	(127.2		)
Effect of changes in foreign exchange rates on cash and cash equivalents	62.2			21.6			(320.6		)
Increase (decrease) in cash and cash equivalents	468.1			3,091.3			(82.6		)
Cash and cash equivalents, beginning of year	6,269.3			3,178.0			3,260.6
Cash and cash equivalents, end of year	$	6,737.4		$	6,269.3		$	3,178.0



	Year Ended December 31,
(In millions)	2017		2016		2015
Supplemental disclosures of cash flow information:
Cash paid for interest (net of interest capitalized)	$	50.3	$	40.2	$	61.0
Cash paid for income taxes (net of refunds received)	$	424.7	$	261.3	$	188.4

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 at December 31, 2014	$	110.2		$	(127.4	)	$	2,451.9		$	3,559.1		$	(711.9	)	$	14.3		$	5,296.2
Net income (loss)	—			—			—			14.4			—			(0.4		)	14.0
Other comprehensive (loss)	—			—			—			—			(373.1		)	(2.6		)	(375.7		)
Net capital transactions	4.3			—			276.1			—			—			—			280.4
Treasury shares (Note 16)	—			46.3			(39.5		)	—			—			—			6.8
Dividends (Note 16)	—			—			—			(300.1		)	—			—			(300.1		)
Share-based compensation (Note 19)	—			—			36.1			—			—			—			36.1
Other	—			—			0.8			—			—			(2.1		)	(1.3		)
Balance at 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 16)	—			36.6			(31.1		)	—			—			—			5.5
Dividends (Note 16)	—			—			—			(262.6		)	—			—			(262.6		)
Share-based compensation (Note 19)	—			—			22.0			—			—			—			22.0
Other	—			—			1.9			—			—			—			1.9
Balance at December 31, 2016	$	114.7		$	(44.5	)	$	2,683.1		$	3,404.1		$	(1,101.6	)	$	(11.7	)	$	5,044.1
Net income	—			—			—			113.3			—			20.9			134.2
Other comprehensive income	—			—			—			—			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 of treasury shares (Note 16)	(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 (Note 16)	—			—			—			(60.6		)	—			—			(60.6		)
Share-based compensation (Note 19)	—			—			44.4			—			—			—			44.4
Other				—			0.7			—			—			11.9			12.6
Balance at December 31, 2017	$	465.1		$	(4.8	)	$	10,483.3		$	3,448.0		$	(1,003.7	)	$	21.5		$	13,409.4

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.

In this Annual Report on Form 10-K, we are reporting the results of our operations for the year ended December 31, 2017, 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 years ended December 31, 2016 and December 31, 2015 and as of 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; estimate 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 can 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 historical cost, less any accumulated impairment losses.

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

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

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

Progress billings are generally issued upon completion of certain phases of the work as stipulated in the contract. Revenue in excess of progress billings are reported in costs and estimated earnings in excess of billings on uncompleted contracts in our consolidated balance sheets. Progress billings and cash collections in excess of revenue recognized on a contract are classified as billings in excess of costs and estimated earnings on uncompleted contracts and advance payments, respectively, in our consolidated balance sheets.

Our operating profit for the year ended December 31, 2017 was positively impacted by approximately $378.4 million, as a result of changes in contract estimates related to projects that were in progress at December 31, 2016. During the year ended December 31, 2017, we recognized favorable changes in our estimates which had an impact on our margin in the amounts of $325.0 million and $53.4 million in our Onshore/Offshore and Subsea segment’s, respectively. The changes in contract estimates are attributed to better than expected performance throughout our execution of our projects.

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.

Debt instruments—Debt instruments include convertible and 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.

Treasury shares—Treasury shares held are recorded as a reduction to stockholders’ equity using the cost method. Any gain or loss related to the sale of treasury shares is included in stockholders’ equity. Canceled treasury shares are accounted for using the constructive retirement method. For shares repurchased in excess of par, we allocate the value to capital in excess of par value of ordinary shares and retained earnings, if any, using the weighted average method to identify the net original issue proceeds to the cost of the shares repurchased.

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 hyperinflationary 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 exchanges 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.

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. MERGER OF FMC TECHNOLOGIES AND TECHNIP

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 $101.8 million and $92.6 million during the years ended December 31, 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 ⁽¹⁾	0.5
Shares of TechnipFMC issued	114.4
Value per share of Technip as of January 16, 2017 ⁽²⁾	$	71.4
Total purchase consideration	$	8,170.7

_______________________

⁽¹⁾

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.


⁽²⁾	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	199.7
Other long-term liabilities	138.7
Total liabilities assumed	3,754.0
Net identifiable assets acquired	3,009.7
Goodwill	5,161.0
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	997.8
Total	$	5,161.0

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.

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)	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

NOTE 3. NEW ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

Effective January 1, 2017, we adopted Accounting Standards Update (“ASU”) No. 2016-09, “Improvements to Employee Share-Based Payment Accounting.” Among other amendments, this update requires that excess tax benefits or deficiencies be recognized as income tax expense or benefit in the income statement and eliminates the requirement to reclassify excess tax benefits and deficiencies from operating activities to financing activities in the statement of cash flows. This updated guidance also gives an entity the election to either (i) estimate the forfeiture rate of employee stock-based awards or (ii) account for forfeitures as they occur. We elected to retrospectively classify excess tax benefits and deficiencies as operating activity and these amounts, which were immaterial for all periods presented, are reflected in the income taxes payable, net line item in the accompanying consolidated statement of cash flows. In addition, we elected to continue to estimate forfeitures on the grant date to account for the estimated number of awards for which the requisite service period will not be rendered. The adoption of this update did not have a material impact on our consolidated financial statements.

Effective January 1, 2017, we adopted ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This update requires in scope inventory to be measured at the lower of cost or net realizable value rather than at the lower of cost or market under existing guidance. We adopted the updated guidance prospectively. The adoption of this update did not have a material impact on our consolidated financial statements.

Effective January 1, 2017, we adopted ASU No. 2014-15, “Disclosure of Uncertainties About an Entity’s Ability to Continue as a Going Concern.” This update states that substantial doubt exists if it is probable that an entity will be unable to meet its current and future obligations. Disclosures are required if conditions give rise to substantial doubt. However, management will need to assess if its plans will alleviate substantial doubt to determine the specific disclosures. The Company adopted this

standard in 2017 and management does not believe there is substantial doubt about the entity's ability to continue as a going concern.

Effective September 30, 2017, we early adopted ASU No. 2017-04, “Simplifying the Test for Goodwill Impairment.” This update eliminates step two from the goodwill impairment test. An annual or interim goodwill test should be performed by comparing the fair value of a reporting unit with its carrying amount. Income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit should also be considered when measuring any applicable goodwill impairment loss. This updated guidance also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and if it fails that qualitative assessment, to perform step two of the goodwill impairment test. Any goodwill amount allocated to a reporting unit with a zero or negative carrying amount net of assets is required to be disclosed. The adoption of this update did not have a material impact on our consolidated financial statements.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued 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. The ASU will supersede most existing GAAP related to revenue recognition and will supersede some cost guidance in existing GAAP related to construction-type and production-type contract accounting. Additionally, the ASU will significantly increase disclosures related to revenue recognition. In August 2015, the FASB issued ASU No. 2015-14 which deferred the effective date of ASU No. 2014-09 by one year, and as a result, is now effective for us on January 1, 2018.

In March 2016, the 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. Early application is permitted to the original effective date of January 1, 2017. Entities are permitted to apply the amendments either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application.

The new standard requires companies to identify contractual performance obligations and determine whether revenue should be recognized at a point in time or over time based on when control of goods and services transfer to a customer. As a result, we expect changes in the presentation of our financial statements, including: (1) timing of revenue recognition, and (2) changes in classification between revenue and costs.

We have performed a detailed review of our contract portfolio representative of our different businesses and compared historical accounting policies and practices to the new standard. Over the course of 2017, we have formed an implementation work team, conducted training for the relevant staff regarding a detailed overview of the key changes within the new standard.

We have engaged external resources to assist us in our efforts of establishing new policies, procedures, and controls, establishing appropriate presentation and disclosure changes. We adopted new revenue recognition guidance using the modified retrospective transition method effective for the quarter ending March 31, 2018, applying the guidance to contracts with customers that were not substantially complete as of January 1, 2018. Our financial results for reporting periods after January 1, 2018 will be presented under the new guidance, while financial results for prior periods will continue to be reported in accordance with the prior guidance and our historical accounting policy. We have evaluated the impact of the new guidance on a substantial portion our contracts with customers, including identification of differences that will result from the new requirements. Based on the analysis performed to date, we do not anticipate any significant changes in our revenue recognition and do not believe that the guidance surrounding identification of contracts and performance obligations or measurement of variable consideration will have a material impact on the revenue recognition for these arrangements. We expect our disclosures related to revenue recognition will expand to address new quantitative and qualitative requirements regarding the nature, amount and timing of revenue from contracts with customers and additional information related to contract assets and liabilities.

In January 2016, the FASB issued 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. The amendments in this ASU are effective for us on January 1, 2018. 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. Early adoption is not permitted. We are currently evaluating the impact of this ASU on our consolidated financial statements.

On February 28, 2018 the FASB issued ASU 2018-03, “Technical Corrections and Improvements to Financial Instruments-Overall(Subtopic825-10):Recognition and Measurement of Financial Assets and Financial Liabilities, that clarifies the guidance in ASU No. 2016-01, Financial Instruments-Overall (Subtopic 825-10).” These amendments clarify the guidance in ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10), on the following issues (among other things): Equity Securities without a Readily Determinable Fair Value-Discontinuation; Equity Securities without a Readily Determinable Fair Value- Adjustments; Forward Contracts and Purchase Options; Presentation Requirements for Certain Fair Value Option Liabilities; Fair Value Option Liabilities Denominated in a Foreign Currency; Transition Guidance for Equity Securities without a Readily Determinable Fair Value. The amendments in this ASU are effective for us January 1, 2018 in conjunction with the adoption of ASU 2016-01. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, “Leases.” This update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. 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. The impacts that adoption of the ASU is expected to have on our consolidated financial statements and related disclosures are being evaluated. Additionally, we have not determined the effect of the ASU on our internal control over financial reporting or other changes in business practices and processes.

In June 2016, the FASB issued ASU 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 permitted. We are currently evaluating the impact of this ASU on our consolidated financial statements.

In August 2016, the FASB issued 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 effective for us on January 1, 2018 and 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. Early adoption is permitted. This ASU is not expected to have a material impact on our consolidated financial statements.

In October 2016, the FASB issued 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 effective for us on January 1, 2018 and are required to be adopted on a modified retrospective basis. Early adoption is permitted. This ASU is not expected to have a material impact on our consolidated financial statements.

In January 2017, the FASB issued 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 effective for us on January 1, 2018 and are required to be adopted prospectively. Early adoption is permitted. This ASU is not expected to have a material impact on our consolidated financial statements.

In February 2017, the FASB issued ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.” This update defines an in-substance nonfinancial asset, unifies guidance related to partial sales of nonfinancial assets, eliminates rules specifically addressing the sale of real estate, removes exceptions to the financial asset derecognition model, and clarifies the accounting for contributions of nonfinancial assets to joint ventures. The amendments in this ASU are effective for us January 1, 2018 and are required to be adopted with either a full retrospective approach or a modified retrospective approach. This ASU is not expected to have a material impact on our consolidated financial statements.

In March 2017, the FASB issued 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. Early adoption is permitted. 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. We will adopt this ASU on January 1, 2018. This ASU is not expected to have a material impact on our consolidated financial statements.

In May 2017, the FASB issued 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. We will adopt this ASU on January 1, 2018. This ASU is not expected to have a material impact 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.

On February 14, 2018 the FASB issued ASU 2018-02, “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (AOCI).” These amendments provide 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. We are currently evaluating the impact of this ASU on our consolidated financial statements.

NOTE 4. EARNINGS PER SHARE

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



	Year Ended December 31,
(In millions, except per share data)	2017		2016		2015
Net income attributable to TechnipFMC plc	$	113.3	$	393.3	$	14.4
After-tax interest expense related to dilutive shares	—		1.5		2.5
Net income attributable to TechnipFMC plc adjusted for dilutive effects	113.3		394.8		16.9
Weighted average number of shares outstanding	466.7		119.4		114.9
Dilutive effect of restricted stock units	0.2		—		—
Dilutive effect of stock options	—		—		—
Dilutive effect of performance shares	1.4		0.5		0.6
Dilutive effect of convertible bonds	—		5.2		11.8
Total shares and dilutive securities	468.3		125.1		127.3

Basic earnings per share attributable to TechnipFMC plc	$	0.24	$	3.29	$	0.13
Diluted earnings per share attributable to TechnipFMC plc	$	0.24	$	3.16	$	0.13

NOTE 5. IMPAIRMENT, RESTRUCTURING AND OTHER EXPENSE

Impairment, restructuring and other expense were as follows:



	Year Ended December 31,
(In millions)	2017		2016		2015
Impairment expense:
Subsea	$	11.5	$	23.0	$	42.9
Onshore/Offshore	—		14.6		—
Surface Technologies	10.2		—		—
Corporate and other	12.6		0.6		2.3
Total impairment expense	34.3		38.2		45.2
Restructuring and other expense:
Subsea	$	88.4	$	58.7	$	34.0
Onshore/Offshore	27.0		214.4		342.2
Surface Technologies	9.0		—		—
Corporate and other	32.8		31.7		16.7
Total restructuring and other expense	157.2		304.8		392.9
Total impairment, restructuring and other expense	$	191.5	$	343.0	$	438.1

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.

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

During 2016 and 2015, our impairment expense was primarily associated with the restructuring plan discussed below.

Restructuring and other—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.

Additionally, during 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.

NOTE 6. INVENTORIES

Inventories consisted of the following:



	December 31,
(In millions)	2017		2016
Raw materials	$	271.4	$	240.4
Work in process	130.2		36.0
Finished goods	585.4		58.3
Inventory, net	$	987.0	$	334.7

All amounts in the table above are reported net of obsolescence reserves of $70.8 million and $38.8 million at December 31, 2017 and 2016, respectively.

Net inventories accounted for under the LIFO method totaled $300.9 million at December 31, 2017. There were no net inventories accounted for under the LIFO method at December 31, 2016. The current replacement costs of LIFO inventories exceeded their recorded values by $0.6 million at December 31, 2017. There was no reduction to the base LIFO inventory in 2017.

NOTE 7. OTHER CURRENT ASSETS

Other current assets consisted of the following:



	December 31,
(In millions)	2017		2016
Value-added tax receivables	$	532.5	$	319.4
Other tax receivables	155.8		124.9
Prepaid expenses	136.2		106.4
Held-to-maturity investments (short-term)	60.0		—
Assets held for sale	50.2		2.2
Available-for-sale securities (short-term)	9.9		—
Other	261.6		246.3
Other current assets	$	1,206.2	$	799.2

NOTE 8. 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 2017, 2016, or 2015.

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



	December 31, 2017
	Percentage Owned		Carrying Value
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 (loss) from equity affiliates included in each of our reporting segments was as follows:



	Year Ended December 31,
(In millions)	2017		2016		2015
Subsea	$	55.3	$	35.0	$	21.2
Onshore/Offshore	0.3		82.7		29.8
Surface Technologies	—		—		—
Income from equity affiliates	$	55.6	$	117.7	$	51.0

Summarized financial information⁽²⁾—Summarized financial information for our equity method investments is presented below for 2016 and 2015. Our major equity method investments are as follows:

Technip Odebrecht. Technip Odebrecht PLSV CV (“Technip Odebrecht”) is an affiliated company in the form of a joint venture between Technip SA and Odebrecht Oleo & Gas. 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. 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. We are not the primarily 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. 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.

FSTP Brasil. FSTP Brasil Ltda. (“FSTP Brasil”) is an affiliated company in the form of a joint venture between Technip Brasil - Engenharia, Instalações e Apoio Marítimo Ltda. and Keppel FELS Brasil S.A. FSTP Brasil was formed in 2003 to operate in the engineering, construction, manufacture and repair of offshore platforms and vessels segments, especially for oil and natural gas companies. We have accounted for our 25% investment using the equity method of accounting with results reported in our Subsea segment.

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 ⁽¹⁾			2015
As of December 31
Current assets	$	619.2		$	4,769.3
Noncurrent assets	2,176.1			1,587.2
Current liabilities	796.9			4,853.7
Noncurrent liabilities	1,355.0			925.6
Year ended December 31
Revenues	$	6,782.9		$	5,426.1
Gross profit	461.0			721.8
Net income (loss)	(348.4		)	561.1

⁽¹⁾ 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.

⁽²⁾As of December 31, 2017, our equity method investments were no longer significant individually or in the aggregate. As such, summarized financial information for 2017 is not presented.

NOTE 9. 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:



	December 31,
(In millions)	2017			2016
Trade receivables	$	98.4		$	220.2
Trade payables	(121.8		)	(200.0		)
Net trade receivables/(payables)	$	(23.4	)	$	20.2

Note receivables	$	140.9		$	153.9

A member of our Board of Directors serves on the board of directors of Anadarko and the table above includes trade receivable balances of $22.3 million from Anadarko at December 31, 2017 as well as $42.5 million from TP JGC Coral France SNC and $13.8 million from Technip Odebrecht PLSV CV, as both companies are equity method affiliates. The trade receivables balance at December 31, 2016 includes $98.8 million and $25.8 million from Dofcon Brasil AS and Technip Odebrecht PLSV CV, respectively, both are equity method affiliates.

The balance in trade payables includes $52.4 million to JGC Corporation and $48.3 million to Chiyoda, both JV partners on our Yamal project, at December 31, 2017. The trade payables balance at December 31, 2016 includes $50.3 million and $64.3 million to JGC Corporation and Chiyoda, respectively, and $46.0 million to Heerema, a joint venture partner of one of our consolidated subsidiaries.

The note receivables balance includes $114.9 million and $104.2 million with Dofcon Brasil AS at December 31, 2017 and 2016, 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.



	Year Ended December 31,
(In millions)	2017			2016			2015
Revenue	$	238.1		$	284.5		$	413.5
Expenses	$	(141.4	)	$	(105.5	)	$	(53.4	)

Revenue in the table above includes $111.3 million from Anadarko and $69.9 million from TP JGC Coral France SNC, an equity method affiliate, during the year ended December 31, 2017. Revenue for the years ended December 31, 2016 and 2015 included $196.7 million and $272.4 million, respectively, from Yamgaz, which was an equity method affiliate during that time.

Expense activity for the year ended December 31, 2017 includes $46.8 million to JGC Corporation and $44.1 million to Chiyoda. Expense activity for the year ended December 31, 2016 includes $71.3 million to Heerema. For the year ended December 31, 2015, there was no expense activity with an individually significant related party.

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	December 31,
(In millions)	2017			2016
Land and land improvements	$	105.2		$	17.3
Buildings	691.2			337.5
Vessels	2,246.0			1,921.7
Machinery and equipment	1,892.2			1,056.6
Office fixtures and furniture	350.4			292.0
Construction in process	136.7			310.5
Other	397.7			376.3
	5,819.4			4,311.9
Accumulated depreciation	(1,947.9		)	(1,691.8		)
Property, plant and equipment, net	$	3,871.5		$	2,620.1

Depreciation expense was $370.2 million, $283.2 million and $315.3 million in 2017, 2016 and 2015, respectively. The amount of interest cost capitalized was not material for the years presented.

NOTE 11. 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 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. The risk-adjusted discount rate applied to our future cash flows was 10.8%. The excess of fair value over carrying amount for our reporting units ranged from approximately 15% to in excess of 200% of the respective carrying amounts.

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



(In millions)	Subsea			Onshore/Offshore			Surface Technologies		Total
December 31, 2014	$	3,232.0		$	882.2		$	—	$	4,114.2
Additions due to business combinations	41.9			—			—		41.9
Impairment	—			—			—		—
Translation	(296.5		)	(73.1		)	—		(369.6		)
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

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



	December 31,
	2017				2016
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Acquired technology	$	240.0	$	25.0	$	—	$	—
Backlog	175.0		118.0		—		—
Customer relationships	285.0		29.0		—		—
Licenses, patents and trademarks	810.1		157.7		167.3		120.9
Software	237.9		145.5		154.7		107.4
Other	72.7		11.7		97.6		17.6
Total intangible assets	$	1,820.7	$	486.9	$	419.6	$	245.9

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 $244.5 million, $17.5 million and $23.4 million in amortization expense related to intangible assets during the years ended December 31, 2017, 2016 and 2015, respectively. During the years 2018 through 2022, annual amortization expense is expected to be as follows: $173.5 million in 2018, $124.1 million in 2019, $114.8 million in 2020, $109.1 million in 2021, $106.6 million in 2022 and $705.7 million thereafter.

NOTE 12. OTHER CURRENT LIABILITIES

Other current liabilities consisted of the following:



(In millions)	December 31, 2017		December 31, 2016
Warranty accruals on completed contracts	$	321.3	$	271.9
Contingencies related to completed contracts	214.9		370.1
Other taxes payable	204.4		143.5
Social security liability	145.0		66.3
Compensation accrual	123.5		27.5
Redeemable financial liability	69.7		33.7
Liabilities held for sale	13.7		—
Other accrued liabilities	595.4		504.6
Total other current liabilities	$	1,687.9	$	1,417.6

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)	2017		2016
Convertible bonds due 2017	$	—	$	524.5
Bank borrowings	48.9		138.8
Other	28.2		20.3
Total short-term debt and current portion of long-term debt	$	77.1	$	683.6

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



	December 31,
(In millions)	2017			2016
Revolving credit facility	$	—		$	—
Bilateral credit facilities	—			—
Commercial paper ⁽¹⁾	1,450.4			210.8
Synthetic bonds due 2021	502.4			431.8
Convertible bonds due 2017	—			524.5
3.45% Senior Notes due 2022	500.0			—
5.00% Notes due 2020	239.9			210.8
3.40% Notes due 2022	179.9			158.1
3.15% Notes due 2023	155.9			137.0
3.15% Notes due 2023	149.9			131.8
4.00% Notes due 2027	89.9			79.1
4.00% Notes due 2032	119.9			105.4
3.75% Notes due 2033	119.9			105.4
Bank borrowings	332.5			452.1
Other	28.2			20.3
Unamortized debt issuance costs and discounts	(13.8		)	(14.2		)
Total debt	3,855.0			2,552.9
Less: current borrowings	(77.1		)	(683.6		)
Long-term debt	$	3,777.9		$	1,869.3

_______________________


⁽¹⁾	At December 31, 2017 and 2016, 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, 2017, 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	$	3,855.0	$	77.1	$	1,972.9	$	1,179.0	$	626.0

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. and Technip Eurocash SNC (the “Borrowers”) with JPMorgan Chase Bank, National Association, 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. The facility expires in January 2022.

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%.

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, make certain investments.

Bilateral credit facilities—We have access to four bilateral credit facilities in the aggregate of €340.0 million. The bilateral credit facilities consist of:


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


•	a credit facility of €80.0 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, 2017 and December 31, 2016. Commercial paper borrowings are issued at market interest rates. As of December 31, 2017, our commercial paper borrowings had a weighted average interest rate of 1.78% on the U.S. dollar denominated borrowings and (0.27)% 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 3,464.6193 and a conversion price of €28.8632. 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.

Convertible bonds—On December 15, 2011, we issued 5,178,455 bonds convertible (the “2011-2017 Convertible Bonds”) into and/or exchangeable for new or existing shares (“OCEANE”) for approximately €497.6 million with a maturity date of January 1, 2017. Net proceeds from the issuance were used to partially restore our cash balance position following the acquisition of Global Industries, Ltd. in December 2011 for a cash consideration of $936.4 million.

At maturity, all outstanding amounts under the 2011-2017 Convertible Bonds were repaid.

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.

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.

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.

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, 2017 reflect the consolidated results of operations related to these entities. Refer to Note 8 for further information regarding the acquisition and consolidation 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, for which $33.7 million was recorded as other current liabilities. During the year ended December 31, 2017 we revalued the liability to reflect current expectations about the obligation which resulted in the recognition of a loss of $293.7 million for the year ended December 31, 2017. Changes in the fair value of the financial liability are recorded as interest expense on the consolidated statements of income. Refer to Note 12 for further information regarding our other current liabilities. Refer to Note 21 for further information regarding the fair value measurement assumptions of the mandatorily redeemable financial liability and related changes in its fair value.

NOTE 15. 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 $369.2 million, $313.5 million and $381.6 million in 2017, 2016 and 2015, 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, 2017, future minimum rental payments under noncancellable operating leases were:



(In millions)
2018	$	347.2
2019	290.2
2020	266.2
2021	178.2
2022	124.7
Thereafter	577.1
Total	1,783.6
Less income from sub-leases	6.3
Net minimum operating lease payments	$	1,777.3

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, 2017
Financial guarantees ⁽¹⁾	$	933.3
Performance guarantees ⁽²⁾	3,670.3
Maximum potential undiscounted payments	$	4,603.6

_______________________


⁽¹⁾	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.


⁽²⁾	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.

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, 2017 and 2016, and that the ultimate resolution of such matters will not materially affect our consolidated financial position, results of operations, or cash flows.

NOTE 16. STOCKHOLDERS’ EQUITY

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.

Dividends declared and paid during the year ended December 31, 2015 based on the results of the year ended December 31, 2014 were €225.8 million. The dividends were paid in cash and shares in the amount of €88.9 million and €136.9 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). As of December 31, 2017 we had distributable reserves in excess of $10.1 billion.

The following is a summary of our capital stock activity for the years ended December 31, 2017, 2016 and 2015:



(Number of shares in millions)	Ordinary Shares Issued		Ordinary Shares Held in Employee Benefit Trust	Treasury Stock
December 31, 2014	113.9		—	1.4
Stock awards	0.6		—	(0.5	)
Treasury stock purchases	—		—	—
Capital increase reserved for employees	1.9		—	—
Shares acquired pursuant to liquidity contract	—		—	1.3
Shares sold pursuant to liquidity contract	—		—	(1.4	)
Dividend payment in shares	2.6		—	—
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 cancellations	(2.1	)	—	(2.1	)
Net stock purchased for employee benefit trust	—		0.1	—
December 31, 2017	465.1		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 FMC Technologies.

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. We repurchased $58.5 million of ordinary shares during the year ended December 31, 2017, under our authorized share repurchase program. We intend to cancel repurchased shares and not hold them in treasury. Canceled treasury shares are accounted for using the constructive retirement method.

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, 2015	$	(855.3	)	$	(181.5	)	$	(48.2	)	$	(1,085.0	)	$	(1.1	)
Other comprehensive income (loss) before reclassifications, net of tax	(71.8		)	(65.7		)	7.0			(130.5		)	1.3
Reclassification adjustment for net (gains) losses included in net income, net of tax	—			120.1			(6.2		)	113.9			—
Other comprehensive income (loss), net of tax	(71.8		)	54.4			0.8			(16.6		)	1.3
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

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, 2017			December 31, 2016			December 31, 2015
Details about Accumulated Other Comprehensive Loss Components	Amount Reclassified out of Accumulated Other Comprehensive Loss									Affected Line Item in the Consolidated Statement of Income
Gains (losses) on hedging instruments
Foreign exchange contracts:	$	(39.3	)	$	—		$	—		Revenue
	5.3			—			—			Costs of sales
	0.8			—			—			Selling, general and administrative expense
	(102.2		)	(165.7		)	(93.6		)	Other (expense), net
	(135.4		)	(165.7		)	(93.6		)	Income before income taxes
	(34.2		)	(45.6		)	(25.8		)	Provision (benefit) for income taxes
	$	(101.2	)	$	(120.1	)	$	(67.8	)	Net income

Defined pension and other post-retirement benefits
Settlements and curtailments	$	25.3		$	10.7		$	—		^(a)
Amortization of actuarial gain (loss)	(2.5		)	(1.0		)	(3.7		)	^(a)
Amortization of prior service credit (cost)	(1.0		)	(0.7		)	(0.7		)	^(a)
	21.8			9.0			(4.4		)	Income before income taxes
	9.1			2.8			(1.3		)	Provision (benefit) for income taxes
	$	12.7		$	6.2		$	(3.1	)	Net income

_______________________


^(a)	These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 18 for additional details).

NOTE 17. 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)	2017		2016		2015
United States	$	284.3	$	154.3	$	152.0
Outside United States	395.4		397.1		(1.5		)
Income before income taxes	$	679.7	$	551.4	$	150.5

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



	Year Ended December 31,
(In millions)	2017		2016			2015
Current:
United States	$	30.2	$	54.1		$	10.8
Outside United States	373.7		298.3			189.8
Total current	403.9		352.4			200.6
Deferred:
United States	71.4		(7.2		)	46.6
Outside United States	70.2		(164.9		)	(110.7		)
Total deferred	141.6		(172.1		)	(64.1		)
Provision for income taxes	$	545.5	$	180.3		$	136.5

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



	December 31,
(In millions)	2017			2016
Deferred tax assets attributable to:
Accrued expenses	$	155.2		$	49.3
Non-deductible interest	85.9			—
Foreign tax credit carryforwards	34.9			—
Net operating loss carryforwards	390.7			225.9
Inventories	13.4			—
Research and development credit	7.5			—
Provisions for pensions and other long-term employee benefits	86.4			56.2
Contingencies related to contracts	111.3			188.3
Other contingencies	33.5			63.1
Fair value losses/gains	12.4			103.1
Other	11.1			15.1
Deferred tax assets	942.3			701.0
Valuation allowance	(430.0		)	(172.7		)
Deferred tax assets, net of valuation allowance	512.3			528.3
Deferred tax liabilities attributable to:
Revenue in excess of billings on contracts accounted for under the percentage of completion method	41.2			—
U.S. tax on foreign subsidiaries’ undistributed earnings not indefinitely reinvested	4.9			—
Foreign exchange	21.5			—
Property, plant and equipment, intangibles and other assets	403.3			101.1
Margin recognition on construction contracts	6.4			4.1
Deferred tax liabilities	477.3			105.2
Net deferred tax assets	$	35.0		$	423.1

At December 31, 2017 and 2016, 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, 2017, deferred tax assets include tax benefits of related to certain intercompany interest costs which are not currently deductible, but which may be deductible in future periods. If not utilized, these costs will become permanently nondeductible beginning in 2025. Management believes that it is more likely than not that we will not be able to deduct these costs before expiration of the carry forward period; therefore, we have established a valuation allowance against the related deferred tax assets.

Foreign tax credit carryforwards. At December 31, 2017, deferred tax assets included U.S. foreign tax credit carryforwards of $34.9 million, which, if not utilized, will begin to expire in 2024. 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 $1.4 billion in 2017 and nil in both 2016 and 2015.

Net operating loss carryforwards. As of December 31, 2017, 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 2018. Management believes it is more likely than not that we will not be able to utilize certain of these operating loss carryforwards before expiration; therefore, we have established a valuation allowance against the related deferred tax assets.

The majority of the net operating loss carryforwards came from a Brazil entity for $315.6 million, a Saudi Arabia entity for $196.8 million, a Mexico entity for $127.0 million, a France entity for $93.2 million, a U.K. entity for $121.0 million, and a Finland entity for $57.7 million. Except where there is a statutory carryforward loss time limit (i.e. Finland 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 and associated interest and penalties⁽¹⁾:



(In millions)	Federal, State and Foreign Tax			Accrued Interest and Penalties		Total Gross Unrecognized Income Tax Benefits
Balance at December 31, 2015	$	—		$	—	$	—
Additions for tax positions related to prior years	—			—		—
Additions for tax positions related to current year	16.6			—		16.6
Reductions for tax positions due to settlements	—			—		—
Balance at December 31, 2016	$	16.6		$	—	$	16.6
Reductions for tax positions related to prior years	(13.6		)	—		(13.6		)
Additions for tax positions related to current year	39.5			3.8		43.3
Reductions for tax positions due to settlements	(0.2		)	—		(0.2		)
Additions for tax positions related to purchase accounting	48.1			2.1		50.2
Balance at December 31, 2017	$	90.4		$	5.9	$	96.3

⁽¹⁾We did not have any unrecognized tax benefits prior to 2016.

At December 31, 2017, 2016 and 2015, there were $96.3 million, $16.6 million and nil, respectively, of unrecognized tax benefits that if recognized would affect the annual effective tax rate.

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

Included in additions for tax positions related to purchase accounting is $45.2 million for potential adjustments for intercompany interest expense pertaining to a financing structure in Norway.

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: 2006 for Norway, 2013 for Nigeria, 2012 for Brazil and 2014 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 19.3% 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. The Merger transaction was generally a non-taxable event for the significant jurisdictions in which we operate. As of the date of the Merger, the Company recorded $306.3 million of deferred tax liability related to purchase accounting.

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,
	2017		2016		2015
Statutory income tax rate	19.3	%	34.4	%	38.0	%
Net difference resulting from:
Foreign earnings subject to different tax rates	18.2	%	(18.5	)%	28.4	%
Net change in unrecognized tax benefits	4.3	%	3.0	%	—	%
Adjustments on prior year taxes	(4.4	)%	2.4	%	(11.0	)%
Change in valuation allowance	19.3	%	13.1	%	36.9	%
Deferred tax asset/liability revaluation for tax rate change	1.4	%	(0.8	)%	1.8	%
U.S. transition tax	17.1	%	—	%	—	%
Other	5.1	%	(0.9	)%	(3.5	)%
Effective income tax rate	80.3	%	32.7	%	90.6	%

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 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 $2.9 billion 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.

As of January 17, 2017, the Company had recorded a deferred tax asset of $77.7 million related to the carryforward of U.S.foreign tax credits. This deferred tax asset was offset by a valuation allowance of $77.7 million, resulting in a net carrying value of the deferred tax asset related to the carryforward of U.S. foreign tax credits of zero as of January 17, 2017. The deemed repatriation allowed for the utilization of $32.1 million of these foreign tax credit carryforwards. Accordingly, the Company recorded a tax benefit of $32.1 million in the fourth quarter of 2017 related to the utilization of these tax assets. As of December 31, 2017, the Company has recorded a deferred tax asset of $34.9 million related to the carryforward of U.S. foreign tax credits. This deferred tax asset is offset by a valuation allowance of $34.9 million, resulting in a net carrying value of the deferred tax asset associated with the carryforward of the U.S. foreign tax credits of zero as of December 31, 2017.

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.

We are currently evaluating provisions of United States tax reform enacted in December 2017. In the fourth quarter of 2017, we recorded a provision to income taxes for our preliminary assessment of the impact of tax reform. As we do not have all the necessary information to analyze all income tax effects of tax reform, this is a provisional amount which we believe represents a reasonable estimate of the accounting implications of this tax reform. We will continue to evaluate tax reform and adjust the provisional amounts as additional information is obtained. The ultimate impact of tax reform may differ from our provisional amounts due to changes in our interpretations and assumptions, as well as additional regulatory guidance that may be issued. We expect to complete our detailed analysis no later than the fourth quarter of 2018.

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 would still be 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, 2017, these tax holidays reduced our provision for income taxes by $4.4 million, or $0.01 per share on a diluted basis.

NOTE 18. 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.

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

The funded status of our U.S. Pension Plans, certain foreign pension plans and U.S. post-retirement health care and life insurance benefit plans, together with the associated balances recognized in our consolidated balance sheets as of December 31, 2017 and 2016, were as follows:



	Pensions											Other Post-retirement Benefits
	2017						2016					2017			2016
(In millions)	U.S.			Int’l			U.S.		Int’l
Accumulated benefit obligation	$	659.8		$	769.9		$	—	$	360.9
Projected benefit obligation at January 1	$	—		$	399.6		$	—	$	457.2		$	0.9		$	0.9
Service cost	10.3			21.0			—		11.7			—			—
Interest cost	26.7			19.6			—		10.9			0.3			—
Actuarial (gain) loss	56.2			(13.5		)	—		39.3			0.8			—
Amendments	0.2			—			—		—			—			—
Curtailments	(67.9		)	(2.8		)	—		(8.2		)	—			—
Settlements	—			(13.5		)	—		—			—			—
Foreign currency exchange rate changes	—			68.9			—		(31.1		)	—			—
Plan participants’ contributions	—			1.4			—		0.1			—			—
Benefits paid	(27.5		)	(27.6		)	—		(24.0		)	(0.6		)	—
Acquisition/Business Combination/Divestiture	661.9			432.3			—		(52.2		)	7.7			—
Other	(0.1		)	12.7			—		(4.1		)	0.9			—
Projected benefit obligation at December 31	659.8			898.1			—		399.6			10.0			0.9
Fair value of plan assets at January 1	—			229.7			—		236.0			—			—
Actual return on plan assets	60.4			63.3			—		29.0			—			—
Company contributions	—			19.1			—		0.4			—			—
Foreign currency exchange rate changes	—			50.4			—		(26.1		)	—			—
Settlements	—			(7.0		)	—		—			—			—
Plan participants’ contributions	—			1.4			—		0.1			—			—
Benefits paid	(24.8		)	(21.5		)	—		(9.7		)	—			—
Acquisition/Business Combination/Divestiture	540.8			361.4			—		—			—			—
Other	—			2.4			—		—			—			—
Fair value of plan assets at December 31	576.4			699.2			—		229.7			—			—
Funded status of the plans (liability) at December 31	$	(83.4	)	$	(198.9	)	$	—	$	(169.9	)	$	(10.0	)	$	(0.9	)



	Pensions											Other Post-retirement Benefits
	2017						2016					2017			2016
(In millions)	U.S.			Int’l			U.S.		Int’l
Other assets	$	—		$	—		$	—	$	—		$	—		$	—
Current portion of accrued pension and other post-retirement benefits	$	(5.4	)	$	(4.1	)	$	—	$	(10.0	)	$	(0.7	)	$	—
Accrued pension and other post-retirement benefits, net of current portion	(78.0		)	(194.8		)	—		(159.9		)	(9.3		)	(0.9		)
Funded status recognized in the consolidated balance sheets at December 31	$	(83.4	)	$	(198.9	)	$	—	$	(169.9	)	$	(10.0	)	$	(0.9	)

The following table summarizes the pre-tax amounts in accumulated other comprehensive (income) loss at December 31, 2017 and 2016 that have not been recognized as components of net periodic benefit cost:



	Pensions								Other Post-retirement Benefits
	2017				2016				2017		2016
(In millions)	U.S.		Int’l		U.S.		Int’l
Pre-tax amounts recognized in accumulated other comprehensive (income) loss:
Unrecognized actuarial (gain) loss	$	0.1	$	21.2	$	—	$	63.7	$	0.8	$	0.1
Unrecognized prior service (credit) cost	0.2		5.5		—		5.7		—		—
Unrecognized transition asset	—		—		—		—		—		—
Accumulated other comprehensive (income) loss at December 31	$	0.3	$	26.7	$	—	$	69.4	$	0.8	$	0.1

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, 2017 and 2016:



	Pensions								Other Post-retirement Benefits
	2017				2016				2017		2016
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded projected benefit obligation:
Aggregate projected benefit obligation	$	659.8	$	744.3	$	—	$	399.6	$	9.9	$	0.8
Aggregate fair value of plan assets	$	576.4	$	558.0	$	—	$	229.7	$	—	$	—



	Pensions								Other Post-retirement Benefits
	2017				2016				2017		2016
(In millions)	U.S.		Int’l		U.S.		Int’l
Plans with underfunded or non-funded accumulated benefit obligation:
Aggregate accumulated benefit obligation	$	659.8	$	212.5	$	—	$	360.9	$	—	$	—
Aggregate fair value of plan assets	$	576.4	$	82.2	$	—	$	229.7	$	—	$	—

The following table summarizes the components of net periodic benefit cost (income) for the years ended December 31, 2017, 2016 and 2015:



	Pensions																Other Post-retirement Benefits
	2017						2016					2015					2017		2016		2015
(In millions)	U.S.			Int’l			U.S.		Int’l			U.S.		Int’l
Components of net periodic benefit cost (income):
Service cost	$	10.3		$	21.0		$	—	$	11.7		$	—	$	13.7		$	—	$	—	$	—
Interest cost	26.7			19.6			—		10.9			—		11.6			0.3		—		—
Expected return on plan assets	(45.5		)	(36.3		)	—		(8.2		)	—		(8.6		)	—		—		—
Settlement cost	—			1.5			—		—			—		—			—		—		—
Curtailment benefit	(26.8		)	—			—		(10.7		)	—		—			—		—		—
Amortization of net actuarial loss (gain)	—			2.5			—		1.0			—		3.7			—		—		—
Amortization of prior service cost (credit)	—			1.0			—		0.7			—		0.7			—		—		—
Net periodic benefit cost (income)	$	(35.3	)	$	9.3		$	—	$	5.4		$	—	$	21.1		$	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, 2017, 2016 and 2015:



	Pensions															Other Post-retirement Benefits
	2017						2016					2015				2017			2016		2015
(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	$	26.7		$	43.3		$	—	$	(10.5	)	$	—	$	18.4	$	(0.8	)	$	—	$	—
Prior service (cost) credit arising during period	(0.2		)	0.1			—		0.1			—		0.3		—			—		—
Settlements and curtailments	(26.8		)	1.5			—		(10.7		)	—		—		—			—		—
Amortization of net actuarial loss (gain)	—			2.5			—		1.0			—		3.7		—			—		—
Amortization of prior service cost (credit)	—			1.0			—		0.7			—		0.7		—			—		—
Other	—			(5.1		)	—		17.6			—		8.1		—			—		—
Total recognized in other comprehensive income (loss)	$	(0.3	)	$	43.3		$	—	$	(1.8	)	$	—	$	31.2	$	(0.8	)	$	—	$	—

Included in accumulated other comprehensive income (loss) at December 31, 2017, 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)	$	—	$	1.2	$	—
Prior service cost (credit)	$	—	$	1.1	$	—

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



	Pensions							Other Post-retirement Benefits
	2017				2016			2017		2016
	U.S.		Int’l		U.S.	Int’l
Discount rate	3.70	%	2.42	%	N/A	2.15	%	4.33	%	1.70	%
Rate of compensation increase	—	%	2.37	%	N/A	2.80	%	4.00	%	N/A

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



	Pensions										Other Post-retirement Benefits
	2017				2016			2015			2017		2016		2015
	U.S.		Int’l		U.S.	Int’l		U.S.	Int’l
Discount rate	4.30	%	2.37	%	N/A	2.80	%	N/A	2.50	%	4.05	%	2.20	%	1.90	%
Rate of compensation increase	4.00	%	2.39	%	N/A	2.30	%	N/A	2.60	%	4.00	%	3.00	%	3.00	%
Expected rate of return on plan assets	9.00	%	6.24	%	N/A	2.80	%	N/A	3.60	%	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, 98% of our total pension plan assets represent the U.S. qualified plan, the U.K. plan, the Norway 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, 2017 and 2016.


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


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


•	Fair values of registered investment companies and common/collective trusts are valued based on quoted market prices, which represent the net asset value (“NAV”) of shares held. Registered investment companies primarily include investments in emerging market bonds. Common/collective trusts primarily includes money market instruments with short maturities.


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


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


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


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

Our pension plan assets measured at fair value on a recurring basis are as follows at December 31, 2017 and 2016. Refer to “Fair value measurements” in Note 1 to these consolidated financial statements for a description of the levels.



	U.S.								International
December 31, 2017 (In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
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 ⁽¹⁾	33.6		—		—		—		72.6		—		—		—
Common/collective trusts ⁽¹⁾	31.2		—		—		—		13.0		—		—		—
Insurance contracts	—		—		—		—		208.2		—		208.2		—
Hedge funds ⁽¹⁾	194.3		—		—		—		74.7		—		—		—
Limited partnerships ⁽¹⁾	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	$	—
December 31, 2016 (In millions)
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	2.1	$	2.1	$	—	$	—
Equity securities:
U.S. companies	—		—		—		—		—		—		—		—
International companies	—		—		—		—		37.2		37.2		—		—
Registered investment companies ⁽¹⁾	—		—		—		—		52.7		—		—		—
Common/collective trusts ⁽¹⁾	—		—		—		—		10.6		—		—		—
Insurance contracts	—		—		—		—		112.2		—		112.2		—
Hedge funds ⁽¹⁾	—		—		—		—		12.3		—		—		—
Limited partnerships ⁽¹⁾	—		—		—		—		—		—		—		—
Real estate and other investments	—		—		—		—		2.5		2.5		—		—
Total assets	$	—	$	—	$	—	$	—	$	229.6	$	41.8	$	112.2	$	—

_______________________


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

Contributions—We expect to contribute approximately $19.9 million to our international pension plans, representing primarily the U.K. qualified pension plans and approximately $5.3 million to our U.S. Non-Qualified Defined Benefit Pension Plan in 2018. We do not expect to make any contributions to our U.S. Qualified Pension Plan in 2018. All of the contributions are expected to be in the form of cash. In 2017 and 2016, we contributed $19.1 million and $3.0 million to all pension plans, respectively.

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



	Pensions				Other Post-retirement Benefits
(In millions)	U.S.		International
2018	$	33.4	$	28.2	$	0.7
2019	34.1		30.9		0.7
2020	34.7		33.3		0.7
2021	35.5		34.4		0.7
2022	34.9		35.5		0.7
2023-2027	174.3		197.5		2.9

Savings plans—The FMC Technologies, Inc. Savings and Investment Plan (“Qualified Plan”), a qualified salary reduction plan under Section 401(k) of the Internal Revenue Code, is a defined contribution plan. Additionally, we have a non-qualified deferred compensation plan, the Non-Qualified Plan, which allows certain highly compensated employees the option to defer the receipt of a portion of their salary. We match a portion of the participants’ deferrals to both plans. Both plans relate to FMC Technologies, Inc and therefore only 2017 amounts are presented below.

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, 2017, our liability for the Non-Qualified Plan was $29.4 million and was recorded in other non-current liabilities. We hedge the financial impact of changes in the participants’ hypothetical investments by purchasing the investments that the participants have chosen. With the exception of 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, 2017, we had investments for the Non-Qualified Plan totaling $25.1 million at fair market value and TechnipFMC stock held in trust of $4.8 million at its cost basis. Refer to Note 18 to these consolidated financial statements for fair value disclosure of the Non-Qualified Plan investments.

We recognized expense of $20.3 million for matching contributions to these plans in 2017. Additionally, we recognized expense of $12.5 million for non-elective contributions in 2017.

NOTE 19. 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.

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 on the date of our annual shareholder meeting following the date of grant. Restricted share units are settled when a director ceases services to the Board of Directors. At December 31, 2017, outstanding awards to active and retired non-employee directors included 64.9 thousand share units.

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 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 for nonvested share units under the Plan is as follows:



	Year Ended December 31,
(In millions)	2017		2016		2015
Share-based compensation expense	$	44.4	$	22.0	$	36.1
Income tax benefits related to share-based compensation expense	$	12.0	$	5.9	$	9.7

As of December 31, 2017, the portion of share-based compensation expense related to outstanding awards to be recognized in future periods is as follows:



	December 31, 2017
Share-based compensation expense not yet recognized (in millions)	$	77.9
Weighted-average recognition period (in years)	2.2

Restricted share units. A summary of the nonvested restricted share units awarded to employees as of December 31, 2017, and changes during the year is presented below:



(Shares in thousands)	Shares		Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2016	—		$	—
Assumed in the FMC Technologies Merger	213.1		$	35.85
Granted	1,516.9		$	27.54
Vested	—		$	—
Cancelled/forfeited	(7.7	)	$	35.85
Nonvested at December 31, 2017	1,722.3		$	28.53

The following summarizes values for restricted share unit activity to employees⁽¹⁾:



	Year Ended December 31,
	2017
Weighted average grant date fair value of restricted share units granted	$	27.54
Vest date fair value of restricted share units vested (in millions)	$	—

⁽¹⁾We began issuing restricted share units in 2017.

Performance Shares. The Board of Directors has granted certain employees, senior executives and Directors or Officers shares 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 or total shareholder return. For performance shares issued on or after January 1, 2017, performance is based on results of return on investment or shareholder value.

A summary of the nonvested performance share units awarded to employees as of December 31, 2017, and changes during the year is presented below:



(Shares in thousands)	Shares		Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2016	1,314.6		$	60.15
Adjustment due to FMC Technologies transaction ⁽¹⁾	1,306.0		$	—
Granted	855.2		$	31.65
Vested	(642.0	)	$	52.42
Cancelled/forfeited	(85.0	)	$	25.33
Nonvested at December 31, 2017	2,748.8		$	25.59

⁽¹⁾ 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).

The following summarizes values for performance share activity to employees:



	Year Ended December 31,
	2017		2016		2015
Weighted average grant date fair value of performance shares granted	$	31.65	$	42.74	$	43.16
Vest date fair value of performance shares vested (in millions)	$	18.60	$	26.38	$	29.01

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. Expected volatility is based on normalized historical volatility of our shares over a preceding period commensurate with the expected term of the option. 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. 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 used 2.0%.

Share options awarded prior to 2017 were granted subject to performance criteria based upon certain targets, such as total shareholder return, 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 assumptions for the option awards granted in the years ended December 31, 2017, 2016 and 2015 are as follows:



	Year Ended December 31,
	2017		2016		2015
Expected volatility	35.7	%	34.5	%	29.2	%
Expected term (in years)	6.5		4.2		4.2
Risk-free interest rate	2.1	%	—	%	1.1	%

During the years ended December 31, 2017, 2016 and 2015, we granted 798.4 thousand, 595.1 thousand and 568.6 thousand options, respectively, and the weighted average grant-date fair value of options granted during years ended December 31, 2017, 2016 and 2015 was $8.79, €7.70 and €6.01, respectively.

The following is a summary of option transactions during years ended December 31, 2017, 2016 and 2015:



(shares in thousands)	Number of shares		Weighted average exercise price		Weighted average remaining life (in years)
Balance at December 31, 2014	2,520.5		€	60.03	2.7
Granted	568.6		€	47.83
Exercised	(561.7	)	€	37.87
Cancelled	(106.9	)	€	69.62
Balance at 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 at December 31, 2016	2,188.8		€	61.72	5.0
Adjustment due to FMC Technologies transaction ⁽¹⁾	2,188.8		$	—
Granted	798.4		$	29.29
Exercised	—		$	—
Cancelled	(292.2	)	$	47.60
Balance at December 31, 2017	4,883.8		$	36.35	4.6
Exercisable at December 31, 2017	1,788.8		$	51.61	1.6

The aggregate intrinsic value of stock options outstanding and stock options exercisable as of December 31, 2017 was $12.5 million and nil, respectively.

There were nil, 25.5 thousand and 561.7 thousand options exercised during the years ended December 31, 2017, 2016 and 2015, respectively. Cash received from the option exercises was nil, €1.5 million and €21.3 million during years ended December 31, 2017, 2016 and 2015, respectively. The total intrinsic value of options exercised during the years ended December 31, 2017, 2016 and 2015 was nil, nil and €12.9 million, 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 additional information concerning outstanding and exercisable options at December 31, 2017 :



	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
$26.00 - $33.00	3,061.9	6.4	$	27.33	—	$	—
$45.00 - $51.00	1,277.0	1.0	$	49.23	1,244.0	$	49.33
$55.00 - $57.00	544.9	3.2	$	56.82	544.9	$	56.82
Total	4,883.8	4.6	$	36.35	1,788.9	$	51.61

NOTE 20. DERIVATIVE FINANCIAL INSTRUMENTS

For purposes of mitigating the effect of changes in exchange rates, we hold derivative financial instruments to hedge the risks of certain identifiable and anticipated transactions and recorded assets and liabilities in our consolidated balance sheets. The types of risks hedged are those relating to the variability of future earnings and cash flows caused by movements in foreign currency exchange rates. Our policy is to hold derivatives only for the purpose of hedging risks associated with anticipated foreign currency purchases and sales created in the normal course of business and not for trading purposes where the objective is solely to generate profit.

Generally, we enter into hedging relationships such that changes in the fair values or cash flows of the transactions being hedged are expected to be offset by corresponding changes in the fair value of the derivatives. For derivative instruments that qualify as a cash flow hedge, the effective portion of the gain or loss of the derivative, which does not include the time value component of a forward currency rate, is reported as a component of other comprehensive income (“OCI”) and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. For derivative instruments not designated as hedging instruments, any change in the fair value of those instruments are reflected in earnings in the period such change occurs.

We hold the following types of derivative instruments:

Foreign exchange rate forward contracts – The purpose of these instruments is to hedge the risk of changes in future cash flows of anticipated purchase or sale commitments denominated in foreign currencies and recorded assets and liabilities in our consolidated balance sheets. At December 31, 2017, we held the following material net positions:



	Net Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Australian dollar	156.5		122.3
Brazilian real	783.1		236.7
British pound	142.0		191.9
Canadian dollar	(181.9	)	(144.9	)
Euro	354.9		425.6
Norwegian krone	(1,857.5	)	226.3
Singapore dollar	116.2		87.0
U.S. dollar	(647.6	)	(647.6	)

Foreign exchange rate instruments embedded in purchase and sale contracts – The purpose of these instruments is to match offsetting currency payments and receipts for particular projects or conduct business in internationally recognized and traded currencies. At December 31, 2017, our portfolio of these instruments included the following material net positions:



	Net Notional Amount Bought (Sold)
(In millions)			USD Equivalent
Norwegian krone	(290.1	)	(35.3	)
U.S. dollar	32.8		32.8

Fair value amounts for all outstanding derivative instruments have been determined using available market information and commonly accepted valuation methodologies. Refer to Note 21 to these consolidated financial statements for further

disclosures related to the fair value measurement process. Accordingly, the estimates presented may not be indicative of the amounts that we would realize in a current market exchange and may not be indicative of the gains or losses we may ultimately incur when these contracts are settled.

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



	December 31, 2017				December 31, 2016
(In millions)	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	$	65.6	$	51.0	$	47.2	$	183.0
Long-term – Derivative financial instruments	28.0		1.7		10.7		47.6
Total derivatives designated as hedging instruments	93.6		52.7		57.9		230.6
Derivatives not designated as hedging instruments:
Foreign exchange contracts:
Current – Derivative financial instruments	12.7		18.0		—		—
Long-term – Derivative financial instruments	4.7		4.2		—		—
Total derivatives not designated as hedging instruments	17.4		22.2		—		—
Long-term – Derivative financial instruments – Synthetic Bonds – Call Option Premium	62.2		—		180.1		—
Long-term – Derivative financial instruments – Synthetic Bonds – Embedded Derivatives	—		62.2		—		180.1
Total derivatives	$	173.2	$	137.1	$	238.0	$	410.7

We recognized a gain of $25.3 million and losses of $10.3 million and $9.0 million on cash flow hedges for the years ended December 31, 2017, 2016 and 2015, 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 of $28.5 million and accumulated comprehensive loss $126.5 million at December 31, 2017 and 2016, respectively. We expect to transfer approximately $23.0 million income 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 2020.

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)	2017		2016		2015
Other income (expense), net	$	44.9	$	32.8	$	(10.2	)

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)	2017		2016			2015
Foreign exchange contracts	$	72.1	$	(86.1	)	$	(91.6	)



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)	2017			2016			2015
Foreign exchange contracts:
Revenue	$	(39.3	)	$	—		$	—
Cost of sales	5.3			—			—
Selling, general and administrative expense	0.8			—			—
Research and development expense	—			—			—
Other (expense), net	(102.2		)	(165.7		)	(93.6		)
Total	$	(135.4	)	$	(165.7	)	$	(93.6	)



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)	2017			2016			2015
Foreign exchange contracts:
Revenue	$	9.5		$	—		$	—
Cost of sales	(9.0		)	—			—
Selling, general and administrative expense	0.1			—			—
Other income (expense), net	23.0			(13.2		)	(16.9		)
Total	$	23.6		$	(13.2	)	$	(16.9	)

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)	2017			2016		2015
Foreign exchange contracts:
Revenue	$	0.9		$	—	$	—
Cost of sales	(0.3		)	—		—
Other income, net	43.0			0.1		1.6
Total	$	43.6		$	0.1	$	1.6

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, 2017 and 2016, we had no collateralized derivative contracts. The following tables present both gross information and net information of recognized derivative instruments:



	December 31, 2017							December 31, 2016
(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	$	173.2	$	(114.4	)	$	58.8	$	238.0	$	(236.6	)	$	1.4

100



	December 31, 2017							December 31, 2016
(In millions)	Gross Amount Recognized		Gross Amounts Not Offset Permitted Under Master Netting Agreements			Net Amount		Gross Amount Recognized		Gross Amounts Not Offset Permitted Under Master Netting Agreements			Net Amount
Derivative liabilities	$	137.1	$	(114.4	)	$	22.7	$	410.7	$	(236.6	)	$	174.1

NOTE 21. FAIR VALUE MEASUREMENTS

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



	December 31, 2017								December 31, 2016
(In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Assets
Investments:
Nonqualified Plan:
Traded securities ⁽¹⁾	$	26.2	$	26.2	$	—	$	—	$	—	$	—	$	—	$	—
Money market fund	2.4		—		2.4		—		—		—		—		—
Stable value fund ⁽²⁾	0.6								—
Available-for-sale securities	37.5		37.5		—		—		27.9		27.9		—		—
Derivative financial instruments:
Synthetic bonds - call option premium	62.2		—		62.2		—		180.1		—		180.1		—
Foreign exchange contracts	111.0		—		111.0		—		57.9		—		57.9		—
Assets held for sale	50.2		—		—		50.2		2.2		—		—		2.2
Total assets	$	290.1	$	63.7	$	175.6	$	50.2	$	268.1	$	27.9	$	238.0	$	2.2
Liabilities
Redeemable financial liability	$	312.0	$	—	$	—	$	312.0	$	174.8	$	—	$	—	$	174.8
Derivative financial instruments:
Synthetic bonds - embedded derivatives	62.2		—		62.2		—		180.1		—		180.1		—
Foreign exchange contracts	74.9		—		74.9		—		230.6		—		230.6		—
Liabilities held for sale	13.7		—		—		13.7		—		—		—		—
Total liabilities	$	462.8	$	—	$	137.1	$	325.7	$	585.5	$	—	$	410.7	$	174.8

_______________________


⁽¹⁾	Includes equity securities, fixed income and other investments measured at fair value.


⁽²⁾	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.

Non-qualified plan—The fair value measurement of our traded securities is based on quoted prices that we have the ability to access in public markets. Our stable value fund and money market fund are valued at the net asset value of the shares held at the end of the quarter, which is based on the fair value of the underlying investments using information reported by our investment adviser at quarter-end.

Available-for-sale investments—The fair value measurement of our available-for-sale investments is based on quoted prices that we have the ability to access in public markets.

Other investments—Held-to-maturity investments included in the investments line item on the consolidated balance sheet are carried at amortized cost.

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 as of December 31, 2017.

101

Mandatorily redeemable financial liability—We determined the fair value of the mandatorily redeemable financial liability using a discounted cash flow model. Refer to Note 14 for further information related to this liability. The key assumption used in applying the income approach is the selected discount rates and the expected dividends to be distributed in the future to the noncontrolling interest holders. Expected dividends to be distributed is 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 decrease of one percentage point in the discount rate would have increased the liability by $6.6 million as of December 31, 2017. 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.

Changes in the fair value of our Level 3 mandatorily redeemable financial liability is presented below. Since the liability was created during the three months ended December 31, 2016, no changes in fair value are presented for the prior period.



(In millions)	Year Ended December 31, 2017
Balance at beginning of period	$	174.8
Less: Gains (losses) recognized in interest expense	(293.7		)
Less: Settlements	156.5
Balance at end of period	$	312.0

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.

Refer to Note 20 to these consolidated financial statements for additional disclosure related to derivative financial instruments.

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

Fair value of long-lived, non-financial assets—Long-lived, non-financial assets are measured at fair value on a non-recurring basis for the purposes of calculating impairment, 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 increases or decreases in actual or estimated cash flows may result in changes to the fair value of long-lived non-financial assets. Refer to Note 5 for additional disclosure related to these asset impairments.

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, 2017				December 31, 2016
(In millions)	Carrying Amount ⁽¹⁾		Fair Value ⁽²⁾		Carrying Amount ⁽¹⁾		Fair Value ⁽²⁾
Synthetic bonds due 2021	$	499.2	$	647.4	$	428.0	$	661.5
3.45% Senior Notes due 2022	500.0		497.7		—		—
5.00% Notes due 2020	238.9		265.2		209.7		239.0
3.40% Notes due 2022	179.8		199.4		158.0		177.8
3.15% Notes due 2023	155.0		167.6		136.1		153.1
3.15% Notes due 2023	149.6		161.4		131.4		142.8
4.00% Notes due 2027	89.9		99.9		79.0		89.6
4.00% Notes due 2032	115.4		142.9		101.2		127.3
3.75% Notes due 2033	116.0		126.7		101.8		107.8

_______________________

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⁽¹⁾	Carrying amounts are shown net of unamortized debt discounts and premiums and unamortized debt issuance costs of $13.8 million and $14.2 million as of 2017 and 2016, respectively.


⁽²⁾	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.

NOTE 22. 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 deepwater exploration and production of crude oil and natural gas.


•	Onshore/Offshore—designs and builds onshore facilities related to the production, treatment 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 for companies in the oil and gas industry.

•

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

Total revenue by segment includes intersegment sales, which are made at prices approximating those that the selling entity is able to obtain on external sales. Segment operating profit is defined as total segment revenue less segment operating expenses. Income (loss) from equity method investments is included in computing segment operating profit. Refer to Note 8 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.

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Segment revenue and segment operating profit



	Year Ended December 31,
(In millions)	2017			2016			2015
Segment revenue
Subsea	$	5,877.4		$	5,850.5		$	6,520.6
Onshore/Offshore	7,904.5			3,349.1			4,951.3
Surface Technologies	1,274.6			—			—
Other revenue and intercompany eliminations	0.4			—			—
Total revenue	$	15,056.9		$	9,199.6		$	11,471.9
Income before income taxes:
Segment operating profit (loss):
Subsea	$	460.5		$	732.0		$	866.9
Onshore/Offshore	810.9			34.1			(313.3		)
Surface Technologies	82.7			—			—
Total segment operating profit	1,354.1			766.1			553.6
Corporate items:
Corporate expense ⁽¹⁾	(359.2		)	(185.9		)	(331.9		)
Interest income	140.8			85.3			77.7
Interest expense	(456.0		)	(114.1		)	(148.9		)
Total corporate items	(674.4		)	(214.7		)	(403.1		)
Income before income taxes ⁽²⁾	$	679.7		$	551.4		$	150.5

______________________________


⁽¹⁾	Corporate expense primarily includes corporate staff expenses, stock-based compensation expenses, other employee benefits, certain foreign exchange gains and losses, and merger-related transaction expenses.


⁽²⁾	Includes amounts attributable to noncontrolling interests.

Segment assets



	December 31,
(In millions)	2017			2016
Segment assets:
Subsea	$	12,944.4		$	7,823.1
Onshore/Offshore	4,604.8			3,229.3
Surface Technologies	2,453.3			—
Intercompany eliminations	(24.3		)	—
Total segment assets	19,978.2			11,052.4
Corporate ⁽³⁾	8,285.5			7,626.9
Total assets	$	28,263.7		$	18,679.3

______________________________


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

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Geographic segment information

Geographic segment sales were identified based on the location where our products and services were delivered.



	Year Ended December 31,
(In millions)	2017		2016		2015
Revenue:
Russia	$	4,894.2	$	283.3	$	—
United States	1,534.7		1,033.7		1,402.5
Angola	1,016.2		935.3		1,013.7
Norway	971.2		574.4		1,293.3
Brazil	911.1		1,006.9		1,102.3
Australia	953.9		776.6		1,044.8
United Kingdom	465.9		761.5		1,155.4
All other countries	4,309.7		3,827.9		4,459.9
Total revenue	$	15,056.9	$	9,199.6	$	11,471.9

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



	December 31,
(In millions)	2017		2016
Long-lived assets:
United States	$	567.1	$	44.1
Norway	321.4		121.9
Malaysia	257.1		166.3
Brazil	408.3		319.5
United Kingdom	1,190.1		1,078.2
All other countries	1,127.5		890.1
Total long-lived assets	$	3,871.5	$	2,620.1

Other business segment information



	Capital Expenditures Year Ended December 31,						Depreciation and Amortization Year Ended December 31,						Research and Development Expense Year Ended December 31,
(In millions)	2017		2016		2015		2017		2016		2015		2017		2016		2015
Subsea	$	179.1	$	286.9	$	290.1	$	507.2	$	256.8	$	295.9	$	169.2	$	75.4	$	67.1
Onshore/Offshore	16.2		26.0		35.4		41.1		43.9		42.8		31.4		30.0		28.4
Surface Technologies	35.4		—		—		63.6		—		—		12.3		—		—
Corporate	25.0		—		—		2.8		—		—		—		—		—
Total	$	255.7	$	312.9	$	325.5	$	614.7	$	300.7	$	338.7	$	212.9	$	105.4	$	95.5

During the years ended December 31, 2017, 2016 and 2015, 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.

105

NOTE 23. QUARTERLY INFORMATION (UNAUDITED)



	2017										2016
(In millions, except per share data)	4th Qtr.			3rd Qtr.		2nd Qtr.		1st Qtr.			4th Qtr.			3rd Qtr.		2nd Qtr.		1st Qtr.
Revenue	$	3,683.0		$	4,140.9	$	3,845.0	$	3,388.0		$	2,047.7		$	2,375.7	$	2,370.5	$	2,405.7
Cost of sales	2,914.1			3,468.2		3,162.0		2,980.3			1,766.3			1,931.0		1,927.0		2,005.7
Net income (loss)	(127.5		)	117.9		159.0		(15.2		)	(155.0		)	301.7		103.8		120.6
Net income (loss) attributable to TechnipFMC plc	$	(153.9	)	$	121.0	$	164.9	$	(18.7	)	$	(133.8	)	$	302.4	$	104.0	$	120.7
Basic earnings (loss) per share	$	(0.33	)	$	0.26	$	0.35	$	(0.04	)	$	(1.13	)	$	2.50	$	0.87	$	1.02
Diluted earnings (loss) per share	$	(0.33	)	$	0.26	$	0.35	$	(0.04	)	$	(1.13	)	$	2.39	$	0.83	$	0.97

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, 2017, 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 Rules 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, 2017, 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.

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, 2017 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, 2017.

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 company's annual or interim financial statements will not be prevented or detected on a timely basis.

We concluded that we had not maintained effective internal control over financial reporting in the following areas that are discussed more fully below: (i) controls relating to the calculation of temporary gains and losses from natural hedges on certain of our projects and related foreign exchange adjustments; (ii) controls over the period-end financial reporting process specifically related to journal entries and account reconciliation in certain regions and locations; and (iii) controls relating to certain information technology systems.

Description of Material Weaknesses

106

Foreign Exchange Adjustments

As previously reported, we did not maintain effective controls relating 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. Additionally, this control deficiency could result in misstatements of the annual or interim consolidated financial statements or disclosures that would not be prevented or detected. Accordingly, management determined that this control deficiency constitutes a material weakness.

Information Technology General Controls

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 to the financial statements; however, the deficiencies, when aggregated, could impact 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 result in misstatements potentially impacting financial statement accounts and disclosures that would not be prevented or detected. Accordingly, our management has determined these deficiencies, in the aggregate, constitute a material weakness.

Period End Financial Reporting—Journal Entries and Account Reconciliation in Certain Regions and Locations

In certain regions and 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 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 result in material misstatements to 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.

Description of Remediation Activities

Foreign Exchange Adjustments

Management has implemented controls designed to ensure the accurate remeasurement of gains and losses due to foreign currency impact for the purpose of external reporting. Management has also 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.

Information Technology General Controls

Management is taking corrective actions to address the material weakness as listed below:

•Improving the control activities and procedures associated with user and privilege access to certain systems;

•Improving the control activities relating to proper segregation of duties related to the affected IT systems;

107

•Implementing 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

•Implementing 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—Journal Entries and Account Reconciliation in Certain Regions and Locations

Management is taking corrective actions to address the material weakness as listed below:

•Implementing specific policies and procedures with detailed instructions in order to adequately communicate the requirements around journal entry and account reconciliation processes and controls;

•Implementing controls over manual journal entries and account reconciliations, including improving the timeliness and effectiveness of our review and approval procedures,

•Communicating 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; and

•Improving the control activities relating to account reconciliation and journal entry processes by issuing guidance regarding adequate retention of evidence of control activities.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended December 31, 2017 that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Disclosures pursuant to Section 13(r) of the Securities Exchange Act

Pursuant to section 13(r) of the Exchange Act, two of our non-U.S. subsidiaries have contracts with entities in Iran. We have prepared a feasibility study related to improvements to an olefins plant in Iran. We are also providing engineering and design services for the construction of an ethylene plant in Iran, which is expected to be completed by the end of 2018. All activities were conducted, and will be conducted, outside the United States by non-U.S. entities in compliance with applicable law. We received no revenue under either contract for the three and twelve months ended December 31, 2017. The expected gross revenue from the olefins plant and the ethylene plant is 250,000 Euros and 8,000,000 Euros, respectively, which is less than 0.1% of our pro forma revenues for the fiscal year ended December 31, 2016. Net profit from the two contracts is unknown at this time.

108

PART III

ITEM 10. CORPORATE GOVERNANCE AND BOARD OF DIRECTORS

The information required by this item regarding our directors and corporate governance is hereby incorporated by reference to the material appearing in our Proxy Statement for the 2018 Annual Meeting of Shareholders under the caption “Corporate Governance.” The information required by this item regarding our executive officers is incorporated herein by reference to “Executive Officers of the Registrant” in Part I, Item 1 of this Annual Report on Form 10-K. The information required by this item regarding compliance by our Information regarding compliance by our directors and executive officers with Section 16(a) of the Securities and Exchange Act of 1934, as amended, is incorporated herein by reference from the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” of our Proxy Statement for the 2018 Annual Meeting of Shareholders.

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

ITEM 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated herein by reference from the sections entitled “Non-Executive 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 2018 Annual Meeting of Shareholders.

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 Outstanding Shares of Ordinary Shares” of our Proxy Statement for the 2018 Annual Meeting of Shareholders. Additionally, Equity Plan Compensation Information is incorporated herein by reference from Part II, Item 5 of this Annual Report on Form 10-K.

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

Information required by this item is incorporated herein by reference from the sections entitled “Transactions with Related Persons” and “Corporate Governance—Director Independence” of our Proxy Statement for the 2018 Annual 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 5 - Ratification of U.S. Auditor” of our Proxy Statement for the 2018 Annual 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:

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

Consolidated Statements of Income for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016, and 2015

Consolidated Balance Sheets as of December 31, 2017 and 2016

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015

Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2017, 2016 and 2015

Notes to Consolidated Financial Statements


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

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


3.	Exhibits:

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

110

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, 2015:
Allowance for doubtful accounts	$	43.0	$	21.4	$	—	$	(16.2	)	$	48.2
Valuation allowance for deferred tax assets	$	119.9	$	13.9	$	—	$	—		$	133.8
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

______________________________


^(a)	“Additions charged to other accounts” includes translation adjustments.


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

See accompanying Report of Independent Registered Public Accounting Firm.

111

ITEM 16. SUMMARY

None.

112

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		First Supplemental Indenture, dated March 29, 2017, between TechnipFMC plc and U.S. Bank National Association, as trustee (including the form of 2.00% Senior Notes due 2017) (incorporated by reference from Exhibit 4.2 to the Current Report on Form 8-K filed on March 30, 2017) (File No. 001-37983)
4.1.b		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)
4.4		Registration Rights Agreement, dated March 29, 2017, between TechnipFMC plc, and each of Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as dealer managers (incorporated by reference from Exhibit 4.4 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*		TechnipFMC plc Incentive Award Plan (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed on January 17, 2017) (File No. 001-37983)
10.3*		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.
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
10.22*		Letter Agreement between TechnipFMC plc and Thierry Pilenko dated September 20, 2017
10.23		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)
10.24		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)
10.25		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)
10.26		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)
10.27		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)
10.28		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)
10.29		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

113

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/ MARYANN T. MANNEN
		Maryann T. Mannen Executive Vice President and Chief Financial Officer (Principal Financial Officer and a Duly Authorized Officer)

Date: April 2, 2018

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



Date		Signature

April 2, 2018		/S/ DOUGLAS J. PFERDEHIRT
		Douglas J. Pferdehirt Chief Executive Officer (Principal Executive Officer)

April 2, 2018		/S/ MARYANN T. MANNEN
		Maryann T. Mannen Executive Vice President and Chief Financial Officer (Principal Financial Officer and a Duly Authorized Officer)

April 2, 2018		/S/ THIERRY PILENKO
		Thierry Pilenko Executive Chairman

April 2, 2018		/S/ ARNAUD CAUDOUX
		Arnaud Caudox, Director

April 2, 2018		/S/ MARIE-ANGE DEBON
		Marie-Ange Debon, Director

April 2, 2018		/S/ ELEAZAR DE CARVALHO FILHO
		Eleazar De Carvalho Filho, Director

April 2, 2018		/S/ KAY G. PRIESTLY
		Kay G. Priestly, Director

April 2, 2018		/S/ JOSEPH RINALDI
		Joseph Rinaldi, Director

April 2, 2018		/S/ JAMES M. RINGLER
		James M. Ringler, Director

114