10-K 1 technipfmc20171231-10k.htm FORM 10-K FOR YEAR ENDED DECEMBER 31, 2017 Document


 
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
or
¨
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
 
 
 
 
 
PART II
 
 
 
 
 
PART III
 
 
 
 
 
PART IV
 
 
 
Item 16. Summary

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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.

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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.

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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, iFEEDTM (“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.

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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.

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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

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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.

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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.
RefiningWe 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 LiquefactionWe 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.

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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.
EthyleneWe 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 FertilizersWe 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.
HydrogenHydrogen 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

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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

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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

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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

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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

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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.

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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.

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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

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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.

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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

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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

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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.

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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

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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

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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.

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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

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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

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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.

27



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

28



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

29



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.

30



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


31



______________________________
(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.

32



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.



33



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

34



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

35



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.


36



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

37



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

38



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.


39



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.

40



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

41



 
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.

42



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: 

43



(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

44



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

______________________________

45



(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.

46



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

47



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

48



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

49



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.

50



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.

51



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.

52



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.


53





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


54



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.

55



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.